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Home My WebLink AboutCO 550 ) ) Image Project Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Cn 550 Order File Identifier Organizing (done) o Two-sided 1111111111111111111 o Rescan Needed 1111111111111111111 RESCAN DIGITAL DATA OVERSIZED (Scannable) D Color Items: o Diskettes, No. D Maps: D Greyscale Items: D Other, Norrype: D Other Items Scannable by a Large Scanner o Poor Quality Originals: OVERSIZED (Non-Scannable) o Other: o Logs of various kinds: NOTES: o Other:: I BY: Helen~ Date: ~ 9..73 ~ 151 mr ~' :.,,>'" Project Proofing ( 1111111111111111111 BY: Helen~ Date~ ~3 OS- 151 w¡p Scanning Preparation x 30 = + = TOTAL PAGES / O:J.-. Helen ~ \ (Count do~s not in~lude cover sheet) YYlP BY: Date:~ ;¡~ OS 151 Production Scanning 111111111111111111 Stage 1 Page Count from Scanned File: I 0.3 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~YES NO . W1P BY: Helen ~ Date:~ ~\5 ó.s- 151 Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Helen Maria Date: 151 Scanning is complete at this point unless rescanning is required. 1111111111111111111 ReScanned 1111111111111111111 BY: Helen Maria Date: 151 Comments about this file: Quality Checked IIII11I1I1111111111 12/1/2004 Orders File Cover Page.doc • • INDEX CONSERVATION ORDER NO. 550 Milne Point Field 1) November 30, 2004 Guidelines for ualification of Multiphase Multi Q p Meterin Systems for Well Testing Y g 2) December 2, 2004 Notice of Hearing, affidavit of mailing, e-mail list, bulk mailing list 3) December 23, 2004 Inter - office e -mail 4) January 6, 2005 Inter -office e-mail 5) January 11, 2005 Si in Sheet Hearing Sign g 6) January 11, 2005 Transcript 7) August 30, 2006 Application Report for EMS Multiphase Metering System 8) September 15, 2006 e-mail from AOGCC to operator re: application 9) September 22, 2006 Notice of Hearing, affidavit of mailing, e-mail list, bulk mailing list 10) October 17, 2006 emails vacating hearing date 11) November 2, 2006 Letter of DNR regarding "Application Report" 12) November 13, 2006 Dates when the application report from EMS was sent to company /agency 13) November 13, 2006 3M Unit Field Qualification tests - Preliminary Plan 14) March 30, 2007 BPXA application for EMA Multiphase Metering System 15) April 26, 2007 Notice of Hearing, affidavit of mailing, e-mail list, bulk mailing list 16) August 10, 2007 BPXA Application Report for EMS Multiphase Metering System (CO550 -002) 17. November 14, 2007 BPXA Application Report for EMS Multiphase Metering System (CO550 -003) 18. March 13, 2008 BPXA Application Report for EMS Multiphase Metering System and subsequent withdraw of Request 19. May 13, 2008 BPXA Application Report for EMS Multiphase Metering 20. July 8, 2008 BPXA application for Weatherford Generation 2.0 Multiphase Metering System 21. July 14, 2008 E -mail from Operator 22) July 8, 2008 BPXA Application Report for EMS Multiphase Metering System (CO550 -006) 23) August 25, 2008 AOGCC request for comments 24) September 30, 2008 Comments from MMS 25) October 3, 2008 Comments from DNR 26) October 7, 2008 Comments from DOR 27)--------------------- Various a -mails 28) December 2, 2008 BPXA Supplemental data for the AOGCC Report 29) January 1, 2009 E-mail re: Unit 5 Approval 30) January 15, 2009 BPXA's long-term quality assurance program for the Weatherford Generation 2.0 Multiphase Metering System 31) February 19, 2009 Copy of BPXA request to DNR for the Weatherford Generation 2.0 Multiphase Metering System 32) April 27, 2009 Supplemental data I1 for EMS ASRC Unit 5 and approval to use Unit #5 in additional BPXA operated fields (CO 550-008) 33) November 24, 2009 BPXA notification of their intent to install a Weatherford Alpha VRSD at Milne Point G-pad for well testing and allocation purposes 34) February 9, 2010 BPXA notification of their intent to install a Weatherford Alpha VRSD at Milne Point G-pad for well testing and allocation purposes 35) April 30, 2012 BPXA notification of their intent to install a Weatherford Alpha VRSD at Milne Point G-pad for well testing and allocation purposes 36) October 1, 2012 Letter from DNR to BPXA re: notification of BPXA's intent to install a Weatherford Alpha VRSD at MPU 37) September 27, 2013 BPXA request in include Weatherford Generation 2.0 yearly status as part of the Annual Surveillance Report (CO 550-009 38) February 6, 2014 Email regarding request PBU Production Metering Plan Dated 8/1/2002 located in Permanent Field File (PBU) CONSERVATION ORDER NO. 550 -l ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: Rules regulating use of multiphase ) Conservation Order No. 550 meters for well testing and ) Milne Point Field: All Pools allocation of production within the ) Milne Point Field ) February 11, 2005 IT APPEARING THAT: 1. On its own motion, the Alaska Oil and Gas Conservation Commission ("Commission") proposed to adopt rules regulating the use of multiphase meters ("MPMs") for well testing and allocation of production within all pools within the Milne Point Field. 2. The proposed rules are set out in the document "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" ("Guidelines"), dated November 30, 2004, and have been made available at the Commission's offices and on its website at www.aogcc.alaska.gov/MeterGuide.htm. 3. Notice of opportunity for a public hearing on the proposal was pqblished in the Anchorage Daily News on December 2, 2004. 4. The Commission received letters of nOI)-objection to the Commission's proposal on January 7, 2005 ITom ExxonMobil Corporation ("Exxon") and January 11, 2005 ITom ConocoPhillips Alaska, Inc ("CPA"). 5. A hearing was held in conformance with 20 AAC 25.540 at the Commission's offices, 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501 on January 11,2005. FINDINGS: 1. Production Allocation Using Well Tests Well tests are conducted routinely to monitor the flow rates ITom wells for purposes of reservoir management, production diagnostics and field allocation. Conventional well testing requires that gas be separated :ITom the fluids before measurement. Production ITom many of the Alaska reservoir pools is commingled on the surface and processed using common facilities serving several pools within a field. Total field sales volumes of oil and gas are continuously monitored using custody transfer metering systems, generally referred to as LACT meters. LACT meters are required by regulation to provide accurate measurement to +/-0.25%. ~ ~ Conservation Order 550 Page 2 February 11, 2005 Because the pools do not have dedicated processing facilities and pool sales volumes are not separately measured through LACT meters, production volumes must be allocated back to wells and pools on the basis of well tests. Inaccuracies in well tests will cause errors within the fmal reported production of a pool, potentially affecting revenue of parties. 2. Multiphase Meter Technology Multiphase metering techniques were developed to Improve upon certain measurement limitations of conventional two and three-phase metering systems requiring gravity based test separators. MPMs usually require less stabilization and test time, which may allow the operators to increase the number and frequency of well tests thereby improving the quality of well test data. Advances in multiphase metering may allow for individual wells to be continuously monitored. Changes in production characteristics and production upsets can then be detected immediately and intervention can be undertaken earlier. MPMs can be made into compact and lightweight systems because. they. can operate without the need for phase separation or with partial separation. With the elimination of the test separator and other ancillary equipment, significant cost savings may be achieved. The smaller footprint. of the MPMs may,also result. in reduced. disturbance to the tundra. ,On-site visits to remote locations to monitor and maintain well test measurement systems may be reduced with the elimination of separators and other equipment required in conventional use. 3. Purpose of Guidelines The use of MPMs for well testing is gaining increased support within petroleum production operations and some Alaska operators are investigating their use for well testing and field production allocation. In particular, in March 2004, BP Exploration (Alaska) Inc. ("BPXA") and ConocoPhillips Alaska, Inc. ("CP A") informed the Commission that tests of MPMs were ongoing in the Prudhoe Bay, Kuparuk: River, and Milne PQint Fields, and requested input on the Commission's requirements for their use. Multiphase metering is a relatively new technology. Industry recommended practices are in place for 2-phase or 3-phase test separator based systems. However, -no standards and few guidelines have previously been published for MPMs. To help fill this gap, the Commission developed the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" ("Guidelines"). The guidelines are intended to direct the operator and Commission personnel on the methodology to qualify these new measurement techniques and to provide a consistent process for the evaluation of the proposed metering systems. Custody transfer applications are regulated separately and are outside the scope of the guidelines. ~ ~ Conservation Order 550 Page 3 February 11, 2005 4. Progress çf Guidelines Development The Commission prepared an initial draft of the Guidelines on May 13,2004. Alaska operators, vendors of MPMs, other state and federal agencies, and industry experts involved in multiphase metering and well testing, were invited to participate in a meeting on June 3, 2004 to provide comment upon the draft. The guidelines were revised to incorporate comments received. A revised draft was distributed on August 27, 2004. A meeting was held to gather comments on the second draft on October 13,2004. Final guidelines responding to industry comments were prepared on November 30, 2004. 5. Content of the AOGCC Guidelines The Guidelines provide a workable and reasonable interim set of criteria and procedures for evaluating proposals for the use of MPMs in well production measurement and allocation. The Guidelines describe: · the administrative process that will be followed for certification of a multiphase metering system, · meter performance requirements and documentation to accompany the application for certification of the proposed multiphase metering system, · requirements for verification of performance ofMPMs. A second document, "Principles of Multiphase Measurements," was prepared by the Commission to provide basic information concerning MPM technology, a list of references for further education, and a list of terms and definitions commonly used in the industry. 6. Future Application As yet, no formal application has been made for use of MPMs for production allocation in Alaska fields. However, BPXA and CPA have tested several meters in the Prudhoe Bay, Kuparuk River, and Milne Point Fields. It is anticipated that three or more applications to use MPMs in Alaskan North Slope fields will be submitted to the Commission in the next few years. The Commission plans to test the workability of the guidelines over the coming two to three years. As experience is gained using these guidelines, the document may be further revised to reflect practical experience gained by the field applications. ) Conservation Order 550 Page 4 February 11, 2005 CONCLUSIONS: 1. Alaska Statute 31.05.030(d)(6) gives the Commission authority to regulate the measurement of oil and gas. 2. The Commission's multiphase metering Guidelines are an appropriate initial mechanism for regulating the use ofMPMs for well production measurement and for allocation of production within the Milne Point Field. 3. A three-year trial period to evaluate the effectiveness and workability of the Guidelines is appropriate. NOW, THEREFORE, IT IS ORDERED: 1. Each of the Conservation Orders Nos. 423 and 477 is amended to add the following rule: For purposes of satisfying well test measurement requirements of 20 AAC 25.230, the use of multiphase meters will be approved only in accordance with the provisions of the Commission's document, "Guidelines for Qualification of Multiphase Meters for Well Testing" dated November 30, 2004. The Commission may administratively waive a requirement of these Guidelines or administratively amend the Guidelines as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles. 2. This order expires on January 1, 2008. - r7 D Alaska an eb ~~\: II , (> I~ f"j'~~ P'I 'tP < "'-, h~\' 1\ J ~" ...,..-'f J::; . :\:. , ,¿cA. · ,. "''''-"", . i ' AI ,:p' -;'?""; . ,\ '::"" ,I jl? a \ '~~ '¡:~. ':', :(.~~..~" ..rji,-. ,':" , '-, ,'-,,~' ~ t?:j A ".:> ".;- ~... ,': " ";,:"..:' ;-"~' . ,0 d:i I S J Co .. ""..''''''''''-''';:;:.>:,.;';''.''''W ame . e ount, r., nnmSSlOner \~~1\;:;'~ ~2,·:;'~~~::~~~'tj\.~ . Alaska O%and Gas Conservation Commission ". "' I,; f' r CO\:J '; "'4...'t~ .. '"... 1""" \\-I' . ~ -"'~>." " ,,-~ AS 31.05.080 provides that within 20 days after receipt of written notice of the entry ofan order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days Hom the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs Hom the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). .......v~.1.....,\aI~ 'I "".IV.I.I '-'I U......I.:> ) ') Subject: Conservation Orders From: Jody Colombie <jody_colombie@admin.state.akus> Date: Tue, 15 Feb 2005 10:11:26 -0900 To: undisclösed-recipients:; BCC: Robert E Mintz <robert_tnÍntz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>" Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, trmjrl <trmjr l@aol.com>, jbriddle <jbriddle@marathonoil.com>, shaneg <shaneg@evergreengas.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark. p. worcester@conocöphillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.akus>, tjr <tjr@dnr.state.akus>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'DoßI\ell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Paul G. Hyatt" <hyattpg@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sömmer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl 1. Kleppin" <K1eppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, Collins Mount <collins _ mount@revenue.state.akus>, mckay <mckay@gcLnet>, Barbara F Fullmer <barbara.ffullmer@conocophillips.com>, bocastwf <bocastwf@bp.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_ schultze@xtoenergy.com>, Hank Alford <harncalford@exxonmobil.com>, Mark Kovac <yesno l@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred. steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite,net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <jah@dnr,state.akus>, Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buonoje@bp.com>, Mark Harney <mark _hanley@anadarko.com>, loren _lernan <loren_Ieman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.akus>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan_hill@dec.state.ak.us>, tablerk <tablerk@Unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.akus>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Bill Miller <Bill_Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <k:jzeman@marathonoil.com>, John Tower <John,Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>, jack newell <jack.newell@acsalaska.net>, James Scherr <James. Scherr@mms.gov>, david roby lof2 2/15/2005 10:12 AM conservatIon Urders <David.Roby@mms.gov>, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry,C.Dethlefs@conocophillips.com>, Jerry Dethlefs <n 1617@conocophillips.com>, crockett@aoga.org, , Cynthia B Mciver <bren _ mciver@admin.state.ak.us> CO df Content-Type: application/pdf 552.p Content- Encoding: base64 C Content- Type: application/pdf 0548.pdf Content-Encoding: base64 Content- Type: application/pdf C0549.pdf Content-Encoding: base64 Content- Type: application/pdf C0550.pdf Content-Encoding: base64 Content- Type: applicationJpdf C0551.pdf Content-Encoding: base64 Content- Type: application/pdf C0547.pdf Content-Encoding: base64 20f2 2/15/2005 10:12 AM Citgo Petroleum Corporation Mary Jones David McCaleb PO Box 3758 XTO Energy, Inc. IHS Enérgy Group Tulsa, OK 74136 Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Mona Dickens Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 408 18th Street President Boise, ID 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman Schlumberger David Cusato Halliburton Drilling and Measurements 200 West 34th PMB 411 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Baker Oil Tools Ivan Gillian Land Department 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99507 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla Richard Wagner Cliff Burglin 399 West Riverview Avenue PO Box 60868 PO Box 70131 SOldotna, AK 99669-7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl Williams Thomas North Slope Borough K&K Recycling Inc. Arctic Slope Regional Corporation PO Box 69 PO Box 58055 Land Department Barrow, AK 99723 Fairbanks, AK 99711 PO Box 129 Barrow, AK 99723 1aJed . It I ' ~j¡S/1J7 . . FRANK H. MURKOWSKI, GOVERNOR A "~A~1iA OIL AlQ) GAS 333 W 7'H AVENUE. SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 559.003 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.001 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.001 All other oil pools within Prudhoe Bay Field ADMINISTRATIVE APPROVAL CO 548.001 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.001 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.001 Northstar Pools Gordon Pospisil GPB Watertlood Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil, By application dated August 30, 2006 BP Exploration (Alaska), Inc. ("BPXA") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to use a portable multiphase metering ("MPM") system for well testing and allocation of production in the Prudhoe Bay Field, the Endicott Field, the Milne Point Field and the Northstar Field. Notice of public hearing was published in the Anchorage Daily News on September 22, 2006. The Commission received no protest or requests for a public hearing and subsequently vacated the public hearing. BPXA's application is in accordance with the Commission's document, "Guidelines for Qualification of Multiphase Meters for Well Testing" ("Guidelines") dated November 30, 2004. BPXA proposes to use the FMC Technologies Enhanced Multiphase System lM ("EMS Thr). BPXA has proposed the use of a portable MPM device to supplement and fi'ee up limited portable test separator units currently used for production allocation testing, for flowback jobs on new production wells and after wellwork. The use ofMPM rather than a gravity separator system will result in more frequent testing due to lowered required stabilization time. While the system is potentially slightly less accurate (roughly 6% inaccuracy on fluid rate for the EMSlM vs. 3-5% with a well.calibrated and correctly designed gravity system), the system may improve overall allocation accuracy due to more frequent testing because less stabilization time is required for the EMSlM. More frequent testing will allow for improved reservoir surveillance. Easier and faster rig-up time and less need for operator intervention should reduce HSE risk once field experience is gained with the unit. It is important to gain field experience with the EMSlM to verify operability and accuracy. Indexing against a correctly calibrated test separator system will allow for evaluation as to whether systemic errors in measurement occur. However, since the measurements are relative to other separator systems' accuracy, measurements will be more uncertain than that of the loop tests. The controlled loop testing indicate the accuracy of the EMSlM meter system is . . satisfactory for well testing and production allocation purposes so long as the system is operated in accordance with BPXA's application. Field testing on the North Slope is planned according to the Guidelines. The unit will be indexed against a separate ASRC portable gravity separator unit and the pad separator (where practical). Initial tests may also involve tank gauging. Tests of representative wells completed in the Ivishak, Kuparuk, and Schrader Bluff formations will provide a full range of fluid properties with as large a range of GVF and water cut as practical. Tentatively, wells at Prudhoe L Pad and E Pad and MPU H Pad are targeted. The Commission approves BPXA's request to use the EMSTM meter system for well testing and allocation on the following conditions: 1. The EMSTMmeter system is operated in accordance with BPXA's application; 2. BPXA conducts field testing of the EMSTMmeter system in accordance with its plans outlined in their e-mail correspondence to Jane Williamson from Jerry Brady regarding "3M Field Qualifications Plan" on October 27,2006; and 3. BPXA' s report of test results is provided to the Commission no later than September 1,2007. This order expires on January 1,2008. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day fall n a holiday or weekend. A person may not appeal a Commission decision to Superior Cou nl ss rehearing has been requested. rage, Alaska and dated November 14, 2006. ØIZ:~ ~flt~ Daniel T. Seamount, Jr. Commissioner co 402a-001, co559-003, co570-001, C0547-001,48-001, co550-00... . Subject: co 402a-00l, co559-003, co570-001, 00547-001, co548-001, co550-001, co551-001 From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 15 Nov 2006 13:40:41 -0900 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjr l@ao1.com>, jdarlington <jdarlington@forestoi1.com>, nelson <knelson@petroleumnews.oom>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@oonocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.oom>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mike1.Schultz@BP.oom>, ''Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@oonocophillips.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobi1.com>, Mark Kovac <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conooophillips.com>, Brit Lively <mapalaska@ak.net>,.jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark _ hanley@anadarko.com>, loren _leman <loren_leman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobi1.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@ao1.com>, rmc1ean <rmc1ean@pobox.alaska.net>, mkm7200 <mkm7200@ao1.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary _ schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.oom>, Paul Winslow <pmwinslow@forestoi1.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>,jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, n1617@conocophillips.com, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@oonocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Karl Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Todd Kratz <ToddKratz@chevron.com>, Gary Rogers <gary _ rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <ken@secorp-inc.oom>, Steve Lambert <salambert@unoca1.oom>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews lof2 11/15/20061:44 PM co 402a-001, c0559-003, c0570-001, C0547-001,48-001, c0550-00... <Iris _ Matthews@legis.state.ak.us>, Paul Decker <pau1_ decker@dnr.state'.us>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoi1.com>, Cammy Taylor <Camille_Taylor@law.state.ak.us>, Winton GAubert <winton_aubert@admin.state.ak.us>, Thomas E Maunder <tom _ maunder@admin.state.ak.us>, Stephen F Davies <steve _davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoi1.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg <jim_regg@admin.state.ak.us>, Catherine P Foerster<cathy_foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <laura _ silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobi1.com>, akpratts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve _ moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paul_bloom@ml.com>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple_davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, Mike Stockinger <Mike.Stockinger@anadarko.com> Jody Colombie <jody colombie(tiJadmin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf co402a-Ol.pdf Content-Encoding: base64 Content-Type: application/pdf co559-3 and others.pdf C b ontent-Encoding: ase64 20f2 11/15/20061:44 PM . . Mona Dickens Mary Jones David McCaleb XTO Energy, Inc, IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Kay Munger Michael Parks 200 North 3rd Street, #1202 Munger Oil Information Service, Inc Marple's Business Newsletter Boise, ID 83702 PO Box 45738 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Seattle, WA 98119-3960 Mark Wedman Schlumberger Baker Oil Tools Halliburton Drilling and Measurements 4730 Business Park Blvd., #44 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Jill Schneider Land Department 9649 Musket Bell Cr.#5 US Geological Survey PO Box 93330 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough Williams Thomas PO Box 69 Arctic Slope Regional Corporation Barrow, AK 99723 Land Department \~ LP PO Box 129 Barrow, AK 99723 ,~\~ \ u 0 \ \\\\ . . SARAH PALIN, GOVERNOR AI,A~1iA. OIL AlÐ) GAS CONSERVATION COMMISSION 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 559.003 (Amended) Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.001 (Amended) Raven Oil Pool ADMINISTRA TIVE APPROVAL CO 547.001 (Amended) All other oil pools within Prudhoe Bay Field ADMINISTRATIVE APPROVAL CO 548.001 (Amended) All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.001 (Amended) All Milne Point Pools ADMINISTRA TIVE APPROVAL CO 551.001 (Amended) Northstar Pools Gordon Pospisil GPB Waterflood Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil, The above referenced administrative approvals are amended to authorize the use of a Schlumberger PhaseWatcher VX™ Multi-Phase Flow Meter as a stand-alone unit or in combination with CMF Technologies CDS-Gasunie separator for well testing at the BP Exploration (Alaska) Inc. operations listed above as requested by your application dated March 30, 2007, and received by the Alaska Oil And Gas Conservation Commission on April II, 2007. Inserted text is shown in bold and [DELETED TEXT IS SHOWN IN ALL CAPS AND BRACKETED]. By applications [APPLICATION] dated August 30,2006, and March 30, 2007, BP Exploration (Alaska), Inc. ("BPXA") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to use [A] portable multiphase metering ("MPM") systems [SYSTEM] for well testing and allocation of production in the Prudhoe Bay Field, the Endicott Field, the Milne Point Field and the Northstar Field. Notices [NOTICE] of public hearing were [WAS] published in the Anchorage Daily News on September 22, 2006, and April 26,2007. The Commission received no protest or requests for either [A] public hearing and subsequently vacated them. [THE PUBLIC HEARING]. BPXA's application is in accordance with the Commission's document, "Guidelines for Qualification of Multiphase Meters for Well Testing" ("Guidelines") dated November 30, 2004. BPXA proposes to use the FMC Technologies Enhanced Multiphase System TM ("EMS TM') and the Schlumberger PhaseWatcher VX™ Multi-Phase Flow Meter (VX™). BPXA has proposed the use of [A] portable MPM devices [DEVICE] to supplement and free up limited portable test separator units currently used for production allocation testing, for flowback jobs on new production wells and after wellwork. The use of MPM rather than a gravity . . July 9, 2007 Page2of3 separator system will result in more frequent testing due to lowered required stabilization time. The [WHILE THE] MPM systems are [SYSTEM IS] potentially slightly less accurate than a well-calibrated and correctly designed gravity separator system: [(]roughly 6% inaccuracy on fluid rate for the EMS™; roughly 2.5% inaccuracy on fluid rate, for gas volume fractions ("GVF") that are less than 90%, for the VX™ system; and [VS.] 3-5% with a well calibrated and correctly designed gravity separator system[)]. [,] However, the MPM systems [SYSTEM] may improve overall allocation accuracy due to more frequent testing because less stabilization time is required for the EMS™ and VX™ systems. Also, more [MORE] frequent testing will allow for improved reservoir surveillance. Easier and faster rig-up time and less need for operator intervention should reduce health, safety, and environmental [HSE] risk once field experience is gained with the unit. It is important to gain field experience with the EMS™ to verify operability and accuracy. Indexing against a correctly calibrated test separator system will allow for evaluation as to whether systemic errors in measurement occur. However, since the measurements are relative to other separator systems' accuracy, measurements will be more uncertain than that of the loop tests. The controlled loop testing indicated that the accuracy of the EMS™ meter system is satisfactory for well testing and production allocation purposes so long as the system is operated in accordance with BPXA's application. Field testing on the North Slope is planned according to the Guidelines. The unit will be indexed against a separate Arctic Slope Regional Corporation [ASRC] portable gravity separator unit and the pad separator (where practical). Initial tests may also involve tank gauging. Tests of representative wells completed in the Ivishak, Kuparuk, and Schrader Bluff formations will provide a full range of fluid properties with as large a range of GVF and water cut as practical. Tentatively, wells at Prudhoe L Pad and E Pad and MPU H Pad are targeted for the field testing. It is also important to gain field experience with the VX™ systems to verify operability. The controlled loop testing indicated that the accuracy of the VX™ system is satisfactory for well testing and production allocation purposes so long as the system is operated in accordance with BPXA's application. However, the CDS-Gasunie separator component has not yet had the extensive field testing that was anticipated in the application. Until confidence in the proper operation of the CDS-Gasunie separator is demonstrated to the Commission's satisfaction, testing of the proposed system that uses this component will be required. The Commission approves BPXA's request to use the EMS™ meter system for well testing and allocation on the following conditions: I. The EMS™meter system is operated in accordance with BPXA's application; 2. BPXA conducts field testing of the EMS™meter system in accordance with its plans outlined in their e-mail correspondence to Jane Williamson from Jerry Brady regarding "3M Field Qualifications Plan" on October 27,2006; and 3. BPXA's report of test results is provided to the Commission no later than September 1,2007. Further, the Commission approves BPXA's request to use the VX™ meter systems for well testing and allocation on the following conditions: 1. The VX™ metering systems are operated in accordance with BPXA's application; 2. BPXA conducts field testing of the Vx TM with a CDS-Gasunie separator system . . July 9, 2007 Page 3 of3 in a manner consistent with the agreed upon testing protocols referenced in condition 2 above for the EMS™ meter system; 3. The Commission may revoke the field testing requirement for the VX™ with a CDS-Gasunie separator system upon proper application from BPXA after sufficient operational experience with, and testing of, the CDS-Gasunie separator have proven to the Commission's satisfaction that it operates properly in the field; and 4. BPXA provides the Commission with a report detailing their operational experience with and testing of the VX™ systems by December 1,2007. This order expires on January 1,2008. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Co u less rehearing has been requested. !~ Daniel T. Seamount, Jr. Commissioner cc: Art Copoulos, DNR, DOG Robynn Wilson, DOR, Tax Div. Jeffrey Walker, MMS . Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, W A 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 . . Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, July 11, 20077:44 AM To: Mciver, C (DOA); Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov); Aleutians East Borough; Anna Raff; Arthur C Saltmarsh; Arthur Copoulos; Barbara F Fullmer; bbritch; Bill Fowler; Bill Walker; Brad McKim; Brady; Brandon Gagnon; Brian Gillespie; Brit Lively; buonoje; Cammy Taylor; carol smyth; Cary Carrigan; Catherine P Foerster; Charles O'Donnell; Chris Gay; Christian Gou-Leonhardt; Christine Hansen; Cliff Posey; Cody Rice; Dan Bross; dapa; Daryl J. Kleppin; David L Boelens; David Steingreaber; ddonkel; Deanna Gamble; Deborah J. Jones; doug_schultze; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gregg Nady; gregory micallef; gspfoff; Hank Alford; Harry Engel; jah; James B Regg; James M. Ruud; James Scherr; Janet D. Platt; jdarlington; jejones; Jerry McCutcheon; Jim White; Jim Winegarner; Joe Nicks; John Garing; John S. Haworth; John Spain; John Tower; John W Katz; Jon Goltz; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kristin Dirks; Laura Silliphant; Lois; Lynnda Kahn; mail=akpratts@acsalaska.net; mail=crockett@aoga.org; mail=foms@mtaonline.net; Mark Dalton; Mark Hanley; Mark Kovac; Mark P. Worcester; Marquerite kremer; marty; Matt Rader; mckay; Meghan Powell; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Nick W. Glover; Patty Alfaro; Paul Decker; Paul Winslow; Randall Kanady; Randy L. Skillern; rcrotty; rmclean; Robert Campbell; Roger Belman; Rosanne M. Jacobsen; Rudy Brueggeman; Scott Cranswick; Shannon Donnelly; Sharmaine Copeland; Sondra Stewman; Sonja Frankllin; stanekj; Stephen F Davies; Steve Lambert; Steve Moothart; Steven R. Rossberg; tablerk; Tamera Sheffield; Temple Davidson; Terrie Hubble; Thomas E Maunder; Tim Lawlor; Todd Durkee; Tricia Waggoner; trmjr1; Walter Featherly; Walter Quay; Wayne RanGier Subject: Various Admin Approvals and 1 Conservation Order Attachments: Colombie, Jody J (DOA).vcf; Cancelled AI01 OB-004.pdf; Amended C0402A-001.pdf; Various Admin Approvals.pdf; CO 583.pdf Cancelled Admin Approval AI010B-004 CO 583-Sterling Unit 41-15RD Amended Admin Approval CO 402A-001 Amended Admin Approval CO 559-003 Put River Amended Admin Approval CO 570.001 Raven Amended Admin Approval C0547-001 All Pool Prudhoe Bay UNit Amended Admin Approval CO 548-001 All Endicott Pool Amended Admin Approval CO 550-001 All Milne Point Pool Amended Admin Approval CO 551-001 Northstar Pool Jody J. Colombie Special Assistant to the Commission I State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Tel: (907) 793-1221 Fax:(907)276-7542 7/11/2007 . . SARAH PALIN, GOVERNOR AIASIiA OIL AND GAS CONSERVATION COMMISSION 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRA TIVE APPROVAL CO 559.006 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.003 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.002 All other oil pools within Prudhoe Bay Field ADMINISTRA TIVE APPROVAL CO 548.002 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.002 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.002 All Northstar Pools ADMINISTRA TIVE APPROVAL CO 402A.002 Badami Oil Pool Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil, By letter dated August 10,2007, BP Exploration (Alaska), Inc. ("BPXA") requested that the report of test results for the ongoing multiphase meter field tests, which were required by the above referenced administrative approvals, be moved from September 1,2007, to December 1,2007. In the request, BPXA cited significant construction delays that have delayed the start of the testing program. Consequently, BPXA will not be able to adequately test the multiphase metering equipment or properly analyze the resulting data by the September 1,2007, deadline. The Alaska Oil and Gas Conservation Commission ("Commission") believes BPXA has diligently pursued completion of this project and that the delay has been caused by factors not within their control. Therefore, BPXA's request to extend the deadline for this report from September 1, 2007, to December 1, 2007, is GRANTED. All other terms and conditions of the prior Conservation Orders and related Administrative Approvals remain in effect. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. To be timely, the application must be received by 4:30 P.M. on the 23rd day following the date of this decision document, or on the next working day if the 23rd day falls on a state holiday or weekend. A person may not appeal a Commission decision to the Superior Court unless the Commiss' has received a timely, properly filed application for reconsideration. orage, Alaska, and dated August 24,2007. ~~~)~;\ CommISsIOner \~.;."...i.tÎ¡~:.~.;.'.'.;:J .: ~:'.:"'" " . ...,. Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 \eÓJ 11 A~' i ~ßO . . Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, August 24,20072:29 PM Subject: Various Multiphase Metering Administrative Approvals Attachments: Various Multiphase Metering.pdf BCC:McIver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff; 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Fowler'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'carol smyth'; 'Cary Carrigan'; 'Catherine P Foerster'; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Christine Hansen'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl 1. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah 1. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=crockett@aoga.org'; 'mail=foms@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'marty'; 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker" 'Paul Winslow" 'Randall Kanady" 'Randy L Skillern" 'rcrotty" 'rmclean" 'Robert Campbell" , , ,.", , 'Roger Belman'; 'Rosanne M. Jacobsen'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'Tricia Waggoner'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments: Various Multiphase Metering.pdf; 8/2712007 • ~~Q~[~ 0~ ps~~~{Q ALA.-SRA OIL .~.I1Tn GAS COI~TSER'QATIOI~I CODIl~II55IOl~T SARAH PALIN, GOVERNOR 333 W. 7ihAVENUE, SUITE 100 ANCH4RP,GE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CORRECTED ADMINISTRATIVE APPROVAL CO 559.007 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.005 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.003 All other oil pools within Prudhoe Bay Field ADMINISTRATIVE APPROVAL CO 548.003 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.003 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.003 All Northstar Pools ADMINISTRATIVE APPROVAL CO 402A.003 Badami Oil Pool Gordon Pospisil Technology & Resource Manager BP Exploration {Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil, The Commission has corrected the Administrative Approval to reflect the correct number in Conservation Order 554. This Administrative Approval also corrects an oversight in the second paragraph by changing "March 31, 2008" to "May 31, 2008." By letter dated November 14, 2007, BP Exploration (Alaska), Inc. ("BPXA") requested that the Alaska Oil and Gas Conservation Commission ("Commission"} extend the deadline fi-om December 1, 2007, to March 31, 2008, for BPXA to complete multiphase metering field tests and submit the reports of the results. BPXA stated that its request was the result of "significant construction delays ...and additional testing required to ensure" that the metering systems "are functioning within designated parametexs." BPXA stated that the completion of reports as of March 2008 will also be difficult to achieve considering potential impact of weather delays upon field testing, contractor's time and availability to thoroughly analyze the data and prepare reports and therefore, BPXA's preferred date for final report to the Commission is May 31, 2008. Based on BPXA's representations, its request to extend the deadline----from December 1, 2007, to May 31, 2008----for completing the field tests and submitting the reports required by the above-referenced administrative approvals is hereby GRANTED. To evaluate the results of the field tests and reach a final decision concerning the use of the multiphase meters in determining production allocation, the commission intends to use the "Guidelines for Qualification of Multiphase Meters for Well Testing" ("Guidelines"), dated November 30, 2004, and adopted by Orders for all North Slope fields to help determine if these ` By original Conservation Orders 547, 548, 449, 550, 551, 552, 559, 570 and by Adminish•ative Approval 402A.001. November 30, 2007 Page 2 of 2 devices should be approved for production allocation purposes. The rule requiring the use of the Guidelines is set to expire December 31, 2007. In accordance with this decision, the expiration date of each aforementioned rule is extended to December 31, 2009. All other terms and conditions of the prior Conservation Orders and related Administrative Approvals are unchanged. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. To be timely, the application must be received by 4:30 p.m. on the 23`d day following the date of this decision or on the next working day if the 23`d day falls on a state holiday ar weekend. A person may not appeal a Commission decision to the Superior Court unless the Commission has received a timely, properly filed application for 30, 2007. ~~ Cathy P. Foerster Commissioner Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 30, 2007 10:25 AM Subject: Corrected Admin Approvals and ERIO 2-005 Attachments: Corrected Various Administrative Approvals.pdf; erio2-005.pdf BCC:McIver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR}; 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'carol smyth'; 'Cary Carrigan'; 'Catherine P Foerster ; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady ; 'gregory micallef ; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz ; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles ; knelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR}; 'rmclean'; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick ; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:Corrected Various Administrative Approvals.pdf;erio2-OOS.pdf; 11/30/2007 • Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 30, 2007 10:25 AM Subject: Corrected Admin Approvals and ERIO 2-005 Attachments: Corrected Various Administrative Approvals.pdf; erio2-005.pdf BCC:McIver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov) ; 'Aleutians East Borough'; 'Anna Raff; Arion, Teri A (DNR); 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'carol Smyth'; 'Cary Carrigan'; 'Catherine P Foerster'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber ; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil ; 'Gregg Nady ; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr ; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing ; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz ; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean ; 'Robert Campbell'; 'Robert Province'; 'Roger Belman ; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman ; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:Corrected Various Administrative Approvals.pdf;erio2-OOS.pdf; 11 /30/2007 • - - - - < __ ~, ~JL~-7~L'~ ®B~I COIITSERQI~7['IO1~T C®1~I155I®1`T SARAH PALIIV, GOVERINOR i~ 333 W. 7th AVENUE. SUITE 100 ANCHORAGE, ALASKA 99501-3539 ` PHONE (907) 279-1433 •' FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 559.007 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.005 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.003 All other oil pools within Prudhoe Bay Field ADMINISTRATIVE APPROVAL CO 548.003 Alt Endicott Pools ADMINISTRATIVE APPROVAL CO 550.002 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.003 All Northstar Pools ADMINISTRATIVE APPROVAL CO 402A.003 Badami Oil Pool Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil, By letter dated November 14, 2007, BP Exploration (Alaska), Inc. ("BPXA") requested that the Alaska Oil and Gas Conservation Commission ("Commission") extend the deadline from December 1, 2007, to March 31, 2008, for BPXA to complete multiphase metering field tests and submit the reports of the results. BPXA stated that its request was the result of "significant construction delays ...and additional testing required to ensure" that the metering systems "are functioning within designated parameters." BPXA stated that the completion of reports as of March 2008 will also be difficult to achieve considering potential impact of weather delays upon field testing, contractor's time and availability to thoroughly analyze the data and prepare reports and therefore, BPXA's preferred date for final report to the Commission is May 31, 2008. Based on BPXA's representations, its request to extend the deadline-from December 1, 2007, to March 31, 2008-for completing the field tests and submitting the reports required by the above-referenced administrative approvals is hereby GRANTED. To evaluate the results of the field tests and reach a final decision concerning the use of the multiphase meters in determining production allocation, the commission intends to use the "Guidelines for Qualification of Multiphase Meters for Well Testing" ("Guidelines"), dated November 30, 2004, and adopted by Order for all North Slope fields to help determine if these devices should be approved for production allocation purposes. The rule requiring the use of the Guidelines is set to expire December 31, 2007. In accordance with this decision, the expiration date of each aforementioned Wile is extended to December 31, 2009. By original Conservation Orders 547, 548, 449, 550, 551, 552, 559, 570 and by Administrative Approval 402A.001. • November 27, 2007 Page 2 of 2 All other terms and conditions of the prior Conservation Orders and related Administrative Approvals are unchanged. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. To be timely, the application must be received by 4:30 p.m. on the 23`d day following the date of this decision or on the next working day if the 23`d day falls on a state holiday or weekend. A person may not appeal a Commission decision to the Superior Coi,~unless the Commission has received a timely, properly filed application for Alaska, and dated November 27, 2007. ft 'I ; Il-~ Daniel T. Seamount, Jr. Cathy P oerst r Commissioner Commissioner • Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58D55 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 ~j p Barrow, AK 99723 ~ i ~ ~ I n " I ~~ i ~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, November 28, 2007 4:44 PM Subject: Various PBU Admin Approvals and A104E.015 PBU Attachments: Various Prudhoe Admin Approvals.pdf; aio4e-015.pdf BCC:McIver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR); 'Arthur C Saltmarsh'; 'Arthur Capoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'carol Smyth'; 'Cary Carrigan'; 'Catherine P Foerster'; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt ; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg ; 'James M. Ruud'; 'James Scherr ; 'Janet D. Platt'; 'jdarlington ; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marry'; 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mike! Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady ; 'Randy L. Skillern ; 'rcrotty ;Rice, Cody J (DNR); 'rmclean'; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:Various Prudhoe Admin Approvals.pdf;aio4e-O15.pdf; 11!28/2007 • • ~-~ ~ ~ ~ ~~ n } SARAH PALIN, GOVERNOR OIIl ~ ~ 333 W. 7th AVENUE, SUITE 100 CO1~T5~RQATI011T COMDIISSIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 550.004 All Milne Point Pools Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: By letter dated May 13, 2008, BP Exploration (Alaska), Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (Commission) grant final approval to use the portable ASRC Unit 5 well testing skid, which uses a FMC Technologies Enhanced Multiphase System (EMSTM), for well testing and allocation purposes in all oil pools of the Milne Point Field. t The Commission needs more time to review BPXA's application and meet with your technical representative before making a decision. Therefore, temporary approval to use the portable ASRC Unit 5 well testing skid for measurement and allocation purposes within the Milne Point Field is GRANTED. This approval expires on ~u~ust 31, 2008. Alaska, an~t.~d/May 292008. . Seamount, Jr. Orman Cathy . Foerster ener Commissioner ~ In Administrative Approval CO 550.003, entered on November 30, 2007, the Commission granted BPXA temporary approval to use the EMSTM for well testing and allocation purposes through May 31, 2008. • • RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements .Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas I Arctic Slope Regional Corporation (,/~/ Land Department ~ /~ PO Box 129 ( O ~/ Barrow, AK 99723 U/ 2 Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, May 30, 2008 8:59 AM Subject: co550-004 Milne Point Attachments: co550-004.pdf BCC:'Aleutians East Borough'; 'Anna Raff; Arion, Teri A (DNR); 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; Gould, Greg M (DEC); 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north- slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Dale Hoffman'; Fridiric Grenier; Joseph Longo; Maurizio Grandi; Tom Gennings; 'Willem Vollenbrock'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, .James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:co550-004.pdf; Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 5/30/2008 ~~Q~~ OIL Q~Q~~{Q / ,....a~.~o~.ow Ai~C~~7~ OI~ A1sD `IA5 333 W. 7th AVENUE, SUITE 100 C01~5I' RQA'I`IO1~T COMDII55IOrIT ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)276-7542 ADMINISTRATIVE APPROVAL CO 550.005 All Milne Point Pools Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: By letter dated May 13, 2008, BP Exploration (Alaska), Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (Commission) grant final approval to use the portable ASRC Unit 5 well testing skid, which uses a FMC Technologies Enhanced Multiphase System (EMSTM), for well testing and allocation purposes in all Milne Point Field oil pools.t In Administrative Order CO 550.004, the Commission approved the temporary use (i. e., until August 31, 2008) of the portable ASRC Unit 5 well testing skid for well testing and allocation purposes. The Commission explained that more time was needed to review test results and meet with BPXA technical representatives before making a final decision. Commission senior staff is continuing to review the test results and met with BPXA technical representatives on July 16, 2008. Based on the Commission's ongoing review, the meeting with BPXA's technical representatives, and the information requirements of the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" (Guidelines), adopted on February 11, 2005, the Commission finds that additional information and clarification of the application and testing results are needed to decide BPXA's request.2 (The required information and clarification will be separately identified.) Accordingly, BPXA's request for final approval is DENIED, but BPXA is GRANTED temporary approval to continue using the portable ASRC Unit 5 well testing skid for measurement and allocation purposes within the Milne Point Field oil pools until December 31, 2008. t In Administrative Approval CO 550.003, entered on November 30, 2007, the Commission granted BPXA temporary approval to use the EMSTM for well testing and allocation purposes through May 31, 2008. ~ The Guidelines' expiration was extended to December 31, 2009 in order to use the Guidelines to evaluate BPXA's final reports. See Administrative Approvals CO 559.007, CO 570.005, CO 548.003, CO 550.003, CO 547.003, CO 551.003, CO 402A.003. Administrative Approval CO 550-005 Page 2 of 2 August 27, 2008 All other terms and conditions of the prior Conservation Orders and related Administrative Approvals are unchanged. ENTERED at Anchorage, Alaska, and ugus 27, 2008. Daniel T. Seamount, Jr. Jo or an Cathy P. Foerster Chair C is ' ner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Mark Wedman Baker Oil Tools 200 North 3rd Street, #1202 Halliburton 4730 Business Park Blvd., #44 Boise, ID 83702 6900 Arctic Blvd. Anchorage, AK 99503 Anchorage, AK 99502 Schlumberger Ciri Ivan Gillian Drilling and Measurements Land Department 9649 Musket Bell Cr.#5 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99507 Anchorage, AK 99503 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla Richard Wagner Cliff Burglin 399 West Riverview Avenue PO Box 60868 PO Box 70131 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl North Slope Borough Williams Thomas K&K Recycling Inc. PO Box 69 Arctic Slope Regional Corporation PO Box 58055 Barrow, AK 99723 Land Department Fairbanks, AK 99711 PO Box 129 Barrow, AK 99723 /~a~/~~ ~ /~/~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, August 28, 2008 2:10 PM Subject: co550-005 Milne Point Attachments: co550-005.pdf BCC:'Dale Hoffman'; Fridiric Grenier; Joseph Longo; 'Lamont Frazer'; 'Mary Aschoff; Maurizio Grandi; P Bates; 'Scott Nash'; Tom Gennings; 'Willem Vollenbrock'; 'Aleutians East Borough'; 'Anna Raff; Arion, Teri A (DNR); 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; Gould, Greg M (DEC); 'Gregg Nady'; 'gregory micallef ; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'Meghan Powell'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean ; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:co550-OOS.pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 8/28/2008 Page 1 of 1 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Thursday, August 28, 2008 2:22 PM To: Brady, Jerry L Cc: Pospisil, Gordon Subject: FW: co550-005 Milne Point Attachments: co550-005.pdf Jerry, See attached. Continued use of Unit 5, FMC MPFM at MPU is granted through the end of the year. Before giving final approval, I need to go through the guidelines, see what information is missing, and, if necessary, send you a request for additional information, and evaluate. In addition, as there is differential royalty in MPU, Temple Davidson DNR indicated she needs more time to determine if they have any concerns. Jane IYViCCiamson, PE AOGCC Senior Reservoir Engineer (907)793-1226 8/28/2008 • L~-7~ ®~ C®1~SERQATIOI~T COMbIISSIOIQ SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 559.008 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.006 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.004 All other Prudhoe Bay Field Oil Pools ADMINISTRATIVE APPROVAL CO 548.004 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.006 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.004 All Northstar Pools ADMINISTRATIVE APPROVAL CO 402A.004 Badami Oil Pool Approval of Use of Weatherford Generation 2.0 Multiphase Metering Systems for Production Well Testing and Allocation within BPXA Operated Oil Fields Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: By application dated July 8, 2008, and received on July 16, 2008, BP Exploration (Alaska), Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (Commission) grant approval to use the Weatherford Generation 2.0 Multiphase Metering System (Gen 2) for production well testing and allocation within BPXA operated oil fields. By e-mail dated October 9, 2008, BPXA stated that it intends to use the Gen 2 only for production well testing and allocation where the production characteristics are similar to those of the PBU Drill Pads V (V- Pad) and E (E-Pad) wells where the Gen 2 was field tested. BPXA requested quick approval, particularly so that it can deploy the Gen 2 at V-Pad and DS-1 to replace the well pad separators there. In accordance with 20 AAC 25.230(a), the Commission GRANTS BPXA's request to use the Gen 2 for production well testing and allocation within the oil pools noted for wells with similar production characteristics as those where the Gen 2 was field tested, subject to conditions set out in this order. Commission Authority AS 31.05.030(d)(6) and 20 AAC 25.230 authorize the Commission to approve the methodology and equipment 'wt.lized for production :.'ell testing and allocation. Because nc standards and few guidelines exist for multiphase flow meters (MPFMs), the Commission developed "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" (Guidelines) to aid operators in preparing applications for approval to use MPFMs for well testing and production Gordon Pospisil • Technology & Resource Manager October 29, 2008 Page 2 of 10 allocation and to assist the Commission in assessing the performance of MPFMs.' On February 11, 2005, the Commission issued orders for all North Slope oil pools requiring that for purposes of satisfying well-test measurement requirements of 20 AAC 25.230, the use of MPFMs will be approved only in accordance with the provisions of the Guidelines. The Commission may administratively waive a requirement of the Guidelines or administratively amend the Guidelines as long as the change does not promote waste or jeopardize correlative rights and is based on sound engineering and geoscience principles. Notification BPXA sent the application to all working interest owners and royalty owners (i. e., the Alaska Department of Natural Resources, Division of Oil and Gas (DOG) and U.S. Mineral Management Services (MMS)) of BPXA operated fields; BPXA also sent the application to the Alaska Department of Revenue (DOR). On August 11, 2008, BPXA presented a technical overview of laboratory and field-testing results of the Gen 2 to the Commission, DOG, DOR, and MMS. Additional Information and Clarifications BPXA provided additional data concerning the field trials (in a-mails dated September 11, 2008, from Jerry Brady and dated October 13, 2008, from Andrew Hall) in response to questions from Jane Williamson (a Commission reservoir engineer). Agencies DOG, DOR, and MMS do not object to the use of the Gen 2 as lon~ as it is used only for production well testing and allocation: i. e., not to replace LACT meters. Also, DOG and MMS noted that separate approvals are required for the installation of MPFMs in areas under their jurisdictions. MMS suggests the AOGCC or BPXA develop a quality assurance program by which these meter systems are evaluated for accuracy and reliability and that this information be reported to the AOGCC on a reasonable schedule. DOR wants to be informed of any changes in use or approval of BPXA's measurement systems. Findings The Gen 2 is an in-line MPFM consisting of four principal components: anear-infrared water- cut monitor (Red-Eye 2G); a Cs 137 gamma densitometer; a passive sonar volumetric flow meter; and a venturi nozzle differential pressure flow meter. The principles of the Gen 2 measurement and rate determination are described in the application. A significant amount of lab and field testing was conducted. Loop tests showed less than f5% uncertainties in the measurements of the gas rate, liquid rate and water-cut for individual components of the Gen 2. ~ The Guidelines and Commission's accompanying "Principles of Multiphase Measurements" are on the Commission's Web site: http~//www state ak us/localiakpaaes~ADMIN!oQc/MeterGuide.shtml. Z See Letter from Kevin R. Banks, Acting Director, DOG, to Daniel Seamount, Jr., Char, Commission (Oct. 3, 2008); letter from Jonathan Iversen, Director, DOR Tax Division, to Seamount (Oct. 7, 2008); letter from Jeffrey Walker, Alaska Regional Supervisor, MMS, to Seamount (Sept. 30, 2008). Gordon Pospisil Technology & Resource Manager October 29, 2008 Page 3 of 10 V-Pad field trials -liquid-dominated regime, high gas-volume fraction (GVF)3, gas-lifted wells (see Figures 1-S) Field tests were conducted at V-Pad with the Gen 2 in series with a portable gravity separator system (ASRC Unit 1), which was used as the reference for measurements. Tests were also conducted with the V-Pad separator. The ASRC Unit 1 was manned throughout the test; the unit has been extensively used in BPXA production testing. The meters and the metering devices were recently calibrated for this field trial. No problems with the performance of the ASRC Unit 1 were noted in the application. The wells at V-Pad produce from the Borealis (Kuparuk Formation), Orion (Schrader Formation), and Prudhoe Bay (Sadlerochit Formation) Oil Pools. Total fluid (oil and water) rates ranged from 300 barrels per day (BPD) to 3,200 BPD; water-cut rates ranged from 0%- 96%. The wells are gas lifted and gas-volume fractions ranged from 85% to 98%. Fluid viscosities ranged from 1.4 centipoise to 653 centipoise. Mayor findin~,s V-Pad field trials • Compared to the ASRC Unit 1 separator, the Gen 2 measurement uncertainties were within ~7% for the gas rate and f8% for the liquid rate. The ASRC Unit 1 estimated uncertainties are f3% for the gas rate and f5% for the liquid rate. No noticeable bias was seen. The fluid rates did not appear to be affected by the water-cut or GVF. • Compared to the ASRC Unit 1 separator, the Gen 2 water-cut uncertainty was within ~5%. The ASRC Unit 1 estimated water-cut uncertainty was f2%. When the ASRC Unit 1 water- cut measurements exceeded 60%, the Gen 2 tended to over-read the water-cut. Gen 2 water- cuts exceeded those of the ASRC Unit 1 by more than 10% in only two well tests, however. Further investigation of the Gen 2 water-cut measurement performance in the mid to high water-cut range may be warranted. • The Gen 2 performed well in measuring the Schrader Formation well production with high viscosity (i. e., up to 632 cp). Additional testing of highly viscous, high water-cut fluids is recommended to verify performance for all ranges of Schrader Formation well operating conditions. • The performance of the Gen 2 was better than that of the existing V-Pad separator throughout the range of well operating conditions. Major Findings E-Pad field trials -wet-gas regime (see Figures 6-8) • The results of the tests of a wet-gas meter (with the same basic technology as the Gen 2 (excluding the densitometer device)) and a reference gravity-based separator were compared. The field test showed gas rates within f5%. Liquid rates were within t10% (excluding data from a few bad tests). Gas-oil measurements were within t5%. • Water-cut measurements were not reported in the material BPXA provided. • The results compared as well or better than those of the loop tests. 3 "The GVF is the gas-volume flow rate, relative to the multiphase volume flow rate, at the pressure and temperature prevailing in that section. The GVF is normally expressed as a percentage. See Appendix 2 of "Principles of Multiphase Measurements" at htt :1/www.state.ak.us/locaUak aces/ADMIN/osc/MeterGuide.shtml. Gordon Pospisil • Technology & Resource Manager October 29, 2008 Page 4 of 10 Applicabili~ of the Gen 2 for well testing in BPXA operated fields V-Pad installation The Gen 2 performance was superior to that of the V-Pad separator through the full range of flow rates and water-cuts. Using the Gen 2 should result in better overall production allocation for this pad. Additional performance testing when water-cut exceeds 60% is recommended. DS-1 proposed installation The flow rates of DS-1 wells range from about 400-13,000 BPD total liquid, including 400-1,100 stock tank barrels per day (STB/D) of oil. The gas-liquid ratios range from 12 million - 100 million standard cubic feet per stock tank barrel (MMscf/STB) and water-cuts range from 0%- 95%. Many of these wells are cycled producers. The gas-oil ratio (GOR) increases within a few days of bringing a well on line; within a few days, it exceeds the marginal GOR of the plant. The Gen 2 may aid in providing more frequent testing to determine whether the well GOR is too high to continue flow. However, the production characteristics may be out of the range of current Gen 2 testing. BPXA needs to update the Commission on the Gen 2's performance at DS-1. Installation at other BPXA pads Based upon the information BPXA supplied, the Commission anticipates measurements better than f 10% uncertainty for most wells in BPXA fields. The Gen 2 flow-rate uncertainties are within the range of uncertainties for gravity-based separation devices as shown by monthly allocation reports filed with the Commission, DOG, and DOR. The Gen 2 flow-rate uncertainties are r*^hahly sufficientl accurate for reservoir management purposes, particularly i. ..__ Y ii there are more frequent well tests. t rl~ Gen 2 performance, however, needs to be evaluated in more extreme conditions (such as in the proposed DS-1 installation and in pads with higher viscosity and higher water-cut Schrader Formation wells). Conclusions 1. BPXA's application meets the requirements of 20 AAC 25.230(a) and the Guidelines for use of MPFMs for production well testing and allocation. 2. The anticipated accuracy exceeds X10 % for wells within the range of conditions tested. This accuracy is suitable for well testing and allocation for reservoir management purposes. 3. During the trials, the performance of the Gen 2 was superior to that of the V-Pad test separator. 4. Additional testing of the Gen 2 is warranted for wells with high water-cut and highly viscous flows. 5. Information from the DS-1 testing will expand the envelope of test information available for determining the applicability of the Gen 2. 6. Continued testing of the Gen 2 will advance MPFM technology and aid BPXA in reservoir surveillance and management. 7. Through periodic performance reviews, the Commission can ensure that the Gen 2s are performing as expected. Gordon Pospisil • Technology & Resource Manager October 29, 2008 Page 5 of 10 8. None of the affected agencies object to the use of the Gen 2 as long it will be used only for well testing and production allocation: i. e. ,not to replace LACT meters. 9. Separate approvals are required for the installation of Gen 2s in areas under the jurisdiction of DOG or MMS or both. 10. The use of the Gen 2 for well testing and production allocation in existing BPXA fields is not expected to promote waste or jeopardize correlative rights. Order In accordance with 20 AAC 25.230(a), the Commission GRANTS BPXA's request to use the Weatherford Generation 2.0 Multiphase Metering System for production well testing and allocation within BPXA operated oil fields where the production characteristics are similar to those of the V-Pad and E-Pad wells where the Gen 2 was field tested. Specifically, installations at PBU V-Pad and PBU DS 1 are approved. This approval is conditioned upon the following: 1. the Gen 2 shall not replace Lease Automatic Custody Transfer meters; 2. production allocation methods shall remain unchanged unless changed by order of the Commission; 3. factory acceptance tests, field maintenance, periodic calibration, and fluid sampling must be performed in accordance with BPXA's application; 4. BPXA must notify the Commission before installing the Gen 2 at any BPXA site; 5. BPXA must conduct yearly status meetings by September 30 of each year detailing the installations to-date, the performance of each Gen 2, all operational issues relating to the Gen 2, and any additional Gen 2-related test results. Thorough summaries of this information shall be included in the annual surveillance reports filed with the Commission by BPXA for the individual pools; 6. BPXA must submit to the Commission a detailed plan of a long-term quality assurance program by January 15, 2008; 7. if the Gen 2 does not perform to the Commission's satisfaction, BPXA must correct the problems or redeploy the existing pad separators; 8. all notices, reports, and other submissions BPXA is required to make to the Commission under this order must, at the time of the submission to the Commission, be provided to all affected working interest and royalty owners and DOR. Gordon Pospisil • Technology & Resource Manager October 29, 2008 Page 6 of 10 9. upon proper application, or its own motion, and unless notice and public hearing is required, the Commission may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated October 29, 2008. .~ ~`° Daniel T. Seamount, Jr. Chair TION AND As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the oruer or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gordon Pospisil • • Technology & Resource Manager October 29, 2008 Page 7 of 10 2500 ~ooo ~~+ 1 Soo 1000 500 Attachments Fi;;ure 1 Comparison A11 Tests -Liquid Rate ,STB/D vs Unit 1 Liquid Rate, STB/D Gen 2, V-WPS ____ _~ O 0 I ' ~ ~ i ---- ~ I' ~~ - ~ ~ ~~ ® Gen 2 , Sadlerochit ~ Gen 2 Kuparuk 6 ® Gen 2 Schrader } - , -' s V-WPS Sadlerochit I !.. ~ ' ~ ~ I ® V-WPS Kuparuk ,, ~ i, I © V-WPS Schrader 500 1000 15oU ~~~~ Unit 1 Liquid STB/D Fi rite L Comparison All Tests -Gas Rate, Mscfd to Unit 1 Gas Rate Gen 2, V-WPS 2500 4000 _._ _ _ ~ I g 3000 °~3- 2000 __ -' ~I • Gen 2 Sadlerochit I'. pZ - " ~ ~ `~ Gen 2 Kuparuk Y i ~ .. ' ~ ~ Gen 2 Schrader I~ 1 OOQ • V-WPS Sadlerochit '~ I~~ = V-WPS Kuparuk j' ~ V-WPS Schrader ~~ 0 ~ ~' 3000 4000 2000 0 1000 Unit 1 Gas Rate, Mscfd STB/D Gordon Pospisil Technology & Resource Manager October 29, 2008 Page 8 of 10 100% 80% e 60"~° U d ~ 40% 20% 60% 40% L 20% t W 0% O LL N C -20% -40% 0 0 000 20% 40% 60% 80% 100% Unit 1 Water Cut, Figure 3 Comparison All Tests Water Cut vs Unit 1 Water Cut Gen 2, V-WPS __ _ _ ~ I _ _ ^ ; ^ 1~ i chit dl 2 S 1 ® ero a ® Gen ' ^ Gen 2 Kuparuk ® • ~, ~~ I ® Gen 2 Schrader I • V WPS Sadlerochit ^ V-WPS Kuparuk ~ ® ~ I ~ ~ • V-WPS Schrader ^ -60% 0% 20% 40% 60% 80% Unit 1 Water Cut, w0% Fi;:ure 4 .•,......,~~.,.. eu rast¢ % Error Fiow Rate vs Unit 1 Water Cut Gordon Pospisil Technology & Resource Manager October 29, 2008 Page 9 of 10 Figure 5 Comparison All Tests % Error Flow Rate vs Unit 1 Gas Volume Fraction Gen 2, V-W PS so°i° 40% 20% W 0% LL N -20% .1f1% -60% 80% 100% 90% Gas-Volume Fraction (GVF) ~i~ure so 45 40 YYa;' 35 30 25 C ~Q 20 15 U 10 5 0 t5% O , ~~ ~~ ~~~ 0 5 10 15 20 25 30 35 Test separator gas flowrate (MMscf/d) 50 Gordon Pospisil ~ • Technology & Resource Manager October 29, 2008 Page 10 of 10 Figure 7 lzoo a loon a M M 800 O C Q 600 O N tM m C O U j 200 All these points _ _ within 110% ,, 0 ~ ' O, unreliable / iow Ipuid it , rate from test separator O V-cone transmitter _ - _ O suspected out of --- range -_._U ~ ' ~R '' -. V-wne transmitter Liquid rate verified ~ O ``, certainly out of with ASRC Una 7 range 0* 0 200 400 600 duu ~~~~ Test separator liquid flowrate (stb/d) 1200 Figure 8 15000 o. O V-cone transmitter suspected out of range p Q 0 100000 90000 _ 80000 a w 70000 ~ 60000 ~ $0000 D V 40000 m 0 30000 U 20000 10000 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 Test separator GOR (scflbbl) • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, October 30, 2008 12:33 PM Subject: dio23-002 and Weatherford Generation 2.0 Multiphase Metering Admin Approval Attachments: dio23-002.pdf; Weatherford generation 2.0 Multiphase Metering AA.pdf BCC:'Aaron Gluzman'; caunderwood@maxathonoil.com; 'Dale Hoffman'; Fridiric Grenier; Jason Brink; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; 'Sandra Lemke'; 'Scott Nash'; Sherry Corley; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; 'Aleutians East Borough'; 'Anna Raff; 'Barbara F Fu'.lr~.cr'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buo~~oje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Gating'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kati Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks`; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover`; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady`; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean ; 'Rob McWhorter '; rob.g.dragnich@exxorunobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman ; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Teri Arion'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:dio23-002.pdf;Weatherford generation 2.0 Multiphase Metering AA.pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 10/30/2008 Mary Jones ~ David McCaleb ~ Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Mark Wedman Schlumberger 200 North 3rd Street, #1202 Halliburton Drilling and Measurements Boise, ID 83702 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Baker Oil Tools Ivan Gillian Land Department 4730 Business Park Blvd., #44 9649 Musket BeII Cr.#5 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99507 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla Richard Wagner Cliff Burglin 399 West Riverview Avenue PO Box 60868 PO Box 70131 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl North Slope Borough K&K Recycling Inc. PO Box 69 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 /~3~/ ~ /`~ __ . • • - ,; ~_ ~ ..; -.-~ 7 ~ ~ ~ -. ~ , SARAH PALIN, GOVERNOR L~Lt~-7~ Di1j ~ ~ 333 W. 7th AVENUE, SUITE 100 ~T C®1~~+LtRQA-Itlol` ~+®~IIS5IOl` -7L l~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CORRECTED ADMINISTRATIVE APPROVAL CO 559.008 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.006 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.004 All other Prudhoe Bay Field Oil Pools ADMINISTRATIVE APPROVAL CO 548.004 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.006 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.004 All Northstar Pools ADMINISTRATIVE APPROVAL CO 402A.004 Badami Oil Pool Approval of Use of Weatherford Generation 2.0 Multiphase Metering Systems for Production Well Testing and Allocation within BPXA Operated Oil Fields Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: The Commission has corrected the Administrative Approval to reflect the correct quality assurance plan due date to January 15, 2009. By application dated July 8, 2008, and received on July 16, 2008, BP Exploration (Alaska), Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (Commission) grant approval to use the Weatherford Generation 2.0 Multiphase Metering System (Gen 2) for production well testing and allocation within BPXA operated oil fields. By e-mail dated October 9, 2008, BPXA stated that it intends to use the Gen 2 only for production well testing and allocation where the production characteristics are similar to those of the PBU Drill Pads V (V- Pad) and E (E-Pad) wells where the Gen 2 was field tested. BPXA requested- quick approval, particularly so that it can deploy the Gen 2 at V-Pad and DS-1 to replace the well pad separators there. In accordance with 20 AAC 25.230(a), the Commission GRANTS BPXA's request to use the Gen 2 for production well testing and allocation within the oil pools noted for wells with similar production characteristics as those where the Gen 2 was field tested, subject to conditions set out in this order. Commission Authority AS 31.05.030(d)(6) and 20 AAC 25.230 authorize the Commission to approve the methodology and equipment utilized for production well testing and allocation. Because no standards and few guidelines exist for multiphase flow meters (MPFMs), the Commission developed "Guidelines Gordon Pospisil • r Technology & Resource Manager November 3, 2008 Page 2 of 10 for Qualification of Multiphase Metering Systems for Well Testing" (Guidelines) to aid operators in preparing applications for approval to use MPFMs for well testing and production allocation and to assist the Commission in assessing the performance of MPFMs.i On February 11, 2005, the CorYUnission issued orders for all North Slope oil pools requiring that for purposes of satisfyiz~.g well-test measurement requirements of 20 AAC 25.230, the use of MFFMs will be approved only in accardance with the provisions of the Guidelines. The Commission may administratively waive a requirement of the Guidelines or administratively amend the Guidelines as long as the change does not promote waste or jeopardize correlative rights and is based on sound engineering and geoscience principles. NotificaN°n BPXA sent the application to all working interest owners and royalty owners (i. e., the Alaska Department of Natural Resources, Division of Oil and Gas (DOG) and U.S. Mineral Management Services (MMS)) of BPXA operated fields; BPXA also sent the application to the Alaska Department of Revenue (DOR). On August 11, 2008, BPXA presented a technical overview of laboratory and field-testing results of the Gen 2 to the Commission, DOG, DOR, and MMS. ,. Additional Information and CIarifications BPXA provided additional data concerning the field trials (in a-mails dated September'11, 2008, from Jerry Brady and dated October 13, 2008, from Andrew Hall) in response to questions from Jane Williamson (a Commission reservoir engineer). Asencies DOG, DOR, and MMS do not object to the use of the Gen 2 as lon~ as it is used only for production well testing and allocation: i. e., not to replace LACT meters. Also, DOG and MMS noted that separate approvals are required for the installation of MPFMs in areas under their jurisdictions. MMS ~,=~agcsts thQ A.OGCC ;~r BPXA develop a quality assurance program by which these meter systems are evaluated for accuracy and reliability and that this information be reported to the AOGCC on a reasonable schedule. DOR wants to be informed of any changes in use or approval of BPXA's measurement systems. Findin s The Gen 2 is an in-line MPFM consisting of four principal components: anear-infrared water- cut monitor (Red-Eye 2G); a Cs 137 gamma densitometer; a passive sonar volumetric flow meter; and a venturi nozzle differential pressure flow meter. The principles of the Gen 2 measurement and~rate determination are described in the application. A significant amount of lab and field testing was conducted. Loop tests showed less than ~5% uncertainties in the measurements of the gas rate, liquid rate and water-cut for individual components of the Gen 2. 1 The Guidelines and Commission's accompanying "Principles of Multiphase Measurements" are on the Commission's Web site: h :/,www.state.ak.us/local/ak a6esIADMIN/o6c/1~leterGuideshtuil. z See Letter from Kevin R. Banks, Acting Director, DOG, to Daniel Seamount, Jr., Chair, Commission (Oct. 3, 2008); letter from Jonathan Iversen, Director, DOR Tax Division, to Seamount (Oct. 7, 2008); letter from Jeffrey Walker, Alaska Regional Supervisor, MMS, to Seamount (Sept. 30, 2008). • , Gordon Pospisil Technology & Resource Manager November 3, 2008 Page 3 of 10 V-Pad field trials -liquid-dominated regime, high gas-volume fraction (GVF)3, gas-lifted wells (see Figures 1-5) Field tests were conducted at V-Pad with the Gen 2 in series with a portable gravity separator system (ASRC Unit 1), which was used as the reference for measurements. Tests were also conducted with the V-Pad separator. The ASRC Unit 1 was manned throughout the test; the unit has been extensively used in BPXA production testing. The meters and the metering devices were recently calibrated for this field trial. No problems with the performance of the ASRC Unit 1 were noted in the application. The wells at V-Pad produce from the Borealis (Kuparuk Formation), Orion (Schrader Formation), and Prudhoe Bay (Sadlerochit Formation) Oil Pools. Total fluid (oil and water) rates ranged from 300 barrels per day (BPD) to 3,200 BPD; water-cut rates ranged from 0%- 96%. The wells are gas lifted and gas-volume fractions ranged from 85% to 98%. Fluid viscosities ranged from 1.4 centipoise to 653 centipoise. Major findings V-Pad field trials • Compared to the ASRC Unit 1 separator, the Gen 2 measurement uncertainties were within f7% for the gas rate and f8% for the liquid rate. The ASRC Unit 1 estimated uncertainties are f3% for the gas rate and ~5% for the liquid rate. No noticeable bias was seen. The fluid rates did not appear to be affected by the water-cut or GVF. • Compared to the ASRC Unit 1 separator, the Gen 2 water-cut uncertainty was within ~5%. The ASRC Unit 1 estimated water-cut uncertainty was f2%. When the ASRC Unit 1 water- cut measurements exceeded 60%, the Gen 2 tended to over-read the water-cut. Gen 2 water- cuts exceeded those of the ASRC Unit 1 by more than 10% in only two well tests, however. Further investigation of the Gen 2 water-cut measurement performance in the mid to high water-cut rars~ may be warran~ed. The Lien 2 performed well in measuring the Schrader Formation well production with high viscosity (i. e., up to 632 cp}. Additional testing of highly viscous, high water-cut fluids is recommended to verify performance for all ranges of Schrader Formation well operating conditions. • The performance of the Gen 2 was better than that of the existing V-Pad separator throughout the range of well operating conditions. Major Findings E_Pad field trials -wet-gas regime (see Figures 6-8) • The results of the tests of a wet-gas meter (with the same basic technology as the Gen 2 (excluding the densitometer device)) and a reference gravity-based separator were compared. The field test showed gas rates within f5%. Liquid rates were within f10% (excluding data from a few bad tests). Gas-oil measurements were within ~5%. Water-cut measurements were not reported in the material BPXA provided. • The results compared as well or better than those of the loop tests. s The GVF is the gas-volume flow rate, relative to the multiphase volume flow rate, at the pressure and temperature prevailing in that section. The GVF is normally expressed as a percentage. See Appendix 2 of "Principles of Multiphase Measurements" at htt ://www.state.ak.us/local/ak aQes/ADMIN/oQc/MeterGuide.shtml. Gordon Pospisil Technology & Resource Manager November 3, 2008 Page 4 of 10 Applicability of the Gen 2 for well testing in BPXA operated fields V-Pad installation The Gen 2 performance was superior to that of the V-Pad separator through the full range of flow rates and water-cuts. Using the Gen 2 should result in better overall production allocation for this pad. Additional performance testing when water-cut exceeds 60% is recommended. DS-1 proposed installation The flow rates of DS-1 wells range from about 400-13,000 BPD total liquid, including 400-1,100 stock tank barrels per day (STB/D) of oil. The gas-liquid ratios range from 12 million - 100 million standard cubic feet per stock tank barrel (MMscf/STB) and water-cuts range from 0%- 95%. Many of these wells are cycled producers. The gas-oil ratio (GOR) increases within a few days of bringing a well on line; within a few days, it exceeds the marginal GOR of the plant. The Gen 2 may aid in providing more frequent testing to determine whether the well GOR is too high to continue flow. However, the production characteristics may be out of the range of current Gen 2 testing. BPXA needs to update the Commission on the Gen 2's performance at DS-1. Installation at other BPXA pads Based upon the information BPXA supplied, the Commission anticipates measurements better than f10% uncertainty for most wells in BPXA fields. The Gen 2 flow-rate uncertainties are within the range of uncertainties for gravity-based separation devices as shown by monthly allocation reports filed with the Commission, DOG, and DOR. The Gen 2 flow-rate uncertainties are probably sufficiently accurate for reservoir management purposes, particularly if there are more frequent well tests. The Gen 2 performance, however, needs to be evaluated in more extreme conditions (such as in the proposed DS-1 installation and in pads with higher viscosity and higher water-cut Schrader Formation wells). Conclusions 1. BPXA's application meets the requirements of 20 AAC 25.230(a) and the Guidelines for use of MPFMs for production well testing and allocation. 2. The anticipated accuracy exceeds f 10 % for wells within the range of conditions tested. This accuracy is suitable for well testing and allocation for reservoir management purposes. 3. During the trials, the performance of the Gen 2 was superior to that of the V-Pad test separator. 4. Additional testing of the Gen 2 is warranted for wells with high water-cut and highly viscous flows. 5. Information from the DS-1 testing will expand the envelope of test information available for determining the applicability of the Gen 2. 6. Continued testing of the Gen 2 will advance MPFM technology and aid BPXA in reservoir surveillance and management. 7. Through periodic performance reviews, the Commission can ensure that the Gen 2s are performing as expected. Gordon Pospisil Technology & Resource Manager November 3, 2008 Page 5 of 10 8. None of the affected agencies object to the use of the Gen 2 as long it will be used only for well testing and production allocation: i. e., not to replace LACT meters. 9. Separate approvals are required for the installation of Gen 2s in areas under the jurisdiction of DOG or MMS or both. 10. The use of the Gen 2 for well testing and production allocation in existing BPXA fields is not expected to promote waste or jeopardize correlative rights. Order In accordance with 20 AAC 25.230(a), the Commission GRANTS BPXA's request to use the Weatherford Generation 2.0 Multiphase Metering System for production well testing and allocation within BPXA operated oil fields where the production characteristics are similar to those of the V-Pad and E-Pad wells where the Gen 2 was field tested. Specifically, installations at PBU V-Pad and PBU DS 1 are approved. This approval is conditioned upon the following: 1. the Gen 2 shall not replace Lease Automatic Custody Transfer meters; 2. production allocation methods shall remain unchanged unless changed by order of the Commission; 3. factory acceptance tests, field maintenance, periodic calibration, and fluid sampling must be performed in accordance with BPXA's application; 4. BPXA must notify the Commission before installing the Gen 2 at any BPXA site; 5. BPXA must conduct yearly status meetings by September 30 of each year detailing the installations to date, the performance of each Gen 2, all operational issues relating to the Gen 2, and any additional Gen 2-related test results. Thorough summaries of this information shall be included in the annual surveillance reports filed with the Commission by BPXA for the individual pools; 6. BPXA must submit to the Commission a detailed plan of a long-term quality assurance program by January 15, 2009; 7. if the Gen 2 does not perform to the Commission's satisfaction, BPXA must correct the problems or redeploy the existing pad separators; 8. all notices, reports, and other submissions BPXA is required to make to the Commission under this order must, at the time of the submission to the Commission, be provided to all affected working interest and royalty owners and DOR. Gordon Pospisil • • Technology & Resource Manager November 3, 2008 Page 6 of 10 9. upon proper application, or its own motion, and unless notice and public hearing is required, the Commission may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated November 3, 2C Daniel T eamount, Jr. Cathy . Foerster Chair Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration aze FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(6), "[t]he questions reviewed on appeal aze limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. V~~iiilsr, ~~Q`~ililt[j ~ • 1~cGTC1©[csgy &c t~.~;~~~u~cc, i~1~i;-~a,:;~~ I~~eF~ern~F'ser 3, ~GD~k~ E~age 7 aG ~ Q~ 2500 2000 1500 1000 500 Attachments Figure 1 Cosnpaiison Rif Tests -Liquid Rate ;STB/D vs Unit 1 Liquid Rate, STBlD Gen 2, V-WPS O O ------- -----~----.._.. _F --._-_-. - ------ ---~ / -~. ---- - / /' -- i j ' ---- ~: i~^ " ~ - ~ Gent (~ - --- - - - - -- --- ~------ - - ~ - - - - - ;------- --- Sadlerochit ^ Gen 2 Kuparuk ------- - ---- -- -~, % ~ Gen 2 Schra er ~. •~ ~'~ -- -- ------ - -~ ~ V-WPS -/.''' -- -- - --- ----- ----- --- Sadlerochit ® V-WPS Kuparuk -~- - - % -- ---=--- - a - - ---1------ - i - V-WPS Schrader ' / p 4000 - 3000 ~ 2000 1000 0 - 0 500 1000 1500 2000 2500 Unit 1 Liquid STB/D Figure 2 Comparison All Tests -Gas Rate, Mscfd to Unit 1 Gas Rate Gen 2, V-WPS ---- ---- - - s ~ ' - --- ---. - ------ -- . , ! 10 ° - ~ , ~ , ---- --- _. - _ -------- ---- , - ---- ~-~r ---- - ~ Gen2Sadlerochit 1 ---- - --- - - __ ~~ --- - -- - -- ® Gen 2 Kuparuk - - - --- ---- -- -= ~ - '-- - --- --- -- - - - -- - - e Gen 2 Schrader - - - ,--- _- ~~ d~ V-WPS Sadlerochit ' = ' = -- ^ V-WPS Kuparuk ---- -- -- _ _ _ ----- -- ~ - . ; -.._- f --- -- ------ ____- - --- -- - ----- -, - - - ---- - --- ~, V-WPS Schrader 1000 2000 3000 4000 Unit 1 Gas Rate, NYscfd STB/D i~ordar~ Puspi~i'~ Technology & Rescsurce wianager November 3, 2008 Page 8 of 10 • Figure 3 Comparison All Tests Water Cut v, Unit 1 Water Cut Gen 2, V-WPS 100% 80% e 60% U ~+ 40% 20% 60% 40% 20% 0% O LL N -20% -40% -60% 0% 0% 0% ~~ ^ - - ~ ,: ~--- _ - -- ---~ - - - ---------------- ---- -- - --- - ~ i i" --- --- -----. -- - --- a~ - --- - ,. ~ ,. --- -.---- ----------__-_-- _-_-__ - - ^--~'-- -- • Gen 2 Sadlerocl • ' ~I ^ Gen 2 Kuparuk --_ - --_- - - --- - • ~~ ' • Gen 2 Schrader . • --- --- --- _ - - --- - ~ ~ E. V-WPS Sadler ~ _ - -~ - --- - -- -, ~ V-WPS Kuparu -- _- .• ^ i o ° 20% 40% 60 /0 80 0 Unit 1 Water Cut, ochit 'i k ~~ er li 100% Figure 4 Comparison All Tests % Error Flow Rate vs Unit 1 Water Cut Gen 2, V-WPS ~~, - - ~ +!- 10% ' ~ ~ j ~~- 2 G _ _ - - - en i • hit ~ --- - i T Sadleroc i- -- --- ----~- ~ -----T--- - - --- ---f--- -- ^ Gen 2 -- Kuparuk i- - _-- - ---- - ~ ~ ~ • Gent -- - ~' - ~ Schrader - ---- -- - ,---- - - - - - -- - f --- - _ --- --- - --- ----- -- ^ F--- - - --- ----- - _--- --~. - - ~' - -~------- _~~ - _~----- - -_-~-~-r.-~- I ~ - __ _ - -- L-- -- ~ _ _ __ 20% 40% 60% 80% 100% Unit 1 Water Cut, • ~ ~~~o~~ ~~~~~u 'R`e,~:~t~TO~cngy Sz, [~cs~ear~ce R~iana~;ei l~c~urerr~6er 3, 2~D~ )~,g~ 9 csG) ~ Fib GoPnparison All Tests % Error Flow Rate Vs Unit 1 Gas o/®lurr~e Fraction Gen 2, iOmV@~PS ~~ -60% 80% 60% ~ --- --- --'- - - - - _ _ - --- i- i _ --- 40°io ~ '~- Gen 2 Sadlerochit ____;-____- -- ~ _. ^ Gen 2 Kuparuk - -- - -------------- - ----------- - ` ° I_ _ ~ Gen 2 Schrader __ _ ~_ __-_------- -- ---- 20 /o jl _ ~ -- - - E---~---- ___, _~ $ -~t~ ----- -- -- ----------- ----- o ,_-- --- ---- - - ---' --- ---- N -----------' ----------'-~---- f--------------- -- ----'----------. ~ -20% --- --- - --------------------- --- ---------- --- ~0% - -------- ___ _ _ t -------- _: _- --- ---- -- T-_-- ----- -:------ --- 90% Gas-Volume r~.:^-~nn (GVF) % Fi~are 6 5 0 0 100% 5 t0 15 20 Zg ov ~~ ~- Test separator gas flowrate (flNlWscf/d) Cx~~l•~la~l, t'~~~pa,5il Technology & Resource Mal~ageo November 3, 2008 Page l0 of 10 Figure 7 lzoo v' 1000 r 800 O Q 600 K D U 400 or C O U j 200 0 ~ i All these points _ within t10% ~~ j O~ ~ " O ~ unreliable /low Ipuid ,~ rate from test separator ~ ~' ~ V-wne transmitter - - - O suspected out of -O -- .. ratga _ O V-cone transmitter Liquid rata verified O ~ certainly out of with ASRC Obit 1 range 0 200 400 600 800 Test separator liquid flowrate (stbld) Figure 8 looooo soooo a a 70000 v M O 60000 .~~ D U 40000 m O 30000 U 20000 10()V -b~ • o Wcone trangmider gUSplcted out Ot fenge i 0 o. j i:= 0 10000 0 :woo 1 LUU 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 Test separator GOR (scflbbl) • ~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, November 03, 2008 3:19 PM Subject: Corrected Multiphase Metering AA.pdf -Adobe Acrobat Professional Attachments: Corrected Multiphase Metering AA.pdf BCC:'Aaron Gluzman'; caunderwood@marathonoil.com; 'Dale Hoffman'; Fridiric Grenier; Jason Brink; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; 'Sandra Lemke'; 'Scott Nash'; Sherry Corley; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; 'Aleutians East Borough'; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece ; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Teri Arion'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:Corrected Multiphase Metering AA.pdf; 11/3/2008 ! i Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Mark Wedman Schlumberger 200 North 3rd Street, #1202 Halliburton Drilling and Measurements Boise, ID 83702 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Baker Oil Tools Ivan Gillian Land Department 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99507 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508-4336 .Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla Richard Wagner Cliff Burglin 399 West Riverview Avenue PO Box 60868 PO Box 70131 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow. AK 99723 f /~ /Z~ r``~~l / / ~'~( / ,~ /, r f /-~f~ • ~~ a o a o 0 SARAH PALIN, GOVERNOR ALASSA OIL AI~TD GA5 333 W. 7th AVENUE, SUITE 100 C01~5D' RQATIOI~T COMNII55IO1~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 550.007 All Milne Point Pools Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: By letter dated May 13, 2008, BP Exploration (Alaska), Inc. (BPXA) submitted a report to the Alaska Oil and Gas Conservation Commission (Commission) providing the results of field tests of a portable Arctic Slope Regional Corporation (ASRC) Unit 5 (Unit 5) FMC Technologies Enhanced Multiphase System (EMSTM) to measure well production;' the field testing was conducted within the Milne Point Field. BPXA states that, "[u]nder the Guidelines, this qualifies use of ASRC Unit 5 (`Unit 5') at Milne Point Field (Conservation Order 550 (`CO 550')) for production allocation well testing." On December 18, 2008, BPXA advised AOGCC that BPXA does not intend to use the Unit 5 MPFM outside the Milne Point Field. The Commission agrees that the report and supplemental information BPXA supplied provide a sufficient basis on which to determine that using the Unit 5 EMSTM for production well testing and allocation for wells within the Milne Point Field is appropriate. Accordingly, under 20 AAC 25.230(a), BPXA's use of the Unit 5 EMSTM for production well testing and allocation in all Milne Point Field oil pools is GRANTED, subject to the conditions set out in this administrative approval. Commission Authority The Commission reviews requests to use multiphase flow meters (MPFMs) for production well testing and allocation under AS 31.05.030(d)(6) and 20 AAC 25.230(a). The Commission developed "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" (Guidelines), dated November 30, 2004, to aid operators in preparing applications for approval to use MPFMs for well testing and production allocation and assist the Commission in assessing the performance of MPFMs? On February 11, 2005, the Commission issued orders for all North Slope oil pools providing that, for purposes of satisfying the well test measurement requirements of 20 AAC 25.230(a), the use of MPFMs will be approved only in accordance with the provisions of the Guidelines. 3 t The EMSTM is comprised of a venturi meter and capacitance and conductance electrodes coupled with a cyclonic pre-separator allowing partial separation and metering of gas in high gas volume fraction wells. z The Guidelines' expiration was extended to December 31, 2009 so that the Guidelines can be used to evaluate BPXA's final reports. See Administrative Approvals CO 559.007, CO 570.005, CO 548.003, CO 550.003, CO 547.003, CO 551.003, CO 402A.003. s See Administrative Approvals CO 547, CO 548, CO 549, CO 550, CO 551, and CO 552. The Commission established similar rules in CO 402A.001 and the pool rules for the Raven Oil Pool (CO 570) and Put River Oil Pool (CO 559). Administrative Approval CO 5007 Page 2 of 4 December 30, 2008 Conservation Order Administrative Approvals Application. By application, dated August 30, 2006, BPXA requested approval to use a portable MPFM system for production well testing and allocation in the Prudhoe Bay, Endicott, Milne Point and Northstar Fields. Notification. Notice of a tentatively scheduled public hearing on BPXA's application was published in the ANCHORAGE DAILY NEWS on September 22, 2006. The Commission received no protest or request for a hearing. The public hearing was cancelled. Technical Basis of Request. BPXA proposed using Unit 5 EMSTM to supplement portable test separator units used for production allocation testing and flowback jobs on new production wells and after well work. The metering system includes a FMC Technologies Enhanced Multiphase System (EMSTM) comprised of a venturi meter and capacitance/conductance electrodes coupled with a cyclonic pre- separator allowing partial separation and metering of gas in high gas volume fraction wells. The technical and operating aspects of the system are fully described in BPXA's August 30, 2006 application. The controlled loop testing and short field trials performed in the Prudhoe Bay Unit in 2005 indicate that the accuracy of the FMC MPFM (without the cyclonic gas-liquid separator) is satisfactory for production well testing and allocation purposes so long as the MPFM is operated in accordance with BPXA's application. Information from loop tests suggests uncertainties in fluid rates of +/-6%. Findings BPXA conducted several qualification tests of the Unit 5 MPFM: it compared the results of the Unit 5 MPFM with the results of an established gravity test separator measurement system (ASRC Unit 1). The cyclonic gas-liquid separator of the Unit 5 EMSTM was not utilized as the gas-liquid ratios of wells in the Milne Point Field are low. Unit 5 MPFM watercut measurements were compared with watercut measurements obtained from fluid sampling. An initial test campaign was conducted to assess hardware and train the crew operating the Unit 5 MPFM. Total fluid rates were verified with tank strapping tests to determine the uncertainty of total liquid measurements of the Unit 5 MPFM and the ASRC Unit 1 reference separator system. Well test data were used to make modifications to hardware and procedures for fluid sampling and fluid property information input to the MPFM software. A second series of tests conducted at Milne Point in December 2007, assessed whether the modifications to the Unit 5 MPFM hardware, software and procedures were effective. Additional testing was performed to determine the cause of watercut discrepancies. Incorrect fluid. property input, including fluid density, conductivity, and permittivity data, was determined to be the major cause of the discrepancies. A specific test protocol was developed, and the Unit 5 crew received extensive training in collecting and entering fluid data, spot checking, and downloading and archiving raw data. Using updated fluid properties derived from this test protocol, the raw data files from selected earlier well tests were reprocessed. The tests show that, as compared to the ASRC Unit 1, the Unit 5 MPFM measures total liquid volume within t10%, with a watercut uncertainty band of about f2.5-5%. A comparison of ASRC Unit 1 and Unit 5 MPFM gas measurements shows greater scatter with the Unit 5 MPFM, particularly at very low gas-liquid ratios (GLRs) and high watercut values. Whether there is a problem in the performance of the Unit 5 MPFM or ASRC Unit 1 is unclear. Gas volume measurements of the ASRC Unit 1 appear low for many tests: the calculated gas-oil ratio (GOR) was lower than the expected solution GOR of the oil in many tests. Administrative Approval CO 007 Page 3 of 4 December 30, 2008 The GLRs of Milne Point produced fluids are relatively low compared with the GLRs of produced fluids of other North Slope fields. The uncertainties in the gas rates do not affect the oil production allocation. BPXA states in its report that "revisions implemented in Unit 5 software are expected to improve consistency of liquid and gas rate measurement." Conclusions 1. As demonstrated by the report of the field testing of the Unit 5 MPFM and related. information BPXA submitted, BPXA's application to use the Unit 5 MPFM for production well testing and allocation in the Milne Point Field meets the requirements of 20 AAC 25.230(a) and the Guidelines for use of MPFMs for production well testing and allocation. 2. A public notice, noting an opportunity for a hearing, was published regarding BPXA's application; no protest or request for a hearing was received. 3. BPXA has met the requirements, set out in the initial approval (CO 550.001 (Amended)), for field qualification of the Unit 5 MPFM within the Milne Point Field. 4. The uncertainty in measurements from the Unit 5 MPFM-i.e., when compared to the ASRC Unit 1-was within f10% for total fluid volume and about f2.5-5% for watercut. In the context of well testing and allocation within the Milne Point Field, this extent of uncertainty is acceptable. 5. Greater uncertainty was apparent in gas measurements, but whether the Unit 5 MPFM measurements were in error is not apparent. As the Milne Point wells have relatively low total gas-liquid ratios, the uncertainty in gas measurements is not a significant issue for oil production well testing and allocation. 6. BPXA does not seek approval to use the Unit 5 MPFM in other BPXA operated fields. Separate approvals to use the Unit 5 MPFM in those fields would be required. Also, approval of the use of the Unit 5 MPFM in pools with higher GLRs will depend on additional evidence of the adequacy of the device's performance. 7. BPXA did not provide results of the performance of the cyclonic gas-liquid separator of the Unit 5 EMSTM 8. The Commission can be kept apprised of the continued performance and operability of the Unit 5 MPFM and of production allocation results through yearly updates in the annual surveillance reports for the Milne Point Field pools. 9. The use of the Unit 5 MPFM for production well testing and allocation in the Milne Point Field is not expected to promote waste or jeopardize correlative rights. Order The Commission GRANTS BPXA's request to use the Unit 5 MPFM for production well testing and allocation within the Milne Point Field. This approval is conditioned upon the following: 1. Factory acceptance tests, field maintenance, periodic calibration, and fluid sampling must be performed in accordance with BPXA's August 30, 2006 application and May 13, 2008 field test documentation. 2. By April 1 of each year beginning in 2009, the operator must provide, for the prior calendar year, a summary of performance and operational issues relating to the Unit 5 MPFM and, for each Milne Point Field pool, include the monthly oil, gas and water allocation factors. The summary of Unit 5 performance and operational issues and the monthly allocation factors may be included in the annual surveillance reports required for the oil pools. 3. The operator must ensure proper production well testing and allocation of production among the wells and pools. Administrative Approval CO 007 Page 4 of 4 December 30, 2008 4. The Commission may require additional information to ensure that the production well tests and allocations are accurate. 5. The use of the cyclonic gas-liquid separator of the Unit 5 EMSTM is not approved for well test allocation purposes without the approval of the Commission. 6. Unless notice and public hearing are required, upon proper application or its own motion, the Commission may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. t;`~ ENTERED at Anchorage, Alaska, and dated December 30, 2008. ~~; Daniel T. Seamount, Jr. Chair ~~ ~{ ~. x r . ~~ ~ ~ t C - c~`"X Cat y P. oerster "``~t x Commt stoner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." \~L In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 • • David McCaleb Cindi Walker IHS Energy Group Tesoro Refining and Marketing Co. GEPS Supply & Distribution 5333 Westheimer, Ste 100 300 Concord Plaza Drive Houston, TX 77056 San Antonio, TX 78216 Jerry Hodgden Richard Neahring Hodgden Oil Company NRG Associates 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Schlumberger Ciri Drilling and Measurements Land Department 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith PO Box 190083 PO Box 39309 Anchorage, AK 99519 Ninilchick, AK 99639 Kenai National Wildlife Refuge Penny Vadla Refuge Manager 399 West Riverview Avenue PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 /~~~c1 /~~3ied • • Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, December 30, 2008 3:36 PM Subject: co550-007 Milne Point Attachments: co550-007.pdf BCC:Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA); 'Aleutians East Borough'; 'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Greg Moore'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac ; 'Mark P. Worcester'; 'Marquerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick ; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR) Attachments:co550-007.pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 12/30/2008 °' ~? ~ ~ ~ ~ VERNOR ~ O SARAH PALIN, GO ~.._ ALAS OIL Al`D ~ 333 W. 7th AVENUE, SUITE 100 COI~TSERQATION C011II1II551O1~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CORRECTED ADMINISTRATIVE APPROVAL CO 550.007 All Milne Point Pools Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: Administrative Approval Conservation Order (CO) 550.007, issued on December 30, 2008, was based upon the understanding that the gas-liquid cyclonic separator was not used during the field trials of the FMC Technologies Enhanced Multiphase System (EMSTM), and therefore, the use of the cyclonic separator was not approved. Consultants to BP Exploration Alaska, Inc. (BPXA) informed the Alaska Oil and Gas Conservation Commission (Commission), by e-mails dated January 2, 2008, that the cyclonic separator was in operation through all testing of the EMSTM. Accordingly, this corrected order eliminates the statements that the cyclonic separator was not used and approves the use of the cyclonic separator. However, BPXA is required to report on the performance of the cyclonic separator during the field. test trials. By letter dated May 13, 2008, BPXA submitted a report to the Commission providing the results of field tests of a portable Arctic Slope Regional Corporation (ASRC) Unit 5 (Unit 5) FMC EMSTM to measure well production; the field testing was conducted within the Milne Point Field. BPXA states that, "[u]nder the Guidelines, this qualifies use of ASRC Unit 5 (`Unit 5') at Milne Point Field CO 550 for production allocation well testing." On December 18, 2008, BPXA advised AOGCC that BPXA does not intend to use the Unit 5 MPFM outside the Milne Point Field. The Commission agrees that the report and supplemental information BPXA supplied provide a sufficient basis on which to determine that using the Unit 5 EMSTM for production well testing and allocation for wells within the Milne Point Field is appropriate. Accordingly, under 20 AAC 25.230(a), BPXA's use of the Unit 5 EMSTM for production well testing and allocation in all Milne Point Field oil pools is GRANTED, subject to the conditions set out in this administrative approval. Commission Authority The Commission reviews requests to use multiphase flow meters (MPFMs) for production well testing and allocation under AS 31.05.030(d)(6) and 20 AAC 25.230(a). The Commission developed "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" (Guidelines), dated November 30, 2004, to aid operators in preparing applications for approval to use MPFMs for well testing and production allocation and assist the Commission in assessing the performance of MPFMs' On February 11, 2005, the Commission issued orders for all North Slope oil pools providing that, for ' The Guidelines' expiration was extended to December 31, 2009 so that the Guidelines can be used to evaluate BPXA's final reports. See Administrative Approvals CO 559.007, CO 570.005, CO 548.003, CO 550.003, CO 547.003, CO 551.003, CO 402A.003. Administrative Approval CO 007 Page 2 of 4 January 6, 2009 purposes of satisfying the well test measurement requirements of 20 AAC 25.230(a), the use of MPFMs will be approved only in accordance with the provisions of the Guidelines. ' Conservation Order Administrative Approvals Application. By application, dated August 30, 2006, BPXA requested approval to use a portable MPFM system for production well testing and allocation in the Prudhoe Bay, Endicott, Milne Point and Northstar Fields. Notification. Notice of a tentatively scheduled public hearing on BPXA's application was published in the ANCHORAGE DAILY NEWS on September 22, 2006. The Commission received no protest or request for a hearing. The public hearing was cancelled. Technical Basis of Request. BPXA proposed using Unit 5 EMSTM to supplement portable test separator units used for production allocation testing and flowback jobs on new production wells and after well work. The metering system includes a FMC Technologies Enhanced Multiphase System (EMSTM) comprised of a venturi meter and capacitance and conductance electrodes coupled with agas-liquid cyclonic separator allowing partial separation and metering of gas in high gas volume fraction wells. The cyclonic separator was in operation through all testing of the EMSTM; however, performance of the cyclonic separator during the field trials was not reported. The technical and operating aspects of the system are fully described in BPXA's August 30, 2006 application. The controlled loop testing and short field trials performed in the Prudhoe Bay Unit in 2005 indicate that the accuracy of the FMC MPFM (without the cyclonic gas-liquid separator) is satisfactory for production well testing and allocation purposes so long as the MPFM is operated in accordance with BPXA's application. Information from loop tests suggests uncertainties in fluid rates of +/-6%. Findings BPXA conducted several qualification tests of the Unit 5 MPFM: it compared the results of the Unit 5 MPFM with the results of an established gravity test separator measurement system (ASRC Unit 1). Unit 5 MPFM watercut measurements were compared with watercut measurements obtained from fluid sampling. An initial test campaign was conducted to assess hardware and train the crew operating the Unit 5 MPFM. Total fluid rates were verified with tank strapping tests to determine the uncertainty of total liquid measurements of the Unit 5 MPFM and the ASRC Unit 1 reference separator system. Well test data were used to make modifications to hardware and procedures for fluid sampling and fluid property information input to the MPFM software. A second series of tests conducted at Milne Point in December 2007, assessed whether the modifications to the Unit 5 MPFM hardware, software and procedures were effective. Additional testing was performed to determine the cause of watercut discrepancies. Incorrect fluid property input, including fluid density, conductivity, and permittivity data, was determined to be the major cause of the discrepancies. A specific test protocol was developed, and the Unit 5 crew received extensive training in collecting and entering fluid data, spot checking, and downloading and archiving raw data. Using updated fluid properties derived from this test protocol, the raw data files from selected earlier well tests were reprocessed. The tests show that, as compared to the ASRC Unit 1, the Unit 5 MPFM measures total liquid volume within f10%, with a watercut uncertainty band of about f2.5-5%. ~ See Administrative Approvals CO 547, CO 548, CO 549, CO 550, CO 551, and CO 552. The Commission established similar rules in CO 402A.001 and the pool rules for the Raven Oil Pool (CO 570) and Put River Oil Pool (CO 559). Administrative Approval CO 007 Page 3 of 4 January 6, 2009 A comparison of ASRC Unit 1 and Unit 5 MPFM gas measurements shows greater scatter with the Unit 5 MPFM, particularly at very low gas-liquid ratios (GLRs) and high watercut values. Whether there is a problem in the performance of the Unit 5 MPFM or ASRC Unit 1 is unclear. Gas volume measurements of the ASRC Unit 1 appear low for many tests: the calculated gas-oil ratio (GOR) was lower than the expected solution GOR of the oil in many tests. The GLRs of Milne Point produced fluids are relatively low compared with the GLRs of produced fluids of other North Slope fields. The uncertainties in the gas rates do not affect the oil production allocation. BPXA states in its report that "revisions implemented in Unit 5 software are expected to improve consistency of liquid and gas rate measurement." Conclusions 1. As demonstrated by the report of the field testing of the Unit 5 MPFM and related information BPXA submitted, BPXA's application to use the Unit 5 MPFM for production well testing and allocation in the Milne Point Field meets the requirements of 20 AAC 25.230(a) and the Guidelines for use of MPFMs for production well testing and allocation. 2. A public notice, noting an opportunity for a hearing, was published regarding BPXA's application; no protest or request for a hearing was received. 3. BPXA has met the requirements, set out in the initial approval (CO 550.001 (Amended)), for field qualification of the Unit 5 MPFM within the Milne Point Field. 4. The uncertainty in measurements from the Unit 5 MPFM-i. e., when compared to the ASRC Unit 1-was within f10% for total fluid volume and about f2.5-5% for watercut. In the context of well testing and allocation within the Milne Point Field, this extent of uncertainty is acceptable. 5. Greater uncertainty was apparent in gas measurements, but whether the Unit 5 MPFM measurements were in error is not apparent. As the Milne Point wells have relatively low total gas-liquid ratios, the uncertainty in gas measurements is not a significant issue for oil production well testing and allocation. 6. BPXA does not seek approval to use the Unit 5 MPFM in other BPXA operated fields. Separate approvals to use the Unit 5 MPFM in those fields would be required. Also, approval of the use of the Unit 5 MPFM in pools with higher GLRs will depend on additional evidence of the adequacy of the device's performance. 7. Documentation of the gas-liquid cyclonic separator is needed to provide an understanding of its performance and operability over the range of tested GLRs. 8. The Commission can be kept apprised of the continued performance and operability of the Unit 5 MPFM and of production allocation results through yearly updates in the annual surveillance reports for the Milne Point Field pools. 9. The use of the Unit 5 MPFM for production well testing and allocation in the Milne Point Field is not expected to promote waste or jeopardize correlative rights. Order The Commission GRANTS BPXA's request to use the Unit 5 MPFM for production well testing and allocation within the Milne Point Field. This approval is conditioned upon the following: 1. Factory acceptance tests, field maintenance, periodic calibration, and fluid sampling must be performed in accordance with BPXA's August 30, 2006 application and May 13, 2008 field test documentation. Administrative Approval CO 007 Page 4 of 4 January 6, 2009 2. By April 1 of each year beginning in 2009, the operator must provide, for the prior calendar year, a summary of performance and operational issues relating to the Unit 5 MPFM and, for each Milne Point Field pool, include the monthly oil, gas and water allocation factors. The summary of Unit 5 performance and operational issues and the monthly allocation factors may be included in the annual surveillance reports required for the oil pools. 3. The operator must ensure proper production well testing and allocation of production among the wells and pools. 4. By March 31, 2009, BPXA must provide documentation of the performance of the gas-liquid cyclonic separator over the full range of GLRs tested within the field trials. 5. The Commission may require additional information to ensure that the production well tests and allocations are accurate. 6. Unless notice and public hearing are required, upon proper application or its own motion, the Commission may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. ENTERED at Anchorage, Alaska, and dated January 6, 2009. Daniel T. Seamount, Jr. Chair Ca by . Foerster Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Commissioner Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, January 06, 2009 3:00 PM Subject: co 550-007 corrected and aio 2b-0008 cancelled Attachments: aio 2b-008 cancelled.pdf; co 550-007 corrected.pdf BCC:'Aaron Gluzman'; caunderwood@marathonoil.com; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); 'Aleutians East Borough'; 'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje ; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze ; 'Eric Lidj i '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons ; 'Gordon Pospisil'; 'Greg Moore'; 'Gregg Nady'; 'gregory micallef ; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah ; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mktn7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Aian J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:aio 2b-008 cancelled.pdf;co 550-007 corrected.pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 1 /6/2009 • Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geologicai Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 v ~~a'~c~~c~~~~ . , ~~ "~f-~e . , ' . ±~j ..~~.i '\ ' ~ ~~ ~ ' ~ , _.. ~ . ' ia~. ~ +~ 4 ,'g',4 . ., i~ , ___ - ,. : ~ ,~ , e! ~._! ~ ~_~ ~ pt ~5~~ ~~ ~u`L ~ C01~5ERQATIO~T COMI~IIS5101'~ f SARAH PALIN, GOVERNOR ~ s' € 333 W. 7thAVENUE, SUITE 100 ANCHORAGE,ALASKA 99501-3539 J' PHONE (907) 279-1433 x FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 559.009 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.007 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.002 All other oil pools within Prudhoe Bay Field ADMINISTItATIVE APPROVAL CO 548.005 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.008 Alt Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.005 All Northstar Pools ADMINISTRATIVE APPROVAL CO 4028.001 Badami Oil Pool Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: By letter dated Apri127, 2009, BP Exploration (Alaska), Inc. (BPXA) requests authorization to use FMC Technologies System (EMS) multiphase f7owmeter system (EMS MPM systen~) for well testing and allocation in the pools referenced above, subject to certain conditions. BPXA's request is GRANTED wit11 the coiiditions identified below. In 2007, under temporary authorization from the Alaska Oil and Gas Conservation Commission (AOGCC or Commission), BPXA began field trials of the EMS MPM system utilizing tlle Arctic Slope Regional Corporation (ASRC) Unit #5 portable well testing system. The qualifcation testing program occurred in three stages. The first stage occurred at the Prudhoe Bay Unit (PBU) L and E pads and Milne Point Unit (MPU) S and H pads. During this phase, a total of 69 tests were conducted on 23 wells using ASRC Unit #5 to assess I~ardware perfarmance. These tests were undertaken in series with the ASRC Unit #l, a conveiltional portable well tesfing system, and tank strapping tests (to verify the accuracy of both portable metering systems (ASRC Unit #5 and ASRC Unit # 1)). Tl~e results were used to design and implen~ent modifications to the ASRC Unit #5 hardware, fluid data input, and crew trainiilg and testing protocols. The second stage occurred at the MPU I pad, where seven tests were conducted on six wells to evaluate the effectiveness of the modifications made after the first stage. These tests were also done in series with khe ASRC Unit # I . The third stage occurred at the PBU V Pad and MPU B, G, I, J, K, and S pad(s), and involved a total of 99 tests conducted on 64 wells. Four of these well tests were conducted with the ASRC Unit #5 and ASRC Unit #1 in series. The results were compared with historical testing data and water cut samples obtained during this phase of testing. During this stage, special attention was paid to improving fluid property input; equipment and protocol modifications were made. Additio~~al crew training was also provided. Over the course of this qualification testing, the modified EMS MPM system utilized on ASRC Unit #5 was demonstrated to be a reliable system for well testing and production allocation. When compaced with ASRC Unit #1 and historical testing data, ASRC Unit #5 is typically within ] 0% for total liquid rate and within 5% for water cut, wifli no apparent bias toward under- or over-reporting. When operated witl~in ttle limits outlined in BPXA's April 27, 2009 application, the EMS MPM systeul will provide reliable results for well testing and production allocation. Accardingly, BPXA's request to utilize tbe EMS MPM system for well testing and production allocation in the subject pools is GRANTED subject to the following conditioils: 1) tlle system must be operated within the parameters identified ~~ tl~e docu~nent titled "Supplemetal-2 Data for the AOGCC - Report 3/24/09," which was included witl~ BPXA's April 27, 2009, application; 2) changes to the parameters must be approved by the Commission; and 3) use of the EMS MPM system at Northstar Unit must be approved by the Minerals Management Service of the U.S. Department of the nt riar. D N~ at Anchorage, Alaska, a J 2, Dauiel T. Seamount, J~r. Jo1m. . orman Chai~man o m' si-oner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the enYry of this order or decision, or sucli further time as the Commission grants for good cause shown, a perso^ affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filecl. Failure to act on it widiin ]0 days is a de~ial of reconsideration. If the Commission denies reconsrderation, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior couit. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the applicatio~ for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission; and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are lim'rted to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of Che period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. June 23, 2009 Page 2 of 2 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, June 24, 2009 8:10 AM Subject: Various AA's multiphase flow metering Attachments: Various AA's multiphase flow metering.pdf ,'`~~`~. Various AA's multiphase flow m... cc: 'Anna Raff ;'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; Chris Gay; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; Deborah Jones; Decker, Paul L(DNR); 'doug_schultze'; 'Eric Lidji'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.neY; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'Janet D. Platt'; 'jejones'; 'Jerry Brady'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Kristin Elowe'; 'Laura SilliphanY; 'mail=akpratts@acsalaska.neY; 'mail=foms@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; Melanie Brown; 'Michael Nelson'; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Winslow'; Pierce, Sandra M (JPO); Rader, Matthew W(DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; Teresa Imm; 'Terrie Hubble'; Thompson, Nan G(DNR); 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjr1'; Von Gemmingen, Scott E(DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Fr~deric Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff ; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C(DNR); Aubert, Winton G (DOA); Birnbaum, Alan J(LAW); Crisp, John H(DOA); Davies, Stephen F(DOA); Fleckenstein, Robert J(DOA); Foerster, Catherine P(DOA); Grimaldi, Louis R(DOA); Johnson, Elaine M(DOA); Jones, Jeffery B(DOA); Laasch, Linda K(DOA); Mahnken, Christine R(DOA); Maunder, Thomas E(DOA); Mciver, Bren (DOA); McMains, Stephen E(DOA); Noble, Robert C(DOA); Norman, John K(DOA); Okland, Howard D(DOA); Paladijczuk, Tracie L(DOA); Pasqual, Maria (DOA); Regg, James B(DOA); Roby, David S(DOA); Saltmarsh, Arthur C(DOA); Scheve, Charles M(DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. WoRh, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Driliing and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Beil Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna. AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recyciing Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 a~ /~ ~ ~ ~~~ ° ~ ~~ r k ! ~ 2 I ~ e-. ~ = ., } I }~ I ?. ~'" ~ ~ ~ ,~~°~ i s; i 6!~t ~'t ' s` ~~'; a' SARAH PAUN, GOVERNOR ' ~ ~ ' ~,~~~ ~ s E~ ~ % ' c i. 'i..' 6,E S!; ~.z t.~ i~ r~ ~,~5~~ Q~ tii`D ~]ra~7 ?~ 333 W. 7thAVENUE, SUITE 100 COI~SER'QA'~"I~1~ COrIl~IISSI01~ ~~ ANCHORAGE,ALASKA 99501-3539 E~' PHONE (907) 279-1433 ~ FAX (907) 276-7542 CORRECTED ADMINISTRATIVE APPROVAL CO 559.009 Put River Oil Pool AllMINISTRATIVE APPROVAL CO 570.007 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.005 Ali other oil pools within Prudhoe Bay Field ADMINISTRATIVE APPROVAL CO 548.005 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.008 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.005 All Northstar Poots ADMINISTRATIVE APPROVAL CO 402B.001 Badami Oil Pool Gordon Pospisil Technology & Resource Mailager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: The Commission has corrected the Administrative Approval to reflect the correct Admi~listrative Approval number for CO 547. By letter dated Apri127, 2009, BP Exploration (Alaska), Inc. (BPXA) requests authorization to use FMC Technologies System (EMS) multiphase flowmeter system (EMS M:PM system) for well testing and allocation in the pools referenced above, subject to certain conditions. BPXA's request is GRANTED with the conditions identified below. In 2007, under temporary authorization from the Alaska Oil and Gas Conservation Commission (AOGCC or Coinmission), BPXA began field trials of the EMS MPM system utilizing the Arctic Slope Regional Corporation (ASRC) Unit #5 portable well testing system. The qualification testing program occuired in three stages. The first stage occurred at the Prudhoe Bay Unit (PBU) L and E pads and Milne Point Unit (MPU) S and H pads. During this phase, a total of 69 tests were conducted on 23 wells usiilg ASRC Unit #5 to assess hardware performance. Tl~ese tests were undertaken in series with the ASRC Unit #1, a conventional portable well testing system, and tank strapping tests (to verify the accuracy of both portable metering systems (ASRC Unit #5 and ASRC Unit #1)). The results were used to design and implement modifications to the ASRC Unit #5 hardware, fluid data inpuf, and crew training and testing protocols. The second stage occurred at the MPU I pad, where seven tests were conducted on six wells to evaluate the effectiveness of the modifications made after the first stage. Tl~ese tests were also done in series with tl~e ASRC Unit #1. The third stage occurred at the PBU V Pad and MPU B, G, I, J, K, and S pad(s), and involved a total of 99 tests conducted on 64 wells. Four of these well tests were conducted with tne ASRC Unit #5 and ASRC Unit #1 in series. The results were compared with historical testing data and water cut samples obtained during this phase of testii~g. During this stage, special attention was paid to improving fluid property input; equipment and protocol modifications were made. Additional crew training was also provided. Over the course of tl~is qualification testing, the niodified EMS MPM system utilized on ASRC U~iit #5 was demoush~ated to be a reliable system for well testiug and production allocation. Whe~1 compared with ASRC Unit #1 and historical testing data, ASRC Unit #5 is typically within 10% far total liquid rate and within 5% for water cut, witl~ no apparent bias toward under- or over-reporting. When operated within the limits outlined in BPXA's April 27, 2009 application, the EMS MPM systeiii will provide reliable results for well testing and production allocation. Accordingly, BPXA's request to utilize the EMS MPM system for well testing and production alloca.tion in the subject pools is GRANTED subject to the following conditions: 2) 3) the system must be operated within the parameters identified in the document titled "Supplemetal-2 Data for the AOGCC - Report 3/24/09," which was included with BPXA's April 27, 2009, application; changes to the parameters must be approved by the Commission; and use of the EMS MPM system at Noi ar Unit must be approved by the Minerals Service of the U.S. Deparh~ent of e Int rior. DONE at Anchor e Al s a, and dat June 2, 2009. / ~ ~ ~ Daniel T. Seamount, h. J n No a Cathy . Foerster Chairman ommis ~ ner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.0$0(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown; a person affected by it may file with the Commission an apptication for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the appiication for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days afrer the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reco~sideration. As provided in AS 31.05.080(b), "[tJhe questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not incl~ded in the period; the last day of the period is included, uoless it falls on a weekend or state holiday, in which event the eriod runs until 5:00 .m. on the next day that does not fall on a weekend or state holiday. June 24, 2009 Page 2 of 2 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, June 24, 2009 8:10 AM Subject: Various AA's multiphase flow metering Attachments: Various AA's multiphase flow metering.pdf ..~u Various AA's multiphase flow m.., cc: Anna Raff; Barbara F Fullmer; bbritch; Bill Walker; Brad McKim; Brandon Gagnon; Brian Gillespie; Brian Havelock; Brit Lively; Bruce Webb; buonoje; Cammy Taylor; Cande.Brandow; carol smyth; Cary Carrigan; caunderwood@marathonoil.com; Charles O'Donnell; Chris Gay; Cliff Posey; Dan Bross; dapa; Daryl J. Kleppin; David Brown; David Gorney; David House; David L Boelens; David Steingreaber; ddonkel; Deborah Jones; Decker, Paul L (DNR); doug_schultze; Eric Lidji ; Evan Harness; eyancy; foms2@mtaonline.net; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gregg Nady; gspfoff; Hank Alford; Harry Engel; jah; Janet D. Platt; jejones; Jerry Brady; Jerry McCutcheon; Jim Arlington; Jim White; Jim Winegarner; Joe Nicks; John Garing; John S. Haworth; John Spain; John Tower; John W Katz; Jon Goltz; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; knelson@petroleumnews.com; Krissell Crandall; Kristin Dirks; Kristin Elowe; Laura Silliphant; mail=akpratts@acsalaska.net; mail=foms@mtaonline.net; Marilyn Crockett; Mark Dalton; Mark Hanfey; Mark Kovac; Mark P. Worcester; Marquerite kremer; Melanie Brown; Michael Nelson; Mike Bill; Mike Jacobs; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Nick W. Glover; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; Patty Alfaro; Paul Winslow; Pierce, Sandra M(JPO); Rader, Matthew W(DNR); Randall Kanady; Randy L. Skillern; rmclean; Rob McWhorter ; rob.g.dragnich@exxonmobil.com; Robert Campbell; Robert Province; Rudy Brueggeman; Scott Cranswick; Shannon Donnelly; Sharmaine Copeland; Sondra Stewman; Sonja Frankllin; Stan Porhola; stanekj; Steve Lambert; Steve Moothart; Steven R. Rossberg; tablerk; Tamera Sheffield; Temple Davidson; Teresa Imm; Terrie Hubble; Thompson, Nan G(DNR); Tim Lawlor; Todd Durkee; Tony Hopfinger; trmjr1; Von Gemmingen, Scott E (DOR); Walter Featherly; Walter Quay; Wayne Rancier; Aaron Gluzman; Dale Hoffman; Frederic Grenier; Gary Orr; Jerome Eggemeyer; Joe Longo; Lamont Frazer; Marc Kuck; Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; Sandra Lemke; Scott Nash; Steve Virant; Tom Gennings; Willem Vollenbrock; William Van Dyke; Woolf, Wendy C(DNR); Aubert, Winton G(DOA); Birnbaum, Alan J(LAW); Crisp, John H(DOA); Davies, Stephen F(DOA); Fleckenstein, Robert J(DOA); Foerster, Catherine P(DOA); Grimaldi, Louis R(DOA); Johnson, Elaine M(DOA); Jones, Jeffery B(DOA); Laasch, Linda K(DOA); Mahnken, Christine R(DOA); Maunder, Thomas E(DOA); Mclver, Bren (DOA); McMains, Stephen E(DOA); Noble, Robert C(DOA); Norman, John K(DOA); Okland, Howard D(DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B(DOA); Roby, David S(DOA); Saltmarsh, Arthur C(DOA); Scheve, Charles M(DOA); Schwartz, Guy L(DOA); Seamount, Dan T(DOA) Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Suppiy & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 . ~~~~~ `a~ ~ ~ 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska) Inc. to administratively amend CO 550 to including Weatherford Generation 2 (VSRD) yearly status as part of the Annual Surveillance Report and eliminate the requirement for annual status meetings Docket Number: CO-14-004 Order No. CO 550.009 Milne Point Unit All Oil Pools North Slope Borough, Alaska February 13, 2014 By letter dated September 27, 2013, BP Exploration (Alaska) Inc. (BPXA) requested approval to provide in the annual reservoir surveillance report the information currently being presented at the annual status meetings required by condition 5 of Conservation Order (CO) 550.006 and to eliminate the status meetings. BPXA provided several reasons for their request, primarily that: - Weatherford Generation 2 (Gen 2) meter performance is stable and consistent with defined acceptance criteria; - No additional data has been acquired or analyzed beyond what has been presented to the Alaska Oil and Gas Conservation Commission (AOGCC) during past annual meetings; and - Performance of the Gen 2 meters is as expected. The AOGCC agrees that the Gen 2 meters have been performing reliably and as predicted. In the absence of any change in performance of the meters, providing the performance information as a part of the annual reservoir surveillance report will accomplish the same goal as the annual status meetings. The AOGCC reserves the right to call a meeting if the information presented in the annual reservoir surveillance report indicates the need. Condition 9 of CO 550.006 allows administrative amendment of the order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. The AOGCC has determined that the change proposed by BPXA meets that standard. Condition 5 of CO 550.006 is hereby amended to read: BPXA must include a detailed summary of all Gen 2 installations to date, the performance of each Gen 2, all operational issues relating to the Gen 2, and any additional Gen 2-related test results in the annual surveillance report. The AOGCC reserves the right to call a meeting on Gen 2 related issues if it determines one is warranted. Conservation Order 550.009 • February 13, 2014 Page 2 of 2 DONE at Anchorage, Alaska and dated Cathy Vommissioner Foerster /\ Chair, February 13, 2014. Daniel T. Seam6unt, Jr. Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, February 14, 2014 11:17 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody 1 (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Turkington, Jeff A (DOA); Wallace, Chris D (DOA); (michaelj.nelson@conocophillips.com); AKDCWellIntegrityCoordinator; Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker; Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff; Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jerry McCutcheon; Jim White; Jim Winegarner; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester; Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson@petroleumnews.com; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; David Tetta; Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Pollet, Jolie; Richard Garrard; Richard Nehring; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke 0 • Subject: C0550.009 Milne Point Unit Attachments: co550-009.pdf Samantha Carlisle Executive Secretary IT .Alaska Oil and iGas Conservation Commission 333 'West 71h .Avenue, Suite wo .Anchorage, AX 99501 (907) 793-1223 (yhone) (907) 276-7542 (fax) • 0 Katrina Garner, P.E. BP Exploration (Alaska, Inc. Post Office Box 196612 Anchorage, AK 99519-6612 %2e'�`E Qk� Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. Post Office Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Bernie Karl CIRI K&K Recycling Inc. Land Department Post Office Box 58055 Post Office Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 Richard Wagner Gordon Severson Post Office Box 60868 3201 Westmar Cir. Fairbanks, AK 99706 Anchorage, AK 99508-4336 Darwin Waldsmith James Gibbs Post Office Box 39309 Post Office Box 1597 Ninilchik, AK 99639 Soldotna, AK 99669 Jerry Hodgden Hodgden Oil Company 40818`s St. Golden, CO 80401-2433 North Slope Borough Planning Department Post Office Box 69 Barrow, AK 99723 Jack Hakkila Post Office Box 190083 Anchorage, AK 99519 #38 Carlisle, Samantha J (DOA) From: Montague, W Stuart < Stuart. Montague@bp.com> Sent: Monday, February 10, 2014 11:16 PM To: Roby, David S (DOA) Subject: RE: BP Request to Eliminate Annual Status Meeting for Weatherford Gen 2 VSRD meters Thanks for your note and explanation Dave. You are correct, omission of CO 550 for Milne Point was accidental. I am happy to correct it with a revised letter to AOGCC, or let me know if this email will suffice for you to include Milne in the remaining orders you are updating. I am on the slope this week, checking email in the evenings. Many thanks for your help! Stuart Montague PBU West Waterflood Team Lead (907) 564-4029 (office) (907) 830-8718 (cell) (907) 564-4046 fax stuart.montaaueftD.com From: Roby, David S (DOA) [mailto:dave.roby@alaska.gov] Sent: Thursday, February 06, 2014 6:00 PM To: Montague, W Stuart Subject: RE: BP Request to Eliminate Annual Status Meeting for Weatherford Gen 2 VSRD meters Stuart, I heard back from the AG office today and was putting the finishing touches on the orders. As a little background, the AOGCC's practice now is to do each order as a separate document, instead of one document that amends multiple orders (as was done for the Gen 2 stuff originally). Since the orders are identical in all aspects except for order numbers and field and pool names I just sent the AG one file for their review and I'm now creating the other documents I need to cover the remaining orders. While doing this I noticed a couple of things. First, your application includes CO 402A for the Badami Oil Pool. Since BPXA is no longer the operator for the Badami Unit we can't modify a CO for them on your request so CO 402A.004 will remain in effect as written and not be modified. Second, your application did not include CO 550 for Milne Point in the list of orders you want modified. I assume this was inadvertent, but I need you to confirm whether Milne's exclusion was intentional or accidental? Thanks, Dave Roby (907) 793-1232 From: Montague, W Stuart [mailto:Stuart. Montague@bp.com] Sent: Monday, September 30, 2013 3:24 PM To: Colombie, Jody J (DOA) Cc: Roby, David S (DOA); Davidson, Temple (DNR); Garner, Katrina N; Lea, John F Subject: BP Request to Eliminate Annual Status Meeting for Weatherford Gen 2 VSRD meters 0 Please forward the attached p df letter to the AOGCC Commissioners and the cc list on behalf of BP Alaska. The original letter will be sent out in today's mail. <<AOGCC_Gen 2 yearly status meeting.pdf>> Thank you for your help and cooperation. Stuart Montague PBU West Waterflood Team Lead (907) 564-4029 (office) (907) 830-8718 (cell) (907) 564-4046 fax stuart.montaque(a bp.com #37 0 • Katrina Garner, P.E. Base Management Manager September 27, 2013 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 1100 Anchorage, AK 99501-3539 Re: Include Weatherford Generation 2.0 (VSRD) yearly status as part of the Annual Surveillance Report for each Pool Amendment to CO 547 — Prudhoe Bay Oil Pool Amendment to CO 548 — Endicott Oil Pool Amendment to CO 551 — Northstar Oil Pool Amendment to CO 559 — Put River Oil Pool Amendment to CO 570 — Raven Oil Pool Amendment to CO 402A — Badami Oil Pool Dear Commissioners: k; BP Exploration (Alaska) Inc P.O. Box 196612 900 East Benson Boulevard Anchorage, Alaska AK 99519-6612 UNITED STATES Or AMERICA Phone: +1-907-230-4212 In accordance with 20 AAC 25.230(a), the Commission granted BPXA approval to use Weatherford Generation 2.0 (VSRD) meters for production well testing and allocation within BPXA-operated fields. Item 5 of the Order states "BPXA must conduct yearly status meetings by September 30 of each year detailing the installations to date, the performance of each Gen 2, all operational issues related to the Gen 2, and any additional Gen 2-related test results." BPXA requests the yearly status meeting requirements contained in Item 5 of the Order, as described above, be eliminated for the following reasons: • Gen 2 performance is stable and consistent with defined acceptance criteria; • 2013 well test data comparisons at L pad were acquired to decision future utilization of the existing gravity test separator; • No additional data has been acquired or analyzed beyond what has been presented to AOGCC and DNR representatives during past annual meetings; • Performance of the Gen 2 meters is as expected and has been reviewed with the Commission and DNR staff during prior annual meetings. Consistent with Item 5 in the Order, BPXA will submit appropriate summary information about Gen 2 performance in future annual pool surveillance reports. We look forward to hearing from you regarding your decision on this request. Sincerely, Katrina Gamer, P.E. Base Management Manager Reservoir Development cc: Dave Roby, Reservoir Engineer, Alaska Oil and Gas Conservation Commission Temple Davidson, Reservoir Engineer, Department of Natural Resources Matthew R. Fonder, Director, Department of Revenue - Tax Division -4.36 • • I %%yam THE STATE Fef: °;] eat ci"?u.r. °al Resources �:�. of LAS KA Division of Oil & Gas - Anchorage Office 550 W. 7th Avenue Suite 1100 n . I/ GOVERNOR SEAN PAR ?il: l.i. Q�T 201 Ancnoroge,Alaska99501 -3560 o- �. Main: 907.269.8800 ALASY' Fox: 907.269.8939 AOGCC October 1, 2012 CERTIFIED MAIL RETURN RECEIPT REQUESTED Bob Jennings Manager, Reservoir Management BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO Box 196612 Anchorage, Alaska 99519 -6612 Subject: Milne Point Unit Notification of BPXA's intent to install a Weatherford Alpha VRSD at MPU S -pad Dear Mr. Jennings, On March 3, 2011, BP Exploration (Alaska) Inc. (BPXA), Operator of the Milne Point Unit (MPU), submitted notice to the Alaska Oil and Gas Conservation Commission (AOGCC) of its intent to install the MPU S Pad Weatherford Alpha VRSD multiphase metering system at S Pad in the Milne Point Unit. The Weatherford Alpha VRSD Multiphase Metering System is the commercial version of the Weatherford Generation 2.0 Multiphase Metering System (Gen 2.0). The MPU S Pad wells produce from the Schrader Formation underlying ADLs 25906, 25118, 380109, and 380110. MPU S Pad has no permanently installed or functioning test separator and periodic well testing is conducted using portable test separator units. AOGCC Conservation Order 550.006 granted BPXA's request to use the Weatherford Generation 2.0 Multiphase Metering System in BPXA operated oil fields where the well production characteristics were similar to those that the Gen 2.0 proved successful in metering during field tests. Conservation Orders 550.007 and 550.008 approved additional parameters to use the FMC Technologies Enhanced Multiphse System (EMS) in Milne Point Field, including the Schrader Bluff Formation. The approvals described certain conditions and required separate approvals in areas under the jurisdiction for the Division or the Minerals Management Service (MMS). The State of Alaska, Department of Natural Resources, Division of Oil and Gas (Division) recognizes the benefits of the new metering technology. Increased frequency of well testing enables improvements S £ bp • RECEIVED (,.; 0 3 LJ1Z BP Exploration (Alaska) Inc. AOGCC East Benson Boulevard AOGCC P.O. Box 196612 Anchorage, Alaska 99519 -6612 Main 907 564 5111 April 30, 2012 Cathy Foerster, - Chairperson Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Re: Notification of BPXA's Intent to install a Weatherford Alpha VRSD (former Generation 2.0 Multiphase Metering System) at Milne Point B -Pad for Well Testing and Allocation Purposes Dear Mrs. Foerster: BP Exploration (Alaska) Inc. (BPXA), Operator of the Milne Point field hereby is notifying the AOGCC that we intend to install a Weatherford Alpha VRSD (former Generation 2.0 Multiphase Metering System) at Milne Point B -Pad for well testing and allocation purposes. This is in accordance with Conservation Order 550 and Administrative approval 550.006, rule 4 that states "BPXA must notify the Commission before installing the Gen 2.0 at any BPXA site:" Additionally, the Order states "the Commission GRANTS BPXA's request to use the Weatherford Gen 2.0 Multiphase Metering System for production well testing and allocation within BPXA operated oil fields where the production characteristics are similar to those of the V -Pad and E -Pad wells where Gen 2 was field tested ". The GPB V -Pad field tests included Tight oil Kuparuk formation wells which is the same formation and has similar production characteristics as the Milne Point B -Pad wells. The wells at GPB V -Pad and Milne Point B -Pad both have similar API gravity and viscosity, and will be operating in the liquid dominated region. Currently, Milne Point B -Pad does not have a functioning test separator. Periodic well testing is performed using portable well test units. Installation of the VSRD will result in increased well testing frequency and reduced HSE risks. Sincerely yours, Emeka Emembolu Manager, Base Mana emm t �� ►. t Emeka Emembolu, BPXA Alex De'Ath, BPXA Jessie Chmielowski, BPXA . • • Randy Skillern, BPXA Jerry Brady, BPXA Bill Barron, Division of Oil and Gas - Department of Natural Resources Matthew Fonder, Director Department of Revenue - Tax Division 2 34 ~ Q ~ 0 6 DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL R~ GAS CERTIFIED MAIL RETURN RECEIPT REQUESTED February 9, 2010 David J. Szabo Milne Point Resource Manager BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO Box 196612 Anchorage, Alaska 99519-6612 SEAN PARNELL, GOVERNOR 550 WEST 7T" AVENUE, SUITE 800 ANCHOR,4GE, ALASKA 99501-3560 PHONE.• (907) 269-8800 FAX.• (907) 269-8938 FHB 1 0 2010 C C ° lion nChbra Subject: Milne Point Unit, Notification of BPXA's intent to install a Weatherford Alpha VRSD at MPU G-pad Dear Mr. Szabo, As requested, on January 25, 2010, BP Exploration (Alaska) Inc. (BPXA), Operator of the Milne Point Unit (MPU), presented an update on the MPU G Pad Weatherford Alpha VRSD multiphase metering system installation to the State of Alaska, Department of Natural Resources, Division of Oil and Gas (Division). The Weatherford Alpha VRSD Multiphase Metering System is the commercial version of the Weatherford Generation 2.0 Multiphase Metering System (Gen 2.0). The MPU G Pad wells produce from the Schrader Formation underlying ADLs 315848, 25906, 25518, and 25516. MPU G Pad has no permanently installed or functioning test separator and periodic well testing is conducted using portable test separator units. Alaska Oil and Gas Conservation Commission (AOGCC} Administrative Approval CO 550.006 granted BPXA's request to use the Weatherford Generation 2.0 Multiphase Metering System in BPXA operated oil fields where the production characteristics were similar to those wells where the Gen 2.0 was field tested, including the Schrader Formation. The approval described certain conditions and required separate approvals in areas under the jurisdiction for the Division or the Minerals Management Service (MMS). The Division recognizes the benefits of the new metering technology. Increased frequency of well testing enables improvements in reservoir management. The permanent installation of this metering "Develop, Conserve, and Enhance Natural Resources for Present and Future Alaskans. " MPU G Pad Multiphase Metering System Installation 2/9/10 Page 2 of 2 system provides a reduction to HSE risk when compared to the use of portable test separators. The Division concurs with AOGCC's approval of the meter installation. Sincerely, ~~ Kevin R. Banks ~o'/ Director Cc: Jeff Landry, DOL Dan Seamount, AOGCC *33 i t bp 0 David J. Szabo RECEIVED Head of Resource Management NOV 2 3 2009 BP Exploration (Alaska) Inc. Alaska Consolidated Team (ACT) 900 East Benson Boulevard PO Box 196612 Masks Oil Gas Cons. Commission Anchorage, AK 99519 -6612 (907) 564 -5111 Anchorage November 24, 2009 Phone: (907) 564 -4788 Fax: (907) 564 -4440 Email SzaboDJ ®bp.com Web: www.bp.com Dan Seamount, Chairman Alaska Oil Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Re: Notification of BPXA's Intent to install a Weatherford Alpha VRSD (former Generation 2.0 Multiphase Metering System) at Milne Point G -pad for Well Testing and Allocation Purposes Dear Mr. Seamount: BP Exploration (Alaska) Inc. (BPXA), Operator of the Milne Point field hereby is notifying the AOGCC that we intend to install a Weatherford Alpha VRSD (former Generation 2.0 Multiphase Metering System) for well testing and allocation purposes. This is in accordance with Commission Order 20 AAC 25.230(a) #4 that states "BPXA must notify the Commission before installing the Gen 2.0 at any BPXA site:" Additionally, the Order states "the Commission GRANTS BPXA's request to use the Weatherford Gen 2.0 Multiphase Metering System for production well testing and allocation within BPXA operated oil fields where the production characteristics are similar to those of the V -Pad and E -Pad well where Gen 2 was field tested." The Prudhoe Bay V -Pad field tests included the Schrader Bluff formation wells which is the same formation and has similar production characteristics as the Milne Point G -Pad wells. The wells at V -Pad and G -Pad both have similar API gravity, viscosity and will be operating in the liquid dominated region. Currently G -Pad has no permanently installed or functioning test separator. Periodic well testing is performed using portable well test units. Installation of the VSRD will result in increased well testing frequency and reduce HSE risks. The installation of the VSRD will not change our current methodology of production allocation. Sincerely yours, David J. Sza Mr. Dan Seamount November 24, 2009 Page 2 cc: Tom Marshall, BPXA Jeff Michels, BPXA Kenton Schoch, BPXA Emeka Emembolu, BPXA Nathan Leonard, BPXA Giovanna Boccardo, BPXA Randy Skillern, BPXA Chris Wyatt, BPXA Eric Jenkins, BPXA Daniel Winter, BPXA Glenn Lau, BPXA Gordon Pospisil, BPXA Jerry Brady, BPXA Dave Robi, Alaska Oil Gas Conservation Commission Kevin Banks Division of Oil and Gas Department of Natural Resources Jon Iversen, Director Department of Revenue Tax Division ~' 32 ~ • ~ bp Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907) 564-5769 Fax: (907) 564-5706 Email: gordon.pospisil~bp.com April 27, 2009 Dan Seamount, Jr. - ~hairman Alaska Oii & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Supplemental data II for EMSTM ASRC Unit #5 and approval to use Unit #5 in additional BPXA operated fields Amendment to CO 547 - Prudhoe Bay Oil Pool Amendment to CO 548 - Endicott Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 - Put River Oil Pool Amendment to CO 570 - Raven Oil Pool Amendment to CO 402A - Badami Oil Pool Dear Mr. Seamount: The attached report (Supplemental data II for EMSTM 3/24/09) was prepared to address questions the AOGCC requested for the EMST"' - ASRC Unit #5 and was sent to Jane Williamson of the AOGCC on 3/24/09. The information provided in the 3 reports (EMST"' Field Tria( Resuits - 5/13/2C0~, ~upplem?ria! ~~rta for EMST~~ - 12/0310~, and this repart Supplemental data II for EMST"' 3/24/09) has established the accuracy and performance envelop of the ASRC Unit 5 with respect to major multiphase measurement parameters in compliance with the AOGCC Guidelines. These parameters include liquid, oil and gas flow rates, GVF range, WC range, well head pressure and temperature, oil gravity, and fluid viscosity. Furthermore, through improvement in Unit 5 hardware and testing protocol, we have shown that the CDS separator can be used to decrease the GVF level of the test fluids to improve the accuracy of the measurements. The EMSTM - ASRC Unit #5 can reliably conduct production well testing at any BPXA operated North Slope location. BPXA is requesting that the FMC Technologies System (EMST"'), subject to the constraints identified in Report Supplemental data II for EMST"' 3/24/09, be approved for well testing and allocations in all the BPXA operated fields listed below and that the appropriate conservation order be amended for this approval. This would allow the system to be used in all the fields as originally requested in BPXA's original application report in 2006. BPXA Request for Clarification •ting and Request for Nearing ~ Page 2 Amendment to CO 547 - Prudhoe Bay Oil Pool Amendment to CO 548 - Endicott Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 - Put River Oil Pool Amendment to CO 570 - Raven Oil Pool Amendment to CO 402A - Badami Oil Pool Should you have any questions regarding this request, please don't hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Thank you for your assistance. Sincerely yours, _ ~~~~. v J ~ ~----~-~'~ ~'~ ~. ~ Gordon Pospisil Technology & Resource Manager Attachment Cc: Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA Sherri Gould, BPXA Carey Reed, BPXA John Cyr, BPXA Chris Wyatt, BPXA Krissell Crandall, BPXA Jerry Brady, BPXA Emeka Emembolu, BPXA John Denis, BPXA Alan Mitchell, BPXA Greg Peters, ExxonMobil Craig Haymes, ExxonMobil Dan Kruse, CPAI Glenn C. Fredrick, Unocal, Chevron Kim Bowen, Anadarko Daniel "Toby" Osborn, Doyon LTD Mathew Fagnani, Nana Jim Mendenhall, Nana Ignacio Herrere, Murphy Exploration Jane Williamson, Alaska Oil & Gas Conservation Commission Cammy Taylor - Unit Manager Department of Natural Resources Jon iversen, Director Department of Revenue - Tax Division . ~ ~~ AOGCC Report 03~24 ~ 2009 ~ ~ Su~~lemental-2 I?ata for the AOGCC - Report 03/24/Q9 ~SRC Uniti 5 Field Quatification This report provides supplemental data requested by Jane Williamson- AOGCC in regards to the ASRC Unit 5 Field Qualifications. The current report supplements data presented in the Sept 29, 2008 and a Dec. 04, 2008 reports previously. Subsequent to the presentation of the previous reports Jane Williamson requested data on the Viscosity, Reynolds Number, test pressure and temperature as well as calculated GVF for the piggy back tests reported in the original submissions. In addition the last AOGCC order for Unit 5 had questions regarding the use of CDS separator. These issues are addressed in the following sections of this report. Fluid properties and Flow Regimes for the Piggy Back Tests Tables 1 and 2 show flow rates and fluid properties far piggy back tests conducted during the qualification using ASRC Unit 1 and Unit 5. These tests covered the WC range of 2-99% and average GVF range of 0- 82%. The actual GVF range, even in low GVF wells, was close to 100% since these wells slug heavily. The testing temperature ranged from 50 to 85 °F and nominal pressure of about 300 psig combined with API gravity of 16-21 provided fairly harsh measurement environments. The multiphase meter had to operate in the 40-140000 Reynolds number range. These parameters are summarized in Tables 1 and 2 for each test. Milne Point Tests Figure 1 shows the WC/GVF inap for the well tests conducted by the ASRC Unit 5 at Milne Point. These tests cover the wells with GVF up to 100 and WC range of 0-100. To be able to handle these ranges of GVF and WC, the ASRC Unit 5 has undergone upgrading of hardware and testing protocols as described in Appendix 1. About 30% of the well tests conducted at Milne Point have utilized the CDS separator to perform partial gas separation - of course all well streams must run through the CDS separator Page 1 of 8 • ` AOGCC Report 03/24 ~ 2009 in order to go through the muitiphase meter. The CDS is used to accomplish the following: • Reduce the GVF for high GVF streams • Reduce the GVF for mid-range GVF streams to move the operating performance envelop for 3" TF meter to 2" TF meter Both of the above steps are used to improve the accuracy of the multiphase measurements. Table 3 shows typical examples of the use of CDS and its impact on GVF reduction for wells with average GVF range of 66-97 %. The setting for CDS separator is determined during the stabilization period prior to the start of the actual well tests. The efficiency of the CDS separator is a function of the flow rates (liquid and gas), frequency of slugging as well as fluid properties as noted by the variation of efficiency for different wells in Table 3. Figure 2 shows an example of the CDS gas removal for MPC - 22 well. Summary The data submitted to AOGCC in the two previous reports and this supplement show that ASRC Unit 5 has been able to operate in the following ranges of multiphase measurement environments: 1. 0-100% WC 2. 0-100% Gas Volume Fraction streams. The CDS separator can be used if needed to divert portion of the gas to reduce the GVF level as shown in Table 3 and Figure 2, and improve the accuracy of ineasurements. 3. Over 468 tests have been conducted in the above ranges of WC and GVF as shown in Figure 1. 4. The tests shown in Tables 1 and 2 have covered fluid viscosity ranges of 1-500 cP and Reynolds number of 10 - 140,000 5. The measured WC uncertainty for all tests is within ± 2.5 to t 5% of sample water cut measurements as shown in Figure 3. Figure 4 shows an improvement in water cut measurements as the testing program has progressed in line with the improvements (items 4, 5, 6- Appendix 1) that have been made to the TopFtow set Page 2 of 8 ~ • ~ AOGCC Report 03~24 ~ 2009 ~ up, for example most notably for B Pad between May 2008 and September 2008 and January 2009. 6. The liquid and gas measurements are within ± 10% of the ASRC Unit 1 and tank tests - as noted in the initial report to AOGCC. However due to lack of good reference measurements at very low gas rates(less than 20 mscfd}, the gas rate uncertainty cannot be confirmed at the low rates as noted in the Sept. 29, 2008 report. 7. The field measurement results are within the scatter of historic data- as noted in Dec. 4, 2008 report to AOGCC. 8. The ASRC Unit 5 should be able to conduct production tests at any BP North Slope location that meets the multiphase fluid stream conditions listed in items 1-4. Page 3 of 8 • i AOGCC Report 03/24 ~ 2009 ~ Tabfe 1- ASRC Unit 1 Test Results Weil Date %WC Liquid BPD Oil SPD Gas MSCFD Sep Press- PSI Sep Temp'F GOR Ave %GVF MPH-04 2007-08-13 21% 156 124 4 275 70 28 15 MPH-13 2007-08-13 45% 646 354 21 275 68 54 19 MPH-16 2007-08-13 20% 768 615 141 269 72 226 60 MPI-03 2007-12-14 5% 126 118 15 298 73 125 47 MPI-03 2007-12-18 4% 136 132 25 298 54 191 57 MPI-04 2007-12-18 55% 455 206 115 279 55 560 66 MPI-06 2007-12-15 62% 769 290 31 293 73 107 24 MPI-14 2007-12-16 47% 712 374 16 327 75 43 11 MPI-17 2007-12-14 20% 1231 981 237 286 69 242 60 MPI-19 2007-12-17 11% 509 450 258 292 51 573 79 MPS-04 2007-08-11 98% 1402 32 0 261 74 0 0 MPS-OS 2007-08-11 66% 1858 632 1Qi 269 78 159 31 MPS-12 2007-08-10 85% 3770 578 544 278 83 936 54 MPS-17 2007-08-09 89% 3681 406 883 277 83 2165 66 MPS-19 2007-08-10 99% 2031 17 0 253 79 0 0 MPS-25 2007-08-10 90°/a 3927 385 13 336 83 34 2 MPS-29 2007-08-09 68% 2009 635 0 334 78 0 0 Table 2- ASRC Unit 5 Test Results Well Date %WC Liquid BPD Oi18PD Gas MSCFD Sep Press P51 Sep Temp. DEG f GOR API Gravity Ave %GVF Mix ~s cP Live Oil Vis Est Reynolds Number MPH-04 8/13/07 22% 240 187 10 282 61 55 16 29 293 157 57 MPH-13 8/13/07 56% 892 393 48 294 67 123 18 27 462 60 35 MPH-16 8/12/07 25% 905 679 155 278 62 228 21 57 114 56 554 MPI -03 12/14/07 1% 101 97 13 314 52 129 20 67 111 100 62 MPI-03 12/18/07 1% 107 104 19 303 48 179 20 67 168 156 44 MPI-04 1?J18/07 49% 342 181 143 300 62 791 21 82 179 37 140 MPI-06 12/15/07 57% 324 739 122 298 67 878 21 62 226 27 105 MPI-14 12/16/07 59% 620 254 110 342 89 433 18 55 184 20 244 MPI-17 12/14/07 34% 1137 755 355 305 70 470 19 71 93 33 882 MPI-19 12/17/07 17% 510 423 323 305 70 764 20 82 44 28 851 MPS-04 8/11/07 92% 1402 112 19 264 74 169 19 11 1 27 101000 MPS-08 8/12/07 62% 1918 729 103 275 78 141 18 30 1 27 61000 MPS-12 8/10/07 86% 4294 512 483 312 83 943 19 43 1 14 140000 MPS-17 8/10/07 79% 3357 705 1215 323 84 1723 17 69 1 21 113000 MPS-19 8/11/07 95% 1905 95 19 253 79 198 17 4 1 31 62000 MPS-25 8/10/07 90% 4051 407 119 350 84 293 21 17 1 13 131000 MPS-29 8/9/07 76% 1888 453 29 335 79 63 20 10 1 25 60300 Page 4 of 8 ~ ~ AOGCC Report 03/24 2009 Table 3- Gas Removal Efficiency of CDS Separator Gas Removal Efficiency - CDS Well Date Tested Ave.Line GVF Ave. TF GVF Ave Efficiency MPS-23 08/10/22 66 25 62% MPH-16 01/26/09 74 37 51% MPI-15 01/29/09 81 75 7% M PS-12 03/25/08 84 19 77 % MPB-04 01/04/09 93 90 3% MPB-16 01/05/09 94 75 20% MPB-15 04/28/08 96 62 35% MPC-22 11/28/08 97 67 31% 100 90 80 7~ o° ~~ ~. ~ 5~ U ~, aa 5 30 2a ~a U ,J o~; • ~ n ~ ~ ^ • •• ~.,. ~ ~ nJ '~ 4J ~~k ~' ~ ~ +~ ^ ~~ i 1~ +~,f ~~~; ~- J ~ ~~~~~~ i + ~~ ~ ~~ ^; ,~ _`-' - ~' ~°0 ~ + ~ ~ + ~~' • ~,~ t~` :~ o~ + + ~ ~` o .#, o + ~ ~' ~~ , ~ . # ~ + ~ -~ "~ . x+~+~ XX , x •MP-B * ++ ~ ~^ ~~ •~ •MP-C t *~~ + ~~~ ~+~ X~~~ ~Y~ ~ • oMf'-E + X+++ ~ x ~~~,v, ~ t x M P-G • ~'` x ;i~ '~C ~ '~l~ ~t ~;~: • •, t.MP-H • • ~ + t ~~ X ~n X~~,~~ ~~• •MP-I • ~ + ~` ~ , ~~~~ e~ ~ ~ x };h ~5,~'~ ~ ~' y p +MP-,l ,~,,. +~ ~ • ~ ~MP K ~ ~ X ~~' +-~~ x+ ~ ~: • . . s MP-L ~ ~ ~MI'-5 ~ ~ ~ • M + + + + ,", ~ 0 2Q 4~ 60 80 GVF {%) Figure 1- Map of WC and GVF for all Milne Point wells tested 1~4 Page 5 of 8 • ~ AOGCC Report 03/24 2009 MPC-22, 081128 1oQ 80 ,~ 60 > l7 ~ ' 40 20 a 7:12 Line GVF TF GVF j 1 14:24 ; Figure 2- Gas removal graph for MPC-22 Well. The well produced 195 bpd of liquid, 449 mscfd gas, API gravity was 22, average WC=54%, temperature of 151 °F, Pressure of 205 psig ~oo 90 $0 ~ ~ 70 U ~ ~~ r ~4 3 50 ~ ~ 4Q ~ ~ a 30 E ~ 2g c ~ 10 0 Page 6 of 8 8:?4 ~:3G 10:48 12:00 13:1? 0 20 ~0 C~0 8G 10a Sample~riater cut (°,~c~) Figure 3- Water cut uncertainty for all tests at Milne Point • • AOGCC Report 03/24 2009 50 -- 40 0 ~ 30 _ ~ 20 ~ ~ 10 ~ ~ u O L ~ f~ 3 -10 ~ a 2a ~ ~ a -30 E ~ -40 _ ~ -50 • MP-B • MP-C _. MP-E MP-G 7 MP-H • MP-I , MP-J MP-K MP-L - MP-S ----+l-5% Nov-2007 Jan-2008 Mar-2008 May-2008 Ju1-2008 Sep-2008 tJov-2008 Jan-2009 Mar-2009 Figure 4- Water cut uncertainty for all tests at Milne Point. Note improvement in the uncertainty as the field tests have progressed. Page 7 of 8 Unit-5 Configurations for Improved Accuracy When this unit was constructed the control system was being totally run from the CDS/Top Flow computer systems; there was no SCADA system design and therefore the capability of the system was limited from the standpoint of continuous improvement as well as data acquisition capabilities. The decision was made by ASRC management and technical support for the in-house design, construction, and integration to the ABB SCADA system that has been proven in field applications with ASRC Well Test Unit #1 (Millennium) and Exploration Unit #4. The ABB SCADA system takes all incoming information from CDS/Top Flow and translates this information to data bases accordingly as well as allowing more precise operational control options and updates. Updates and options that have been incorporated to date are as follows: 1j Successful auto-tuning of P&ID controllers; this is an advanced relay and step auto tuning application built into the ABB system. 2) Added a Differential Pressure cell for more precise vessel level indication / control, this gives the operator an option to use Differential Pressure or Magnatrol probe for vessel level control / indication; this ties into the P&ID controller for more precise / active vessel level control. 3) Smaller orifice plates were added to the overall plate choices giving the operator the ability to read lower gas rates; this is especially effective at MPU when you need to knock of some GVF from Top Flow on certain wells to be in the most accurate range. 4) An on-board Conductance Analyzer was purchased for real-time water analysis; this gives us the ability to calibrate conductance for Top Flow for each stream. 5) An on-board Anton Par DMA35n density meter was purchased, giving us the ability in real time to make accurate oil and water density measurements; this gives us the capabilities of calibrating the Top Flow for each stream. 6) Redesign of spreadsheet that calculates oil permittivity for a more accurate estimate that is used in TopFlow calibration for each stream. 7) New PC's for TopFlow flow computer, faster processor and more memory. 8) Better understanding and training of personnel on the TopFlow configuration and its importance. 9) Recently added discharge coefficient calculation spreadsheet for improved VDC setting within Top Flow. Page 8 of 8 RE: Supplemental data II for FMC Enha~ d Multiphase System (EMS) used in ~ C Unit #5 and requ... Page 1 of 2 Colombie, Jody J (DOA) From: Brady, Jerry L (Jerry.Brady@bp.com] Sent: Tuesday, March 24, 2009 3:20 PM To: Williamson, Mary J (DNR) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); p.mehdizadeh@cox.net Subject: RE: Supplemental data II for FMC Enhanced Multiphase System (EMS) used in ASRC Unit #5 and request to use Unit #5 in additional fields Jane, I will prepare an official application to Chairman Seamount to use ASRC Unit #5 in all BP pools and cc DNR and DOR as you have suggested. We are not is a significant hurry with the exception we believe that we can utilize the equipment more efficiently by having approval to use it in any of the BP operated properties. Given that we have operated the Unit for several months in Milne Point and we feel that we have a good handle on its capabilities, we are ready to start using it at our other locations. If needed, we can setup a meeting with Andrew and Parviz to answer any questions that you may have with the supplemental data. Sorry to hear that yau have been ill. I hope that you make a swift and total recovery! Take care, Jerry From: Williamson, Mary J (DOA) [mailto:jane.williamson@alaska.gov] Sent: Tuesday, March 24, 2009 1:20 PM To: Brady, Jerry L Subject: RE: Supplemental data II for FMC Enhanced Multiphase System (EMS) used in ASRC Unit #5 and request to use Unit #5 in additional fields Jerry, Pll try to review. Concerning the request for use of the meter in all BP pools, you'll need an official application to Chairman Seamount, and you need to copy DNR and DOR. Are you in a hurry for any specific use at this time? I want to take some time to go through your partial separation writeup, and maybe get with you, Parviz, Andrew, Tom Maunder, Dave Roby. You might also want to consider having a meeting similar to that which you had for the Gen 2 with DNR, DOR, MMS representatives. Are things progressing on the Gen 2 with those agencies ok? 1've been ill the past couple of weeks, but am recovering and doing some work at home. You can call me at home at 345-7678 today (and maybe tomorrow if I don't get in to wark.) Else, give me a call next week (793-1226). Jane -----Original Message----- From: Brady, Jerry L[mailto:Jerry,Brady cr bp.coin] Sent: Tue 3/24/2009 9:24 AM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); p.mehdizadeh@cox.net; Steve.Myers@asrcenergy.com; Emembolu, Emeka Subject: Supplemental data II for FMC Enhanced Multiphase System (EMS) used in ASRC Unit #5 and request to use Unit #5 in additional fields 5/4/2009 RE: Supplemental data II for FMC Enha~ d Multiphase System (EMS) used in ~ C Unit #5 and requ... Page 2 of 2 Jane, «cover IeterNote to Jane on Supplemental data for ASRC Unit #Spm (3).doc» «Supplemental Data II for EMS 03-24-09.doc» The attached report (Supplemental data II for EMSTM 3/24/09) was prepared to address questions and data you requested for the EMSTM - ASRC Unit #5. The information provided in the 3 reports (EMSTM Field Trial Results - 5/13/2008, Supplemental data for EMSTM - 12/03/08, and this report Supplemental data II for EMSTM 3/24/09) has established the accuracy and performance envelop of the ASRC Unit 5 with respect to major multiphase measurement parameters in compliance with the AOGCC Guidelines. These parameters include liquid, oil and gas flow rates, GVF range, WC range, well head pressure and temperature, oil gravity, and fluid viscosity. Furthermore through improvement in Unit 5 hardware and testing protocol, we have shown that the CDS separator can be used to decrease the GVF level of the test fluids to improve the accuracy of the measurements. The ASRC Unit 5 should therefore be able to conduct production well testing at any BPXA operated North Slope location that meets the well stream conditions delineated by the multiphase fluid parameters listed in items 1-4 of the summary of the attached report. BP is submitting this information to: 1) Meet the requirement of Order #4 under the Administrative Approval CO 55-007 dated January 6, 2009 for the use of FMC Technologies Enhanced Multiphase System (EMSTM) for well testing and allocations in the Milne Point field. This order states "By March 31, 2009, BPXA must provide documentation of the performance of the gas-liquid cyclonic separator over the full range of GLS tested within the field trials." 2) BPXA is again requesting that the FMC Technologies Enhanced Multiphase System (EMSTM), subject to the constrains identified in Report Supplemental data II for EMSTM 3/19/09, be approved for well testing and allocations in all the BPXA operated fields listed below and that the appropriate conservation order be amended for this approval. This would allow the system to be used in all the fields as originally requested in BPXA's original application report in 2006. Amendment to CO 547 - Prudhoe Bay Oil Pool Amendment to CO 548 - Endicott Oil Pool Amendment to CO 550 - Milne Point Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 - Put River Oil Pool Amendment to CO 570 - Raven Oil Pool Amendment to CO 402A - Badami Oil Pool If you have any questions, please give me a call. 7erry Brady 5/4/2009 Supplemental data II for FMC Enhanced Multiphase System (EMS) used in ASRC Unit #5 and request t... Page 1 of 2 ~ • Colombie, Jody J (DOA) From: Brady, Jerry L [Jerry.Brady@bp.com] Sent: Tuesday, March 24, 2009 9:24 AM To: Williamson, Mary J (DNR) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); p.mehdizadeh@cox.net; Steve.Myers@asrcenergy.com; Emembolu, Emeka Subject: Supplemental data II for FMC Enhanced Muitiphase System (EMS) used in ASRC Unit #5 and request to use Unit #5 in additionai fields Attachments: cover IeterNote to Jane on Supplemental data for ASRC Unit #5pm (3).doc; Supplemental Data II for EMS 03- 24-09.doc Jane, «cover IeterNote to Jane on Supplemental data for ASRC Unit #5pm (3).doc» «Supplemental Data II for EMS 03-24- 09.doc» The attached report (Supplemental data II for EMSTM 3/24/09) was prepared to address questions and data you requested for the EMSTM - ASRC Unit #5. The information provided in the 3 reports (EMSTM Field Trial Results - 5/13/2008, Supplemental data for EMSTM - 12/03/08, and this report Supplemental data II for EMSTM 3/24/09) has established the accuracy and performance envelop of the ASRC Unit 5 with respect to major multiphase measurement parameters in compliance with the AOGCC Guidelines. These parameters include liquid, oil and gas flow rates, GVF range, WC range, well head pressure and temperature, oil gravity, and fluid viscosity. Furthermore through improvement in Unit 5 hardware and testing protocol, we have shown that the CDS separator can be used to decrease the GVF level of the test fluids to improve the accuracy of the measurements. The ASRC Unit 5 should therefore be able to conduct production well testing at any BPXA operated North Slope location that meets the well stream conditions delineated by the multiphase fluid parameters listed in items 1-4 of the summary of the attached report. BP is submitting this information to: Meet the requirement of Order #4 under the Administrative Approval CO 55-007 dated January 6, 2009 for the use of FMC Technologies Enhanced Multiphase System (EMSTM) for well testing and allocations in the Milne Point field. This order states "By March 31, 2009, BPXA must provide documentation of the performance of the gas-liquid cyclonic separator over the full range of GLS tested within the field trials." 2) BPXA is again requesting that the FMC Technologies Enhanced Multiphase System (EMSTM), subject to the constrains identified in Report Supplemental data II for EMSTM 3/19/09, be approved for well testing and allocations in all the BPXA operated fields listed below and that the appropriate conservation order be amended for this approval. This would allow the system to be used in all the fields as originally requested in BPXA's original application report in 2006. Amendment to CO 547 - Prudhoe Bay Oil Pool Amendment to CO 548 - Endicott Oil Pool 5/4/2009 Supplemental data II for FMC Enhanced Multiphase System (EMS) used in ASRC Unit #5 and request t... Page 2 of 2 ~ • Amendment to CO 550 - Milne Point Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 - Put River Oil Pool Amendment to CO 570 - Raven Oil Pool Amendment to CO 402A - Badami Oil Pool If you have any questions, please give me a call. Jerry Brady 5/4/2009 ~ Jane, ~ The attached report (Supplemental data II for EMSTM 3/24/09) was prepared to address questions and data you requested for the EMSTM - ASRC Unit #5. The information provided in the 3 reports (EMSTM Field Trial Results - 5/13/2008, Supplemental data for EMSTM - 12/03/08, and this report Supplemental data II for EMSTM 3/24/09) has established the accuracy and performance envelop of the ASRC Unit 5 with respect to major multiphase measurement parameters in compliance with the AOGCC Guidelines. These parameters include liquid, oil and gas flow rates, GVF range, WC range, well head pressure and temperature, oil gravity, and fluid viscosity. Furthermore through improvement in Unit 5 hardware and testing protocol, we have shown that the CDS separator can be used to decrease the GVF level of the test fluids to improve the accuracy of the measurements. The ASRC Unit 5 should therefore be able to conduct production well testing at any BPXA operated North Slope location that meets the well stream conditions delineated by the multiphase fluid parameters listed in items 1-4 of the summary of the attached report. BP is submitting this information to: 1) Meet the requirement of Order #4 under the Administrative Approval CO 55-007 dated January 6, 2009 for the use of FMC Technologies Enhanced Multiphase System (EMSTM) for well testing and allocations in the Milne Point field. This order states "By March 31, 2009, BPXA must provide documentation of the performance of the gas-liquid cyclonic separator over the full range of GLS tested within the field trials." 2) BPXA is again requesting that the FMC Technologies Enhanced Multiphase System (EMSTM), subject to the constrains identified in Report Supplemental data II for EMSTM 3/19/09, be approved for well testing and allocations in all the BPXA operated fields listed below and that the appropriate conservation order be amended for this approval. This would allow the system to be used in all the fields as originally requested in BPXA's original application report in 2006. s • Amendment to CO 547 - Prudhoe Bay Oil Pool Amendment to CO 548 - Endicott Oil Pool Amendment to CO 550 - Milne Point Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 - Put River Oil Pool Amendment to CO 570 - Raven Oil Pool Amendment to CO 402A - Badami Oil Pool If you have any questions, please give me a call. Jerry Brady ~~~ ~ bp Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. February 19, 2009 Kevin Banks - Director Division of Oil and Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, Alaska 99501-3560 Phone: (907) 269-8800 Fax: (907) 269-8938 ~ ~EGEIVED ~ ~~ B 5 2009 ~~~~~~y~ ~?;' ~, C . Cammission A BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907) 564-5769 Fax: (907) 564-5706 Email: gordon.pospisildbp.com Re: Application for Weatherford Generation 2.0 Multiphase Metering System Badami Unit Duck Island Unit Milne Point Unit Northstar Unit Prudhoe Bay Unit Dear Mr. Banks: BP Exploration (Alaska) Inc. (BPXA), Operator of the Units and Participating Areas shown in Table 1, hereby requests authorization to use a multiphase measurement device, as briefly described below and in the Application Report for Weatherford Generation 2.0 Multiphase Metering System approved by the AOGCC on October 29, 2008 for the purpose of well testing and production allocation (Appendix 1). The report describes the design, the expected performance and the anticipated applications of the Weatherford Generation 2.0 Multiphase Flow Meter. The Gen 2.0 in-line multiphase metering system described in the attached report is based on the infrared water cut detector and sonar flow meter technologies, both developed by Weatherford. The system has been successfully tested at GPB V-pad and provides a metering solution for use in the full range of well conditions on the North Slope. The trial on V-pad concentrated on high gas fraction, gas lifted wells, but with conditions in the liquid-dominated multiphase regime. V-pad was also selected because all three major producing reservoirs (Sadlerochit, Kuparuk, and Schrader Bluffl are produced through this facility and could be tested with a single hook-up of the • ~ BPXA Request for Clarification Meeting and Request for Hearing Page 2 multiphase flow meter. The Gen 2.0 meter was tested in series with other multiphase and conventional separator based metering systems on V-pad. The performance data was statistically evaluated for accuracy, precision, and repeatability against a known standard two-phase separator. Additionally, the wet gas portion of this meter system has been tested at GPB E-pad, in a well with very high GORs (>50,000) and gas volume fractions greater than 99%. The performance of the components and the entire Gen 2.0 system has also been verified in several test loops. A summary of these results were presented to the DNR, AOGCC, DOR and MMS on August 11, 2008. Based on the results of these tests and other experience gained throughout the world, BPXA has gained an improved understanding of the applicability of multiphase metering to North Slope production wells. The proposed applications will use the Weatherford Gen 2.0 (now called the VSRD) multiphase metering for production allocation. There are two applications for this meter. The first is to replace pad test separators. In this application there is no change to the current well test and allocation methodology. The second application is to use the meter for continuous monitoring of an individual well. In that case the well rates will be determined by measurement of the multiphase flow meter and those flow rates will replace the traditional well test and rate tables. This continuous monitoring should result in better determination of the well production rates. In both methodologies, the standard Gathering Center or Flow Station allocation factor will be applied to the flow rates of the well. The Gen 2.0 will not be used to replace traditional LACT meters or for fiscal allocations except in the case where current fiscal allocation is being performed with a conventional test separator and well rate allocations. In the event where a conventional test separator that was being used for fiscal allocation is replaced with the Gen 2.0 (for example: satellites production into the Prudhoe Bay Oil Rim) the multiphase flow meter fiscal allocation will be handled in the same way as the conventional test separator that was being used in the fiscal allocation process. While the use of these meters as described above and in Appendix 1 remains subject to the approval and funding of the working interest owners of the units where such use is proposed, DNR approval of this request will advance the use of multiphase technology for North Slope production measurements and ultimately increase production and efficiencies. Benefits from a multiphase meter includes improved testing frequency (much shorter stabilization period required), production ~ngerprinting (no vessel dampening), reduced HSE risk (smaller footprint, fewer personnel, no vessel), and opportunity for lift optimization. Should you have any questions regarding this request, please don't hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. ~ ~ BPXA Request for Clarification Meeting and Request for Hearing Page 3 Thank you for your assistance. Sincerely yours, ~ a~.-~ ~ Gordon Pospisil Technotogy 8~ Resource Mgr. BP Exploration {Alaska} Inc. Attachment Cc: Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA Sheni Gould, BPXA Carey Reed, BPXA J~hn Cyr, BPXA Chris Wyatt, BPXA Krissell Crandall, BPXA Jerry Brady, BPXA Emeka Emembolu, BPXA John Denis, BPXA Alan Mitchell, BPXA Greg Peters, ExxonMobil Craig Hayrnes, ExxonMobil Dan Knase, CPAI Glenn C. Fredrick, Unocal, Chevron Scott MiHington, Anadarko Daniel "Toby° Osbom, Doyon LTD Mathew Fagnani, Nana Jim Mendenhal(, Nar-a Ignacio Herrere, Murphy Exploration Jane Wiliiamson, Alaska Oi! & Gas Conservation Commission Cammy Tayior - Unit Manager Department of Natural Resources Jon iversen, Director Department of Revenus - Tax Division ~ bp Gordon Pospisil Technology & Resource Manager BP Expioration (Alaska), Inc. July 8, 2008 Dan Seamount, Jr. - Chairman Alaska Oil & Gas Conservation Commission 333 West 7t~' Avenue, Suite 100 Anchorage, AK 99501 ~ BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907) 564-5769 Fax: 1907) 5645706 Email: gotdon.pospisil~bp.com Re: Application Report for Weatherford Generation 2.0 Multiphase Metering System Amendment to CO 547 - Prudhoe 6ay Oil Pool Amendment to CO 548 - Endicott Oil Pool Amendment to CO 550 - Milne Point Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 - Put River Oil Pool Amendment to CO 570 - Raven Oil Pool Amendment to CO 402A - Badami Oil Pool Dear Mr. Seamount: BP Exploration (Alaska) Inc. (BPXA), Operator of the fields shown in Appendix 1 of the attached Application Report, hereby requests authorization to use a multi-phase measurement device, as described in the Application Report, for the purpose of well testing and production aflocatian within BPXA operations conducted in the Prudhoe Bay Oil Pool, Endicott Oil Pool, Milne Point Oil Pool, Northstar Oil Pool, Put River Oil Pool, Raven Oil Pool, and Badami Oil Pool pursuant to 11 AAC 83.371, 20 AAC 25.228, and 20 AAC 25.230. The report describes the design, the expected performance and the anticipated applications of the Weatherford Generation 2.0 Multi-Phase Flow Meter. BPXA atso requests an amendment to each of the aforementioned AOGCC Conservation Orders (COy governing each pool in order to allow for the use of multi-phase meter technology as described in the Attached Report. The in-line multiphase metering system described in the attached report is based on the infrared water cut detector and sonar flow meter technologies, both developed by Weatherford. The system has been successfufly tested at GPB V-pad and provides a metering solution for use in the full range of well conditions in the North Slope fields. The trial tests on V-pad concentrated on high gas traciian, gas lifted wells, but with conditions in the liquid-dominated multiphase regime. These meters were tested in a series and were statistically evaluated for accuracy, precision, and repeatability against a ~ ~ BPXA Request for Clarification Meeting and Request for Hearing Page 2 known standard two-phase separator. Based on the result of this test and other expe~ience gained throughout the world, BPXA has gained an improved understanding of the applicability and limitations of muiti-phase metering to North Slope production welis. The AOGCC Application Report submitted herein compiles the data and literature that were used to qualify the design and establish performance levels for the Weatherford Gen 2.0 Multi-phase Flow Meter as a self contained unit. This document was prepared toilowing the "Guidelines for Qualification of Multiph~se Metering Systems for Well Testing" issued November 30, 2004 by the AOGCC. Approval of this request will advance the use of multi-phase metering technology for North Slope production measurements. It will allow BPXA to gain operatianai experience with this. meter while demonstrating multi-phase metering technology can provide allocation well tests comparable to a conventional test separator. Additional benefits include improved testing frequency tno stabilization period required), production fingerprinting (no vessel dampening), reduced HSE risk (smaller footprint, fewer personnei, no vessel), and opportunity for lift optimization. Should you have any questions regarding this request, please don't hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Thank you for your assistance. Sincerely, _~~-1'~~, ;f` .1 ~` %~_ ^~a ~ ~ Gordon Pospisil Technology & Resource Manager Attachment cc_ Frank Paskvan, BPXA Scott Digeri, BPXA Diane Richmond, BPXl~ Mark Weggeland, [iPXA John McMullen, BPXA Sherri Goufd, BPX~1 John Cyr, BPXA Jerry Brady, QPXA Alan Mitchep, BPXA Sanny Rix, ExxanMobil Dan Kruse, CPAI Glenn C. Fredrick, Chevron USA Scott Millington, Anadarko Daniel "Toby" Osbom, Doyon Ltd Mathew Fag~ani, Na~a Glenn Fredrick, Chevron ignacid Herrere, Murphy Exploration Jane Williamson, Alaska Oil & Gas Conservation Commission Kevin Banks (Acting Director) Division of Oil and Gas - Department of Naturaf Resources Cammy Tayior - Unit Manager Department of Natural Resources Jon {versen, Director Department of Revenue - Tax Division ~ BP Alaska ~ AOGCC "Application Report" for the Weatherford Gen 2 Multiphase Metering System ~/ZS/ZOOs • ~ 076308 :10GCC Gen2 :1pp Rpt.duc Table of Contents AOGCC "Application Report"for Gen 2 Multiphase Measurement System ............................ 3 1. Introduction ........................................................................................................................ 3 2. Proposed Applications ....................................................................................................... 3 3. System Components and Measurement Strategy ................................................................ 3 4. Field Test Program and Test Results ................................................................................. 6 Table 1- Summary of wells tested, time, and duration ......................................................... 7 Table 2- Well Fluid Properties for Gen 2 Tests ................................................................... 7 Table 3- Summary of Gen 2 Measurement Uncertainties (RMS average values) ................. 7 S. Factory Acceptance Tests (FAT) ......................................................................................10 6. Field Maintenance and Periodic Calibration ..................................................................10 7. List of References .............................................................................................................11 8. List ofAppendices ............................................................................................................11 2of11 . ~ 4 ~t ,~a.;-t~ ~. . s .. ~~.F,_ r ~~_;, 1~~~~'~` `~~~~~~ic~~~iar~ T~e~Q~~~~"fo~• ~e~ ~ .l~lulti~l~~ase 1~`eers~rr~n~~er~t Sys~er~~ 1. Introduction This document describes the design and anticipated performance of Weatherford Gen2 - hereafter referred to as Gen 2 multiphase metering skids - designed for well testing of wells in operating areas shown in Appendix l. This report compiles the data and literature that was used to qualify the design and establish performance levels for the Gen 2 skid. This document is to be submitted to Alaska Oil and Gas Conservation Commission (AOGCC) as an "Application Report" to obtain their approval for using the Gen 2 multiphase metering system as an alternative to conventional gravity based test separators for well testing. The "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued by AOGCC, requires operators to submit this "Application Report" before new metering systems are used for production well testing and allocations. Section 3 of the AOGCC document outlines the type of information that the application has to provide. This BPX "Application Report" provides the information that is requested in the Section 3 of the AOGCC document. The Gen 2 in-line multiphase metering system described in this report is based on the infrared water cut detector and sonar flow meter technologies, both developed by Weatherford. The system has been successfully tested at GPB V-pad and provides a metering solution for use in the full range of well conditions on the North Slope. The trial on V-pad concentrated on high gas fraction, gas lifted wells, but with conditions in the liquid-dominated multiphase regime. The ASRC Unit 1 was adopted as the reference device for the test. Confidence in Unit 1 was established through spot sampling of water cut and by comparison to the well pad separator. 2. Proposed Applications The proposed multiphase metering systems are designed to be used either as permanent wellhead installation or mobile systems deployed in a field. Table 1 in Appendix lA shows the wells and production horizons in which BP is the operator or has working interest that may use the proposed multiphase metering unit. This Table also shows the working interest owners. All parties with working interest, royalty ownership, as well as the Alaska Department of Revenue will be notified about the use of the metering system when the application of the metering system affects such interests. The proposed application will use the multiphase metering skids for production allocation. In the event that the proposed multiphase metering scheme does not produce the expected accuracy, we will revert to use the conventional well testing techniques. The allocation methodology currently practiced will continue and would not be affected by the multiphase metering system. 3. System Components and Measurement Strategy The Weatherford Gen 2.0 multiphase meter concept consists of four principal components: 1. A Red Eye 2G near-infrared water cut monitor 2. A Cs 137 gamma densitometer 3. A passive sonar volumetric flow meter 3of11 ~ ~ o-roat~s :~occc c~„z .ap[~ a~t.a„~ 4. A Venturi nozzle differential pressure flow meter The proposed well head field configuration is shown in Figure 1. Figure 2 shows the Gen 2 installation in V-Pad trial tests conducted in January of 2008. Each of the metering components has been previously tested in wet gas and multiphase flow conditions as noted by the list of references. The innovation of the Gen 2.0 meter is to combine the four sensors to enable the optimum measurement of oil, water and gas flow rates across the full spectrum of composition, i.e. from 0% to 100% water cut, and from 0% to 100% gas volume fraction. The field tests reported in this document were performed to confirm loop test results for the Gen 2 meterl and qualify this meter for field application. The sonar and nozzle are integrated into a single spool piece, with the densitometer and Red Eye meters located on downstream spools of restricted diameter (matching the diameter of the restriction at the sonar section); it is the intention that the four measurements will be integrated into a single spool, along with a static pressure and temperature measurement. The Red Eye 2G near-infrared water cut monitor has been extensively tested by a technology program led by the BP Gulf of Mexico (GOM). This has demonstrated the capability of the Red Eye to detect the water cut in multiphase flow streams containing up to 95% GVF with an uncertainty of f5% absolute in the water cut measurement, almost independent of the GVF. A Red Eye has been installed at the UK National Engineering Laboratory (NEL) for nearly two years, undergoing a range of multiphase flow tests.2 One final comment on the Red Eye is that its measurement of water cut is expected to be unaffected by the composition of the water phase, i.e. independent of water salinity. This is because the dissolved salts in the water phase have no effect on the absorption of infra red radiation at the wavelengths usedZ. The gamma densitometer based on the 137 Cs Isotope uses the high energy 661 keV gamma ray. This device can be clamped to the outside of a steel pipe, and at 661 keV there is little composition sensitivity of the absorption of the gamma ray, and so this instrument can be used to measure the density of the fluid mixture across a single path through the pipe, in this case a vertical path. This measured density can be directly related to the void fraction in the pipe. If the slip between the gas and liquid is known, then the void fraction can be converted to gas volume fraction. Note that `high energy' refers to the energy of the particular gamma ray, not the intensity. A high energy gamma ray is required to penetrate the steel pipe walls, but the intensity, or activity of the radioactive source material can be relatively modest, with a source activity of 100mCi more than adequate. The passive sonar instrument consists of an array of strain detectors mounted around the pipe circumference. This instrument interprets the propagation along the array of pressure pulses generated by the turbulence in the flow. This has been demonstrated to work well in a single phase (either gas or liquid) environment, and in a wet gas environment, with the measurement of total velocity (gas + liquid) in a wet gas stream almost independent of the liquid content3, a The tests at V-pad, presented in this report, were conducted in a liquid dominated multiphase stream to compliment the previous work. In this implementation the airay of strain gauges is mounted on a section of restricted diameter. The reduction in the pipe cross section and consequent increase in gas velocity gives an improvement in the ability of the device to measure a velocity in a multiphase flow stream; this velocity is very strongly correlated with the gas velocity. 4of11 ~ • ~~. Finally, the Venturi nozzle is based on a modification of the ISO 5167 standard ISA 1932 nozzle differential pressure flow meter and is included in this configuration order to make a measurement of the total flow momentum and hence mass flow rate. The choice of the nozzle type device over the more conventional Venturi was an attempt to condition the flow profile better for entry into the sonar measurement section, and a slight modification was made to the standard nozzle design in order to optimise the entrance effect of the flow meter area change on the sonar array in the meter throat. This device has been tested at Colorado Engineering Experiment Station and at NEL in wet gas flow conditions. The meter that was tested at V-pad in January of 2008 was 3-inch full bore ANSI 1500, with the diameter ratio (beta) of the nozzle being 0.541. The exact internal diameter at the inlet was 2.62 inch (66.64 mm) with the nozzle throat diameter 1.42 inch (36.05 mm) and the ID of the sonar section 1.58 inch (40.06 mm). Photomultlplier _~ ~~ fibsolute t Line1 Fressixe - - ~~ Differential Pressure ~ Temp~rctture Ju RedEVe 1Natercut Probe _ : .~.~ - Gamma Ray Source Figure 1- Schematic of the Gen 2 Well Head configuration The measurement strategy for the Gen 2 system utilizes the "over reading" by Venturi and Sonar devices, caused by liquid content of the multiphase stream, to calculate the total and liquid flow rates in the multiphase stream. This is accomplished through a model developed for the Gen 2, which then calculates the GVF in the multiphase stream. The liquid density derived from the RE water cut meter and the multiphase fluid density provided by the densitometer, is used to partition the total flow rate into oil, water and gas flow rates at line conditions. The line condition flow rates are transformed to standard conditions through PVT calculations and reported as the output for the meter. Sofll ~ • Figure 2- Gen 2 Installations at V-Pad 4. Field Test Program and Test Results The testing was performed at Prudhoe Bay V-Pad between January 26`h, 2008 and February 6`h, 2008, with 16 well tests completed in this period. Each well was stabilized through the test system for 4 to 6 hours, followed by an 8 hour well test. Table 1 show the wells tested, test time and duration. The fluid properties for these tests are shown in Table 2. The test results are summarized in Table 3. Figures 4 to 9 show graphs of well test results for gas rate, liquid rate, and water cut. In each graph the data from Gen 2 is plotted against the data from ASRC Unit 1 that was used as the reference. The graphs in Figures 4-9 are presented in support of the gas, liquid and WC uncertainty levels for Gen 2 shown in Table 2. These graphs include the error from the reference test separator. 6 of 11 ~ • 070808 .AOGCC Gen2 :tpp RpY.duc Table 1- Summary of wells tested, time, and duration Well T~st dste 7est times Test d~vatian Pnullwe Bap V~ad dri~i+ak) Y-Q~ ~8~ 11Q~ 8Y89~8 v-m a~ -af -aoos aa:oo -~~:oo a t~o~ W~I Q2•D3-7El0Ei Sk:41] - 71:00 £3 hows V-#Yt ~f -28-ZfIfJ~3 t 5:(p - T3:OD 8 ittrurs PrwJhoe Bap Vf~d V-t D4 OZ-05-20D9 24:00 - t15:00 8 hawxs Y' 7 Q2 01-29-2008 t t:OD - 19: W $ hou5 V-703 Ot-29-20f1~ IXI:OD - OC3:53 fiest abandonad Unrt5 ~atu Di -3t -Z{)0~ t 6:CID - ~:FIO $ hoars Y-t {]~B Ot-3D-ZD(k3 40:OJ - O~dQ Urrt l a~d lfar~t'~ assed Ot -3t1-2410B t~:00 - 2f SIO $ fious V-t07 We~ nd testad Y-t4E3 Q2-U4-20(k3 tl4:00- 12:00 8 hwas V-149 We! not tested V-t t t OQ-{Yi-2D41B 18:Q0 - 9Q:Of1 8 riours Y-t t3 01-2$-2E1K~3 16:OD - t9:t 5 FP2S t~sp - t~st ~a~xia~ed Ot-27-Zt7t~ 12:QE1- 2flt~~ $ haress V-t i7 Wa6 nat avaaiab9e V-171 02-K]5-2~1{k3 Ofi:O~ -1611fl $ ho~as Pn~dlwe Bay V~+ad (Sclrader 81ufry V-2U2 d2-C11=Z006 Ob:OCI - f3:iX! S hovs V 3U3 01-28-20{k3 U2:OD - i0:04 $ haus - f)'2-02-2008 t2:Ofl-20t10 ~hours Y-203 02-Qt -ZQ~3 20:d4 - fl4:00 8 h~wrs Y-'Lt~'i 02•tCi-20f18 0{:00 - fl9:0~1 £3 hous Table 2- Well Fluid Properties for Gen 2 Tests Gas Oil Water Formation/Well Density Density API Viscosity Density SG at 60 F cP at 60 F .886 14.1 @ Ivishak/V-04 0.882 g/cm3 28.2 68 F 1.013 g/cm3 .939 117 @ 66 Kuparuk/V-111 0.8 g/cm3 19.2 F n/a .938 273 @ 68 Schrader Bluff/V-204 0.75 g/cm3 19.4 F 1.014 g/cm3 Table 3- Summary of Gen 2 Measurement Uncertainties (RMS average values) Meter Measurement Uncertain Relative to ASRC Unit 1- % Gas Rate Li uid Rate Water Cut Gen 2 f7 f8 t5 V-Pad Se arator ~9 f14 f9 Estimated Reference Uncertain ASRC Unit 1 f3 f5 t2 7of11 ~ ~ 070SOR :#OGCC Gen2 ~~pj~ Rpt.cluc ~mo ~ .~-. ~ g ~~ ~ ~ 3°0° $ 2sao C a ~~ 0 ~1 ~sw c ~ taoo ~ 0 -- --~- - ~, -' • /iFfC~nSU~tt:;kfAM: . ~ ^ V~FTGe~..t~pE.s;lfufarl, ~ ~ • nRGCn~.tipil,58Nitles.@ut( . _ _.~..5#s ~~ . . --- .~.,~., _ __ _ _ ~ ~ ~.~ ~~ %~, ` ~ ~ .._ - 4 ~ s-. i~ ' `"~ ~ ~~ .-t~~ - ~~* ~~ . , ;s k•- ` r `.-. ~ 0 5CD 1000 150D 7qq0 1l500 3Q0p 35pp 1~[! I9pp yf~p Uni 4 gas flow-ate (MscfldJ Figure 4- Gas flow rates from Gen 2 ~ <IDis ~ 3D'R ~ ~ ~ 4 iDi O ~' C ~ - iGK 4 N -~: e ~ -3oa: r.;~ .~ ~ • yt&'NfT6arr:9C~e9aifel}. ... .. ~. ^ @ttvlfFT,'te~~:.9~11tu•uUj ~. ~~~ • 9t&~HFTL.m.i~ yac ~9ensarr_OLri; ~ . - _.,_ ge, . ~~' .x. 7;N . '______-~____~___'___'___'~_______________'~ ~`--~ =~: ~ --_____ _ - _ - _ _ _ _ _ _ _ _ _ ~ _ _ ' _ ' _ ' ~ ~~_ - _ '__ ~_ _ _ ~_ _ _ _ _ ~ __ _' _' _ ~i ~ • ~___ _ • sa sa 5o es m tS ec as aR as ~m Unit 1 GVF ~9L) Figure 5- Gas flow rate accuracy as a function of GVF ~ ~ Q ~ ~ O W ~ 7OfD O C ~ 7~ 15GiQ 4 N ~~ CY O 900 0 ~ 4 • YIFTGtn'[:~~uclS4.tnY. _ : ~ NFTCftI.:.b~pufrRUF+~~1; ... '.,~. " • VdTb[f.,'Vlqtdp,5(pt}tltl-64i{ ' . ~ ~~} 4'N ~, _ . ~~~ y i'uin . .._. . ... ... .. .' - .~ ~,~... .' ,..,"~~~' . ~' A.. ~':.~~~. ~~' ~ .. 900 t00D 1500 ZL106 15GD ' 00 76GD Unit 1 liquid flowrabe ( amtd) Figure 6- liquid flow rates from Gen 2 8of11 • ~ o~asos :~oc,cc c;E~~2 .api~ xQt.a~~ ~ 909i '~! 7~t L' 'lO9S Y ~ 7qAi ~ $ Q Q4~ 9 .Q "tox 0 ~ -~ n -~ -~OVs .gD~ . ... • 51H+V~FtUtn:P Waotnet.a; , ^ 9tB+MFTCSM:.Aki~(tliKuWUi; ~~~. .. • Bl8/hFTSM~.`U~9~bi&/~1auM:81i1; , ~ ~H. ?i ~~~ tl. ~~ '-____~~____~___'___'___'_______~___~_-_'___'___'~-_ •__ ___ _ _ ~ ~ _ _ _ _ _ _ _ ~ _ _ _ _ _ ' _ ' _ ' _ _ _ _ _ _~. _ ~ _ ~ _ • - _ _ ~ ~ _ _ - _ _ ~ _ _ _ _ _ _ ' _ ' _ ' _ -Lr--_rt_-_-_ w ------------------------------------------------- ---°~--~----- • °A S6 BO fi6 70 75 !0 !6 90 64 100 Un~ 1 ~VF E!4) Figure 7- Liquid flow rate accuracy as a function of GVF. The Schrader-Bluff "out of bound" data is believed to be due to the over-reading of reference (ASRC Unit 1) under the flow conditions. ,~ ~'A 80A ~ ~1 a ~ ~ ~"u 5~ 3 q ~ N yC v ~ 3Q96 iQ% Q~ . ^ ' '` • YJFT;3tl~::Jw`mIX{~I:MIfNb.~.. . , ~~,,~~ ~ ~~ ^ i i+iTfs~;C+w~t~;K,~c.rLL3 ~~~. ~ • +'YfT3m,.:~w~atttu9&ns7er.BUlI; ~ , . ~ : . ,.. ~ ~ M" ~j{ S J ~ ~,-'~~ - • : y • ~ ! " ,..,:.!' . ~ 0% 704s 2CI)> ~% p~G SO~ ~'# 70iK 1%1% 90fi. 10Q96 Unit 1 watar cut pfG) Figure 8- WC measurements from Gen 2 9of11 • o~oxas :aoc:cc c~t~,z App Rpt.doc ~ ~ ~ a ~" ~ ,~ 3 ~ ~ a 'Z -104+ q N C -2D~6 ~ .~ ~ . . ~ _ ~ _ ~ _ _ _ ~ _ _ ' _ ' _ ' _ : _; ~ _~ _ ~ _ _ _ ----- • _-_-_~_~_~_~___~'_'_'____~_~ _.~_~_ _~ _5pq ~ • Y/FTLtn ~YA/6[4utif.~iY1; , ^ IHFSfihn:9aWlltu~iKWNU~,= . • ~iFTfirn:.dwAertu]i&btibr-8i.t!# ~~. ~~. - '.t 5x. _' - •T, _. .u i~ ao E6 'AD 86 700 Un~ 1 GVF t%~ Figure 9- Gen 2 water cut accuracy as a function of GVF 5. Factory Acceptance Tests (FAT) The following factory acceptance tests will be conducted prior to field installation: • Hydrostatic pressure testing is performed according to the meter's pressure rating. • Liquid and gas flow rate tests will be conducted to check the performance of the meters. The test conditions will be guided by both the operating constraints of the test meter and of the flow facility. • A single-phase (water) calibration of the sonar array and a verification of the nozzle discharge coefficient are conducted. Due to well behaved Reynolds characteristics of the Sonar meter and documented properties of the Venturi nozzle, the single-phase water calibration has been found sufficient. • The Red Eye probe is calibrated on air as well as pure dry oil and produced water samples. Air calibrations are unique for each Red Eye unit. 6. Field Maintenance and Periodic Calibration The following items will be checked periodically: • The PVT tables would be updated monthly or as necessitated by operations to match a revised fluid characterization derived from representative field samples. • Correct operation of the primary devices will be tracked yearly to detect any offset (e.g. due to fouling). Establishing single-phase flow through the meter for a basic cross check between the nozzle and the sonar array provides the necessary primary device diagnostics. • Empty pipe calibration required as necessary for the densitometer. • Radioactive source site requirements - wipe test every 6 months. • Periodic calibration of DP/P/T transmitter. • Expected replacement of Red Eye monitor after 5- 7 years. 10of11 • ~ (i7080Fi AOGCC' Gen2 App Rpt.doc 7. List of References 1. "A PROTOTYPE WET-GAS AND MULTIPHASE FLOWMETER" E. S. Johansen (Weatherford Intl.), A. R. W. Hall (BP Exploration & Production),~. H. IJnalmis, D. J. Rodriguez, A. Vera, V. Ramakrishnan (Weatherford Intl.) ,25~' Intemational North Sea Flow Measurement Workshop 16`~ - 19~', October 2007. 2. "Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions", Andrew Hall, BP Exploration & Production John Lievois, eProduction Solutions, Babajide Adejuyigbe, eProduction Solutions. 6~' South East Asia Hydrocarbon Flow Measurement Workshop7th- 9thMarch 2007. 3. "Wet gas metering using sonar-based flow meters and piping pressure loss gradients," Gysling, D.L., Loose, D.H., Morlino, N. and van der Spek, A., 25~' International North Sea Flow Measurement Workshop, Oslo, Norway, October 2007. 4. "New class of ineter solves old problem impacting well test accuracy," Ward, E., SPE paper 100893, 2006 SPE Western RegionaUAAPG Pacific Secrion/GSA Cordilleran Section Joint Meeting held in Anchorage, Alaska, May 2006. 8. List of Appendices Appendix 1- Fields, Pools, and Wells Appendix 2-"A PROTOT'YPE WET-GAS AND MULTIl'HASE FLOWMETER" 25`~ Intemational North Sea Flow Measurement Workshop 16~' -19`~, October 2007. Appendix 3-"Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions" Appendix 4- CLAMP-ON, SONAR-BASED VOLUMETRIC FLOW RATE AND GAS VOLUME FRACTION MEASUREMENT FOR INDUSTRIAL APPLICATIONS Appendix 5-"New class of ineter solves old problem impacting well test accuracy," 11 of 11 Appendix 1A Table 1- List fields, pools and wells affected by this proposal Working interest, royality interest, and tax treatment for leases noGCC _ Alaska Prope rty Ownenhips Proeeasing Fadlily naaami Partldpating Area Badami Pool Code AOGCC Pool Dasc~iptlon ~Ot00 Badami Royalty Rate % ELF BP Expbration Chevron Conoeo Phillips Euon Mobil D oyon Ltd Nana Unocel Anadarko Murphy Tofal 125%to1867% Sepa2te 700 Entlicott Eider 220165 Ivishak Undeflned (Eider) 12.50% Separate 100 ~~ Entlicott Endicott Endicott Sag Delta North 220100 220150 Endicott Sag Delta North 12.5% ro 20% 1 Separate 67.9221 0.0234 21.0206 0.1291 0.3874 10.5174 ~~ ~pp 2.5% to 20% Separete 88.1327 0.4668 1.4005 ~pp ~PC LPC Niakuk Tred Operations 840148 640147 Niakuk GPMA Ivishak-Seg River ~ 12.5% 12 ConsdidatedNiakuk 26.360567 7.16 36.078746 36.402887 ~~ ~~ LFC West Niakuk 840149 Niakuk, Undefined .5% 12.5% Conadideted Niakuk Conaolidated Niakuk 28.380567 1.16 36 076746 36 402687 Q ~~ North Prudhoe Bay State 640152 Nath Prudhoe Bay Sfate 12.5% Separate 26.380567 1.18 . 36.078746 . 36 402687 ~~ LPC & Piudhoe GC-1 Weat Beach Lisbume 640186 840144 Weat Beach Llsbume 72.5% Separate 26.360567 1.76 36.076746 . 38.402887 ~~ ~~ 12.5% Separate 26.360567 1.16 38.W6746 36.402887 ~~p Milne Point MPU Kuparuk 525100 Milrre Polnt Kuparuk 12.5% to 20% Separate 99 425789 Milne Point MPU Sag River 525150 Milne Point Sag River 12.5% to 20% Separate . 98 741072 0.574231 100 Mllne Point MPU Schrader Bluff 525740 Milne Point Schreder BIuH 12.5% ro 20% Separate . 99289596 ~ 256928 ~00 Milne PoiM Trad Operadons 525160 Milne Point Ugnu, ~~deflned 12.5% Seperete 100 0.730404 100 ~~ Northslar Northstar 590100 NoAhstar 20% plus supplemental Separete 98 5772 . ~ 4~8 ~~ LPC 8 Prudhoe GG1 Prudhoe All GC & FS PaM MWnlyre P dh 840180 Paint Mclnlyre 12.5% W 18.8~% Cmredidated Prudhoe 26.360567 1.16 36.076746 36.402887 ~Qp Prudh GGt ru oe IPAs (ORIGC) Mi 840150 Sadlerochk 12.5% ConsoNdated Piudhoe 28.380567 1.78 38.0767q6 38.402687 ~ oe Prudhoe GG2 dnigM Sun A 840158 MidnigM Sun, undeflned 12.5% Consolidated Prudhoe 26.360587 1,16 38.076746 38.402887 pp ~pp Prudhoe GG2 urora B li 640120 PBU Aurora, Undeflnetl 12.5% Consdidated Prudhoe 26.380567 1.16 36.078~46 36.402867 ~pp Prudhoe GC-2 aea s O i 840130 PBU Borealis, Undefi~ed 12.5% Conadidated Prudhoe 26.360587 1.16 38.076748 38.402887 ~p~ Prudhoe GG2 r on Pdaris 840135 640160 PBU Orion, Undefined Schrader BIuB (Satellite) undefined 12.5% 12 % Consolidated Pnitlhoe 26.360567 1.16 36.078748 38.402687 ~pp , .5 Consolidated Prudhoe 26.380567 7.16 36.W6746 36.402887 ~~p ~ ~ G.Benson . ~ a a ~" a ~ R , ~ ~ e x' ~ ~ ~~'~` _ ~~~ ~ ~~~ -~~~ n : n . ~ A ~ a ~ L } o ~ ~~ _ 8 e ~ ~ ~~ ~ ~ ; . e~~ €~T ~ ~ y ~, ~ ~ ~ ~ ~ ~F ~ ~ ~ r', _ \ ..,~-..-~ _ . . y , 3 ~`~' t -~- ti -~'r • ~ ; - ~~`~, ~ ~ . ~f ~a ~-" fi ~ ~~ - ~ ~ ~,~ - f . l~ ~ ~ .. 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J~COBS LMDER UNR •nMnko 50.0% eGUrt. ~o.ax e~onriuxrt '~ -_ ~ ~ - Ji~ ABRC 10.0% p~0AMI5~NO8P~ A" Appm~ ] MIY~ Eut ~RGtIC FORTITVOE UNR ~ ~ ~(' ~ BP EaD~a~b~ 100-0% J.A. VfiHS 700.0% ~ r i .~~ ~ ~~~~1~~~ ~ ~ ~ ~.s.~~_ ~-,~~~,~~, PhY~ ~ ~ . - ~ v' ~} --- .~ p.unnl. . U ~YUxI .I.'. ... ~ F~ (~~ MdincU S.IM;o~I~BbIn.sWln..r.n~~.. . . ' )"^~ ~~ ~~' fA ~ ~ 25~' International North Sea Flow Measurement Workshop 16~' - 19~' October 2007 A PROTOTYPE WET-GAS AND MULTIPHASE FLOWMETER E. S. Johansen (Weatherford Intl.), A. R. W. Hall (BP Exploration & Production) O. H. Unalmis, D. J. Rodriguez, A. Vera, V. Ramakrishnan (Weatherford Intl.) ABSTRACT A wet-gas flowmeter based on the field-proven downhole fiber-optic multiphase flowmeter has been developed. The flowmeter is based on an extended throat Venturi-nozzle and a Sonar flowmeter. This combination exploits the characteristics of these two devices in wet-gas flows. For the Venturi, there is a well-defined and large over-reading with increasing liquid-loading, whereas this has a significantly lower impact on the total flow rate measured by Sonar. The Sonar-Venturi wet-gas flowxneter has been in development over the past several years and has been tested extensively in industry flow loops. Particular emphasis has been placed on developing a flowmeter with a broad operating envelope that includes a large span of fluid properties, a high turndown ratio, and well characterized response both within and outside its intended operating envelope. The wet-gas performance has been demonstrated at the recently cornmissioned CEESI 3 phase wet-gas flow loop, yielding total and gas flow rates better than f5%,* liquid flow rate better than f0.5 m3/hr in Type I wet gas,' and better than f20% in Type II wet gas. A Red Eye 2G near- infrared (NIR) water cut meter is used to differentiate the oiUcondensate a.nd water. The Red Eye 2G has field proven performance in low gas volume fraction (GVF) flows for full range of water cut. A prototype version has demonstrated f5% water cut uncertainty in high GVF multiphase2 flows and initial testing of the Red Eye in wet-gas flows is showing great promise. The wet-gas flowmeter was also tested at the NEL multiphase flow facility to evaluate whether the measurement capability could be extended beyond the wet-gas envelope. Although the performance in low-pressure multiphase flows did not match the performance seen in high-pressure wet-gas flow, measurement capability was maintained and reasonable performance was demonstrated for the entire range of GVF. INTRODUCTION Test separators and portable well testing services are the most common technologies used to generate a measurement snapshot, typically every 30 days, but often less frequent. It is, however, widely accepted that real-time individual wellhead production monitoring is an effecrive tool to monitor the health and maximize the performance and ultimate recovery of producing oil and gas wells. Measurement technologies have been developed to monitor individual wells in real-time; however, the high cost has generally limited the install base to prolific wells or multiple wells multiplexed with multi-port selector valves. Furthermore, many are being used as mobile well- testing devices. Other factors complicating wide implementation include limited operating envelope, fragile mechanical and sensing characteristics, and sensitivity to changes in fluid chemistry or composition. To date, only a few meter types claim to operate both in wet-gas and ' All performance numbers quoted herein are relative measurements with 95% confidence interval, unless otherwise noted. ~ ~ multiphase regimes. Most other wet-gas or multiphase meters may report highly erroneous results outside their intended operating range. Therefore, as wells mature with increasing gas fractions and water cut, the flow measurement conditions at the wellhead necessitate flowmeters with a wider operating envelope and a lower sensitivity to compositional changes than is available today. The Sonar flowmeter technology platform offers the potential for a cost-effective and robust flowmeter with a broad operating envelope that may bridge the gap between traditional multiphase flowmeters and high gas-fraction metering. Sonar flow measurement is derived from the field- proven downhole fiber optic multiphase flowmeter.3-5 It is non-intrusive, has no wetted sensors and offers excellent resilience to erosion and corrosion. Sonar flowmeters offer accurate and repeatable flow measurement with a small and well-behaved Reynolds number dependence and a large turndown ratio. Sonar can measure liquid and gas flows with no changes in hardwaxe or software. The conventional types of differential pressure meters (e.g. Venturi, cone or orifice plate meters) still remain the flowmeters of choice in the vast majority of gas wells. The over-reading of such devices when there is liquid in the flow stream is well understood and documented in literature.6'~ However, the liquid content can be very difficult to estimate and hence correct for in the field. Consequently, the erroneous readings must be corrected by back allocation. Sonar tends to have a very well-behaved and low over-reading with liquid loading in wet-gas flows. The combination of a differential pressure meter with a Sonar flowmeter therefore offers an over-reading contrast that is exploited to yield the total and gas flow rates and the liquid content. FLOWMETER DESCRIPTION The Sonar-Venturi flowmeter is a combination of a Sonar sensor array located in the extended throat section of a Venturi-Nozzle, shown in Fig 1. The higher mixture velocity in the throat is favorable to the passive Sonar array as it improves signal to noise ratio and enhances mixing. The Sonar flowmeter consists of an array of electronic strain gauges (non-fiber optic) combined with fully integrated data acquisition and processing electronics housed in a spool-mounted enclosure. T'he prototype flowmeter also employs a multivariable pressure, temperature, and differential pressure transmitter for the Venturi. The flowmeter also includes Modbus and diagnostic communications over RS 485 and Ethernet. The entire assembly is powered by 12-36 VDC, consumes less than 10 W, and is Class I, Division 1 compliant. 2 i multivariable transmitter ~ Sonar data acquisition and processing eleatronics flo-~ Figure 1- Sonar-Venturi flowmeter schemaHc. Sonar Flowmeter Turbulent pipe flow contains self-generating vortical structures that convect with the fluid. These vortices remain coherent for several pipe diameters, and they decay as they convect through the pipe. Meanwhile new vortices are continuously generated by frictional forces acting between the fluid and pipe wall and within the fluid itself. An array of circumferentially mounted and axially distributed pressure sensors measures dynamic pressure fluctuations associated with the convecting turbulent eddies. The convection velocity is calculated from the unsteady pressures by array processing algorithms. The volumetric flow rate is directly proportional to the convective velocity measured by Sonar and a single Reynolds number calibration yields a flow rate for liquid or gas. with an uncertainty typically better than ±1%. The calibrated performance of the Sonar meter in single-phase (oil, water and gas) is presented in Fig. 2. A Reynolds number "turndown" of nearly three orders of magnitude is demonstrated for six different fluids at three different test facilities with no change in the three calibration constants. The calibration values are also consistent with what is typically seen in a fiber-optic flowmeter. In wet- gas conditions, the calibrated Sonar velocity yields a volumetric flow rate that is slightly higher than the actual mixture velocity. The over-reading of Sonar is well behaved with respect to liquid loading and is readily correlated with the Lockhart-Martinelli parameter. Venturi noule Sonar array ~ ~ 5% 4% 3% ~ ~' 2°/a ~ O ~ w ~ 1% w 3 °~~ tL ~, o~a m ! a m `2~~0 ~ -3°/a -5% Venturi ~ NEL-Brine • NEL-Oseberg ^ NEL-Nitrogen O Weatl~erford Water O WeatherfoMy4ir A CEESI-Natural Gas •-•- t 1% ------,---~-~--~--~----g---------------- ~~----------o-.._...._........------------------ ~. °• ~ • o g g .~ 4~ ~ ° n ~ o """"""""""""""""t""""""""""""" ........ ........"""""'""""' -d% 1.E+04 1.E+05 1.E+06 1.E+07 1.E+08 Reynolds Number, [-] Figure 2- Baseline Sonar performance over broad Reynolds number range. The extended throat Venturi-nozzle performance was verified with the same da.taset and was found to measure single-phase flow rates within f 1.4%. T'he Venturi behavior is well described in literature. Tests conducted with the Sonar-Venturi combination throughout single-phase, multiphase, and wet-gas flow were consistent with published values of discharge coefficients. The turndown ratio of the differential pressure sensor is 84:1 from the multivariable transmitter specification sheet. In practice, the wet gas differential pressure on a horizontal Venturi-nozzle was observed to depart from the deLeeuw correlation at pressure turndown ratio of 30:1. Since ~P is proportional to VZ the velocity turndown ratio for the Venturi-nozzle is at best 9:1 and, in practice, it can be as low as 5:1. Thus, in terms of flow velociry turndown, the performance of the Sonar meter far exceeds that of the Venturi-nozzle. Water Cut Meter The Red Eye 2G water cut meter is based on the principles of spectroscopy and relies on the large difference in the absorption of near infrared (NIR) radiation between oil and water. Differentiation is achieved by operating over a very narrow band of radiation with maximum intensity occurring at wavelengths where crude oil and water exhibit large differences in opacities. The Red Eye measures transmissions at multiple infrared wavelengths simultaneously and calculates the water fraction from the ratio of attenuation at different wavelengths. The technique operates consistently across the full range of 0% to 100% water cut, and is effectively insensitive to free gas. 4 ~ ~ 100 90 ° 80 e ~ 70 ~ ~ '~ 60 ~ Q J 5Q w 3 ao m ~ 30 w g 20 10 0 - - - t 5~o absolute error , ~ o Red Eye 2G, NEL, Aug 2005, Ho~izontal o Red Eye 2G, NEL, Aug 2005, Vettical o~ 0 'o ; J.. 0 10 20 30 40 50 60 70 80 Reference Water Liquid Ratio, [%] Figure 3- Performance of water cut measurement Z 15 e 0 ~ 10 E 0 ~ 5 .o :.°. ~ ~ 0 w ~ -5 'a .~ Q L -1O m .. R 3 -15 - - - t 5% absolute error a Red Eye 2G, NEL, Aug 2005, Horizontal e Red Eye 2G, NEL, Aug 2005, Vertical 90 100 n , ° n o , ~ o ----------------------o--a--~--o-o ---so -A-'~---- o ° e o m o e 0 0 0 0 e o o ° n n e o ~ op ~ o or.u~ n °b o 0 o~~ ~~~ e o o ~ooo on --------------- ------ 0 0- - ----- o ---- ---- o Q 0 0 0 10 20 30 40 50 60 70 80 90 100 Reference Gas Volume Fraction, [%] Figure 4- Performance of water cut measurement for wide GVF range.Z Data shown in Figs. 3 and 4 range from 10 to 95% GVF at low pressures.2 Even those points at the highest GVF do not constitute wet-gas flows with Lockhart-Martinelli ~parameter significantly higher than 0.3 (due to the low pressure and high liquid/gas density contrast) . However, recent tests conducted at CEESI show very good sensitivity, correlation, and measurement capability in wet-gas flows at GVF up to 99.9%. The water cut measurement has been verified in separate studies and the remainder of the discussion in this paper will focus on the ability to measure liquid and gas flow rates by the Sonar-Venturi combination. 5 • ~ TEST ENVELOPE The flowmeter was tested at NEL (multiphase) and CEESI (3-phase wet gas) in August and September of 2007 respectively. The CEESI tests were conducted in the recently commissioned 3- phase wet-gas flow loop. ~ o0 10 E ~ 1 - O m > ~° 0.1 - ~ a ia ~ o.o~ a ~ ~ 0.007 '- 0.0001 - 0.7 o NEL 0 0 ~ o n CEESI g ~ o~o ~O o8~ ~ d - o ~ GVF8.1% ~o~ ~ i0~ ~ ~'o~~ " Booe ° Op~ ~ GVF 50°~ ~ • ~ . a n GVF 90.9% ~ ~ 0 s e-_ o • ~ g GVF 89.0% ~ e n a ~ e GVF 99.9% 0 GVF 99.89% 7 10 700 Supe~ciai Gas Velocity, [m/s] Figure 5- Phase superficial velocity and GVF variations for NEL and CEESI test matrices. Figure 5 shows the entire test matrix for both facilities in terms of supe~cial liquid and gas velocities with no-slip GVF as isolines. From this view, it appears as though the two tests overlap, however, the test pressure at NEL ranged from 2 to 7.5 bar, whereas the test pressures at CEESI ranged from 14 to 55 bar yielding very different liquid/gas density contrasts (see table below). Consequently the high GVF points in the NEL test matrix are not representative of wet-gas conditions because the relatively low gas density results in a relatively low gas Froude number, Frg and a relatively high Lockhart-Martinelli parameter, XLM. The CEESI test envelope, on the other hand, covered Frg and XLM within the regions defined by API as Type I and Type II wet-gas flow.l CEESI NEL Pressure 14, 28, 55 bara 2- 7.5 bara Tem erature 28-35 °C 22-42 °C WLR 0-100% 1, 40, 75, 100% GVF no sli 97.5-100% 0- 100% Total Volume Flow Rate 85-655 m/hr 14 - 460 m/hr Liquid/Gas Density Ratio 16 at 55 bara 40 at 28 bara 98 at 14 bara 106 at 7.5 bara 485 at 2 bara Fr Sonar 1.5 - 20 0.07-2.6 Fr Nozzle 0.5 -5.5 0.02.-0.7 XL,~, 0 - 0.26 0.3-167 LM 0 - 0.72 0-1 6 ~ ~ WET-GA5 TESTS CEESI Test Facility The CEESI (Colorado Engineering Experiment Station, Inc.) wet-gas facility, originally built in 1998, was designed for two-phase flow studies consisting of natural gas and hydrocarbon liquids. The loop has been recently redesigned for three-phase operation. Figure 6 shows the block diagram of the three-phase wet-gas loop used for the current tests. CIRCU'_ATI~N ~ HEAT I I IC~ALESCING~ TURBINE I I ULTRAS~NI( COMPRESS~RS EXCHANGERC-~I FILTER METER n METER I I I I GAS CHR~MAT~GRAPH TRI?LEX 2~ 0,5' PUMPS FOR CORIOLIS C~RI~LIS METER METER HYDR~CARBON GAS-LIQUID LIQUID SEPARAT~R LIQUiD-LI'~UID SEPARATOR ~__J TRIPLEX ~~ 0,5" PUMPS CORIDLIS C~RI~LIS FOR METER METER ' WATER TES? TEST TEST TEST TEST _OCATILIN 5 LOCATION 4 L~CATICN 3 LOCAT:ON 2 L~CATION 1 Figure 6- Block diagram of wet-gas research loop, 4-inch test line Both a turbine meter and an ultrasonic meter measure the flow rate of the natural gas. The difference in mass flow rate between these two meters is monitored; if the difference exceeds a specified amount, the data. is scrutinized for detrimental effects such as pulsation. If the difference is within tolerance, then all other meters installed in the research loop can be compared to the natural gas mass flow rate as measured by the turbine meter. Pressure and temperature measurements at various locations on the loop (including the test locations) are used to calculate local gas density. The hydrocarbon liquid and the water, which reside in the liquid-liquid separator, can be injected into the gas stream by positive displacement pumps (Triplex pumps). Coriolis meters measure the mass flow rate and the density of the liquids to be injected. The gas stream carries the liquid mixture through the meter test locations and on to the horizontal gas-liquid separator where it is then returned to the liquid-liquid separator. Stability of liquid density, gas composition, pressure, temperature and flow rate is monitored to determine steady state conditions. During each test point, a gas chromatograph obtains a sample of the natural gas on a 6-minute time interval. Using the average natural gas composition during the test point and the measured pressure and temperature at any given location in the test loop, the gas density at that location is determined using AGA-8. The composition of the gas has some seasonal variation with the methane composition ranging from approximately 83% to 95% during the year. The hydrocarbon liquid (ExxsolTM D80) is very similar to kerosene with less than 2 ppm sulfur. 7 ~ ~ ~ ~:.. /' _~ r~, ~ ~~ :~ ,# _z~ :~~;r":7~ Figure 7- Sonar-Venturi flowmeter installed vertically in flow loop. Figure 7 shows the vertical installation of the Sonar-Venturi flowmeter in the 4-inch wet-gas flow loop. The flowmeter was mounted immediately downstream of a blind T. Measurement Contrast The flowmeter has two independent measurements - the Sonar velocity and the Venturi OP. It has been established (as evidenced in literature and through tests at multiple flow facilities by the authors) that both instruments measure dry-gas flow-rates very well. In wet-gas flow, it is desirable for each instrument to have an over-reading that is dependent primarily on liquid loading and minimally on other flow parameters such as gas Froude number and line pressure. A modified version of the de Leeuw correlation (developed for horizontal flows) was found to work very well and has been adopted for the Venturi. The basis for the Venturi over-reading (ORV) and subsequent correlation is O p V _ Qg.appuren~ ~ ~ ~ [\ n ~ `Gg,r¢f Wlth ORV = f, (X, Frg ) , (2) where the Lockhart-Martinelli parameter is defined herein, as: X = "-'' p~ . (3) mX P~ 8 ~ ~ The over-reading correlation for the Sonar meter (ORS) was established based on the measured flow velocity and the liquid mass quality (LMQ): ORS = Q~,~~ren~ ~ ~4) Qt,rej Qt,apparent VmA ~ ~5~ ORS = f (LMQ, Frg ) ; (6) LMQ = m~ ~ ~~) mt where Vm is the Sonar mixture velocity after applying the Reynolds calibration. A necessary condition for solving for both unknowns (i.e., total flow rate and liquid loading), is to have two independent equations that characterize ORV and ORS. A convenient way to quantify the independence of the over-reading characteristics is to depict the contrast (i.e., difference in slope) of both over-reading trends. The apparent nozzle gas flow rate and the apparent Sonar bulk flow rate were divided by the reference total flow rate and plotted against XLM in Fig. 8. The contrast between the two trends is what allows for a successful iterative solution for the unknowns. 1.35 1.2 1.3 1.25 :~ ~ .. 0 ~ 1.15 ~ c ~ 1.1 A a ~ 1.05 1 o e ~ -_.--------- °n .,~__~~-------- -o~ e~ 0.95 o Nozzle n Sonar 0.9 ~ 0.00 0.02 0.04 0.06 0.08 0.10 Lockhart-Martinelli, [ ] 0.12 0.14 Figure 8- Difference in slope between the over-reading trends of Sonar and Venturi reveals the contrast between the two devices in wet-gas flow. 9 ~ ~ 70% m ~ 5% 3 0 LL i0 ~+ H C 0% ~ t W m > :+ d -5% ~ -10% a 14 bara 0 27 bara + 55 bara --•••t5% ••-•••••••••-••••••-••••-•-•-••--••••••+ -......•-•-••••••...••-•-••••--••-••-••-•••-•--••-•-•... + + ~ + }+ # t + + ++ t # T 0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2 Lockhart-Martioelli, [-] Figure 9- Total tlow rate relative error for wet gas. Figure 9 shows the total flow rate relative error predicted over all test pressures for the Sonar- Venturi flowmeter. Total flow rate is predicted well within f5% for the test points across the full range of Lockhart-Martinelli parameter tested. The gas flow rate relative error is shown in Fig. 10. As expected, the gas rate performance follows the total flow rate since the liquid content by volume is negligible for a majority of the test matrix. ~ o~~o m ~ 5°h 3 0 a w ~o t~ c p"/, .t W N > 'i+ ~ `S~~O ~ -10% 0 14 bara n 28 bara + 55 bara •-•-•~t5% -•---• ...............••-••••-•--•-•••••a..-••••-••-•-••-••-•••-•••-••••••••••••-•••••--•-----...._ + + °+ ~ ~ ,* o + ++ + # 0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2 Lockhart-Martinelli, [-] Figure 10 - Gas tlow rate relative error for wet gas. 10 ~ ~ 40% 30% d 3 20% 0 ~ 10% 3 Q c 0% ~ O W -10% m > ~ -20% ~ -30% -40% 0 14 bara n 28 bara + 55 bara •-••-• + t 20% . . ..................••••-•••••-•••---................. # + ~ ~ $ g ~ $ + + ++ +~+ .* + •-••-•-•-••-•••••-•••-••-•••--•--.......••••-•••-••-••••••-I + + 0.02 0.04 0.06 0.08 0.1 0.72 0.14 0.16 0.18 0.2 Lockhart-Martinelii, (-] Figure 11- Liquid flow rate relaNve error for API Type II wet gas. Figure 11 shows the relative error in liquid flow rate for API Type II wet gas, defined by having XLM > 0.02. The dashed lines show that most of the points are contained within a f20% relative error band. Figure 12 shows the error in liquid flow rate for API Type I wet-gas flows, where XLM < 0.02. In this case the data has been presented in absolute terms and is shown to be within f0.5 m3/hr. 7.0 t E ~ 0.5 OC 3 0 LL C' ~.0 J c .` 0 W w -0.5 ~ 0 w .c a . ___ 0 14 bara n 28 bara ' + + 55 bara •-•-•t 0.5 m'/h •••.......•••••••.......••••••••....... ..._..._... f-•••.••.......••-•-•-••-••••-•• ................ + + + + + + +~ + + + + t ~ +~ f' ++~' + ~ t + pp t + + + o + + ....--••••••••••--•--•-•-••••-••--•-••••....-•-•-•••-••----•-••-••-•-.._...•-•••••-•••--~t•••••... -~.o + 0 0.005 0.01 0.015 0.02 Lockhart-Martinelli, [-] Figure 12 - Liquid flow rate absolute delta for Type I wet gas. 11 ~ ~ 1.5 L 7.0 ~ E « 3 0.5 0 LL a 0.0 J C .` w` -0.5 :: ~ 0 ~ Q -1.0 -1.5 0 97%<GVF<99% ~ 89%<GVF<99.6% I p 0 + 99.6%<GVF<100°/u ; ' ---t0.5m'/h ~ ~ dF pp 4 ------ ° --- --------- ------------- ------ ' #------------- E 0 + ° ~~ ~ ~ o ~ ° 4 i~ t + ~ ~ t # t +} +p ~ ~ ~ ~ ---~------ ----------- ------ ~------ -----------------------~ ~ o ~ o I a a 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Water cut, [-] Figure 13 - Error in liquid tlow rate prediction vs. water cut. Figure 13 shows the effect of water cut on the measured liquid flow rate demonstrating that there is no discernable effect of liquid viscosity and to a certain degree density. MULTIPHASE TESTS The Sonar-Venturi is primarily designed for wet-gas flow; however, it was also tested at NEL to evaluate the performance in off-design conditions. An extension of the wet-gas iterative solution described above was devised for resolving the liquid and gas flow rates under multiphase flow conditions. While analogous ORS and ORV concepts are used in characterizing the multiphase response of the single phase devices, the definitions of these quantities as well as their correlating parameters are different from the ones used for wet gas. The ORV in multiphase flows follows published methods and is analogous to variations in discharge coefficient in multiphase flow conditions.8'9 The 5onar over-reading was characterized in a form similar to the wet-gas methodology. No refinement was attempted for this first evaluation of multiphase performance and no effort was made to asymptotically match the multiphase and wet-gas models. 12 • ~ 1 ~I ~ ~ ~ ~-..~. ~ ,.~~- ..~i Figure 13 - Sonar-Venturi tlowmeter at NEL multiphase test facility. The gamma densitometer in picture is for R&D only and has not been used in the Sonar-Venturi flowmeter calculations. The results were categorized using three gas volume fraction (GVF) ranges namely D<GVF<60%, 60<Gi~F<80%, and 80<GVF<97.5°/o. It is worth emphasizing that even the highest GVF in this facility does not constitute wet-gas flows and that intermittent flow conditions occurs at all GVF above 30%. 400 i --_---__ ._ _ _ + 350 300 L ~ E 250 ~ ' ,'+ / + + ~ ,~~ + ~ + +,~--, ~ 200 ,'~ 3 -" ~ 0 ~ 150 ,,'o~ ~,-' ^ 0%<GVF<60% ~~ ~ ' ~° ~ * - ' n 60%<GVF<80°/a 100 ~° +~ + 80%<GVF<100% , ~@~{ - { ~ Reference 50 ~ , t 20% 0 ~---- - _ -- - - - - 0 50 100 150 200 250 300 350 400 Reference Total Flow Rate, [m'/h] Figure 14 - Total flow rate in multiphase Figure 14 shows the total flow rate for all GVFs ranging from 0 to 100% and all water cuts ranging from 5 to 75%. It can be seen that the total flow rate is predicted to within f20% for GVF<80%, however, at higher GVF the measurement is erratic. The velocity reported by Sonar at these 13 ~ ~ conditions is not deemed representative as a time-averaged total flow rate. Further refinement of Sonar processing is required to resolve these flow conditions accurately. 120 100 F E 80 m 0 ~ 60 3 0 ~ ~o 'Q 40 J 20 i ° ° ~ ~ 0 o' a' ~' ~o, o. , °' A' 0 0%<GVF<60% 0 60°h<GVF<80% ' + 80%<GVF<100% I - Reference I --- t10% ' ~ ~~ r-~ 0 20 40 60 80 100 120 Reference Liquid Flow Rate, [m'/h] Figure 15 - Liquid flow rate in multiphase. Similar to the total flow rate, Fig. 15 shows that liquid flow rate is measured to within 20% for GVF<80%. The effect of the inaccurate Sonar velocity between 80 and 97.5% GVF exacerbates the liquid error. aoo 350 ~ + I I , ~ + ±, '' + + + ,++ I ++ 300 t ~ 250 ~ 200 3 0 ~ 150 R t9 100 50 ~+ + 0 n°'~ ~/ , Q *+ ~ - ~+ ~ + 0 0°k<GVF<60% e 60°k<GVF<80% ~~I + g0%<GVF<100°h II - Reference I --- t20% 0 -k 0 50 100 150 200 250 300 350 400 Reference Gas Flow Rate, [m'/hj Figure 16 - Gas flow rate in multiphase. 14 ~ ~ Figure 16 shows the gas flow rate. The gas rate is predicted to within 20% between 60 and 80% GVF, but larger errors are prevalent at lower GVF. Again, the measurement performance between 80 and 97.5% GVF is reduced due to low accuracy of the Sonar in this regime to the widely time- varying properties of the flow. Currently Sonar algorithms do not attempt to capture transient properties, but is rather reporting volumetric and time-averaged flow properties. It is worth noting that the Sonar processing algorithms can readily identify the slugs and offer potential to calculate both slug and bubble velocity and volume. CONCLUSIONS The Sonar-Venturi-(Red Eye) flowmeter constitutes a high-accuracy top-side evolution of the downhole fiber-optic flowmeter technology. The flowmeter combines Sonar sensors with an extended throat Venturi that enables measurement of liquid and gas rates in wet-gas and multiphase flows. Addition of a Red Eye 2G water cut meter enables distinction of oiUcondensate and water. This flowmeter has been tested in a range of wet-gas and multiphase flow conditions at CEESI and NEL where it was found that for wet-gas flows the total and gas flow rates are measured to within ~5% and liquid rate is determined to be within f20% in API Type II wet gas and f0.5 m3/hr in API Type I wet gas. In multiphase flows, liquid and total rates are predicted to better than f20% at GVF below 80%. In low pressure highly unsteady slugging flows, there is a reduction in Sonar measurement capability and hence the measurement performance is reduced. This was evident between 80 and 97.5% GVF in the multiphase facility. Additional work is required to improve the multiphase and especially Sonar performance in unsteady flow conditions. The Red Eye water cut meter has been demonstrated in other work to be within f5% (absolute) over the full range of GVF and WLR and is not significantly affected by slugging flow conditions. ' ACKNOWLEDGEMENTS The authors gratefully acknowledge BP Exploration Operating Company Limited and Weatherford Intl. for permission to present this work. We would also like to thank our co-workers who have directly or indirectly contributed to this work. NOMENCLATURE Acronyms and Symbols A = Area, [m2] API = American Petroleum Institute CEESI = Colorado Engineering Experiment Staxion, Inc f = Function Fr = Densimetric Froude Number, [-] GVF = Gas Volume Fraction, [-] LMQ = Liquid Mass Quality m = Mass flow rate, [kg/s] NEL = National Engineering Laboratory 1vIR = Near-Infrared ORS = Over-Reading Sonar, [-J ORV = Over-Reading Venturi, [-] Q = Volumetric Flow Rate, [m3/s], [m3/hr] V = Velocity, [m/s] WLR = Water Liquid Ratio, [-] 15 • XLM = Lockhart-Martinelli parameter, [-] ~P = Differential Pressure, [bar] Subscripts g = Gas 1 = Liquid m = Mixture s - Supe~cial t - Total REFERENCES ~ [1] "State of the Art Multiphase Flow Metering" API Publication 2566, First Edition, May 2004. [2] Hall, A., Lievois, J., and Adejuyigbe, B., "Testing of the Red Eye Near-Infrared Water Cut Monitor for Application as a Water Cut Sensor in Multiphase Flow Conditions," Multiphase Pumping and Technologies, International Conference & Exhibition, Abu Dhabi, 10-14 February 2007. [3] Kragas, T.K., Johansen, E.S., Hassanali, H., and Da Costa, S. L.: "Installation and Data Analysis of a Downhole, Fiber Optic Flowmeter at BP's Mahogany Field, Offshore Trinidad," SPE 81018, SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of- Spain, 27-30 April 2003. [4] Johansen, E. S., Kragas, T. K. and Beaumont, P., "Downhole Fiber Optic 3-Phase Flowmeter Field Test at BP Mungo," 21 st North Sea Flow Measurement Workshop, T~nsberg, 28-30 October 2003. [5) Sand,ery B., et al. "Improved Reservoir Management with Intelligent Multi-Zone WAG Injectors and Downhole Optical Flow Monitoring," SPE 95843, SPE Annual Technical Conference and E~chibition Dallas, 9-12 October 2005. [6) De Leeuw R., "Liquid Correction of Venturi Meter Readings in Wet-gas Flow", North Sea Workshop 1997. [7] Stewart, D., et al. "Wet-gas Venturi Metering" North Sea Flow Measurement Workshop, T~nsberg, Norway, 2003. [8) Hall, A.R.W., Reader-Harris, M.J. and Millington, B.C., "A Study of the Performance of Venturi Meters in Multiphase Flow," 2nd International Conference on Multiphase Technology, Banff, 22 June 2000. [9] Vilagines, R. and Hall, A.R.W., "Comparative Behaviour of Multiphase Flowmeter Test Facilities," Oil and Gas Science Technology, Vol. 58, No. 6, pp. 647-657, 2003. 16 ~ i 6`" South East Asia Hydrocarbon Flow Measurement Workshop 7"' - 9"' March 2007 Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions Andrew Hall, BP Exploration 8 Production John Lievois, eProduction Solutions Babajide Adejuyigbe, eProduction Solutions INTRODUCTION Near infra-red spectroscopy is a well-known technique for chemical analysis and has been successfully applied to measurement of small quantities of water in a variety of inedia, such as paper, methanol, tobacco, etc. The Red Eye~ 2G water cut monitor was developed to exploit the very characteristic attenuation of infra-red light by water as a means to measure the water cut in mixtures of oil and water. The water cut monitor uses four specific NIR wavelengths to provide a capability for water cut measurement across the full range from 0% to 100%. The monitor was known to operate reliably in the presence of a small quantity of free gas (up to 20%) from previous tests, and the purpose of this new test programme was to evaluate the capability of the instrument to operate in much higher gas volume fraction environments. This paper presents new data obtained in three test campaigns at the TUV NEL multiphase flow facility. The tests spanned the full range of water cuts from 0% to 100%, at a range of fluid mixture velocities, and with gas volume fractions in the 60% to 95% range. Most tests were for meters in a horizontal orientation, but some additional tests were included in vertical flow. The results exceeded expectations of water cut measurement uncertainty at these high gas fraction conditions, with very little dependence of the uncertainty on GVF. 2 RED EYE WATER CUT MONITOR 2.1 Description of the meter The Red Eye water cut measurement is based on near-infrared absorption spectroscopy. As shown in Figure 1, the dependence of absorption of near-infrared light on wavelength varies with the composition. At several key wavelengths, infrared light absorption is dependent on the behaviour of carbon-hydrogen and oxygen-hydrogen bonds in the molecules. Water, contains O-H bonds and hydrocarbons do not, therefore allowing infrared absorption to distinguish water from organic molecules. Furthermore, the characteristic wavelength associated with bending of the H-O-H bond in water is different from the wavelength associated with O-H bond stretch, so there exists the potential for water to be distinguished from other molecules, such as methanol, containing O-H bonds. The Red Eye 2G water cut meter extends the performance of the earlier 1 G meter, which used a single wavelength, to allow more accurate measurements of water cut at lower water- cut, by simultaneously measuring multiple wavelengths that include both the water and oil absorbent peaks. Scattering effects caused by emulsions, sand, or gas bubbles, are expected to have the same effect at all wavelengths and as such can be eliminated. Furthermore, changing salinity should have no effect on the measurement, since the water absorption is based on the water molecule itself, not what is dissolved in the water. The intemal design of the meter is shown in Figure 2. The meter consists of a probe which is inserted into the flow either through a 1-inch NPT tapping or using a 1Yrinch flanged connection and an electronics module mounted directly onto the probe. The only extemal connections required are for power (10 to 30 V DC @ 8 W) and output signal (4-20 mA analogue or RS-485 MODBUS outputs). ! • 6"' South East Asia Hydrocarbon Flow Measurement Workshop 7'" - 9'" March 2007 The main measurement section within the insertion probe has a small gap, with an infrared source on one side and detector consisting of a fibre optic bundle on the other. Befinreen the optical source and detector and the process fluids are sapphire windows for their optical and mechanical properties including abrasion resistance. 2.2 High gas fraction test philosophy The meter had previously been tested at gas volume fractions up to about 20% GVF, demonstrating that gas at this level had only a minimal effect on the water cut measurement. However, the meter had never been tested at higher gas fractions prior to the BP test in August 2005. Initially this test, simultaneous with testing of other equipment, was just intended to explore the impact of high gas fractions on the meter, with no preconceived expectations of its performance under these conditions. 2.3 Installation of ineters and test matrices The Red Eye meter was tested in horizontal and vertical flow without a mixer in August 2005; in a horizontal orientation with a static mixer immediately upstream of the Red Eye meter in February 2006; and in horizontal flow, without a mixer but in a pipe spool of restricted diameter (2.4 inch in a test line of 4 inch diameter) in November 2006. The meters were located approximately 80 feet downstream of the inlet to the multiphase test section. The test section adjacent to the meter was instrumented with a pressure transmitter and a platinum resistance thermocouple. These instruments provided the reference pressure and temperature measurements for correction of the reference gas volumetric flowrate to actual meter conditions at the Red Eye meter. The August 2005 horizontal flow test was conducted in series with another meter undergoing a performance test, and so the test matrix was determined by the requirements for the FAT, which required high flowrates. Tests were conducted at 5%, 25%, 40% and 100% water cut. The reason for testing at 100% water cut was to allow testing at high liquid flowrates. The schedule was also very tight, because of the need to deliver the meter to its field installation, and this did not allow additional time in this configuration for conducting further tests. Several other meters were also included in this test including a Weatherford sonar flow meter (also shown in Figure 3). The August 2005 vertical flow test was conducted immediately following the horizontal test, but with the commercial multiphase meter removed from the test line. Tests were conducted at 5%, 75% and 90% water cut. Following encouraging results obtained in the August 2005 campaign, it was decided to conduct a more systematic test, concentrating on the Red Eye meter alone. This was installed in February 2006, once again in a horizontal orientation, shown in Figure 5, and a test matrix was designed which spanned the previous tests, but ~ow included more intermediate water cuts. The water cuts tested were 5%, 25%, 40%, 50%, 60%, 75%, 82.5%, 87.5%, 90%, 92.5%, 95% and 97.5%. It would also have been desirable to include some tests between 5% and 25%, but these conditions are difficult to set up and control in this flow facility. An additional test was conducted in November 2006 of other equipment, with a Red Eye meter included as part of the test, to maximise utilisation of the test facility. The water cuts tested were 5%, 25%, 40%, 50%, 60%, 75%, 90% and 100%, covering roughly the same ranges of conditions as the previous test. Figure 7 shows the planned and actual test matrices for both the 2005 and 2006 test programmes. 2.4 Reference system (TUV NEL multiphase flow test facility) The TUV NEL multiphase flow facility is located in the James Young Building in East Kilbride, near Glasgow, Scotland. This site is also the location of the UK National Standards for flow measurement (oil, water and gas standards). The TUV NEL multiphase flow facility consists of a 250 barrel separator which is filled with the water and oil phases. Nitrogen gas is generated on demand by evaporation of liquid nitrogen 2 ~ • 6`" South East Asia Hydrocarbon Flow Measurement Workshop 7~' - 9"' March 2007 which is stored in a 40m3 tank. The nitrogen is used on a one-pass basis and is exhausted to atmosphere at the outlet of the separator. The oil is metered though Faur~-Herman helicoidal turbine meters, either 1%rinch or 3-inch depending on the flowrate required. These meters are calibrated in the UK National Standard gravimetric oil calibration facility at TUV NEL, using oil of an appropriate viscosity. The water is metered through standard flat-bladed turbine meters, either 1'/rinch or 3-inch depending on the flowrate required. These meters are cafibrated in the UK National Standard gravimetric water calibration facility at TUV NEL, using fresh water. The gas is metered through standard flat-bladed turbine meters, either %rinch, 1-inch or 3- inch depending on the flowrate required. The '/rinch meter was not used for these tests. These meters are calibrated in the UK National Standard gravimetric gas calibration facility at TUV NEL, using air. Both the oil and the water phases can be cross-contaminated with a small proportion of the other phase, due to limitations of the separator capacity. Generally the cross-contamination becomes most noticeable at higher liquid flowrates when the water cut is in the range 25% to 50%. The water content of the oil stream is detected using a capacitance-based water-in-oil monitor. This is specifically calibrated on the fluids in the test facility, and gives an uncertainty in the water cut of the oil stream of less than t1 % absolute. The oil content of the water stream is detected using a Coriolis-based densitometer. This takes as an input the density of the oil and water as a function of tempe~ature, and the temperature-coRected reading from the densitometer is used to calculate the oil content. This gives an uncertainty in water cut of the water stream of less than ±1 % absolute. Extensive testing at TUV NEL has demonstrated that the cross-contamination of the liquid streams has a negligible impact on the turbine meter accuracy over the ranges encountered. Tests have also shown that there is no dissolved gas in the separator outlets, and as the gas is generated from pure liquid nitrogen, it is completely dry at the reference gas flowmeters. Since the flows are metered on a volumetric basis, the temperature of the oil and water, and the temperatu~e and pressure of the gas, is measured at the flowmeters. The volumetric flowrates are corrected to the measured temperature and pressure at the location of the test meter in the multiphase flow line to give the correct volumetric flowrates at the test meter at line conditions. 2.5 Fluid properties The fluids used were stabilised crude oil, salt water and nitrogen gas The crude oil is topped to remove high volatitity components, and mixed with kerosine in approximate proportions of 70% crude to 30% kerosine to restore the original viscosity. The crude oil is a mixture of crudes from different North Sea oil fields, including Forties, Beryl and Oseberg crudes. The density and viscosity of the crude oil mixture are periodically measured as a function of temperature The salt water phase consists of a solution of magnesium sulphate (MgSO4). This salt was selected by TUV NEL to avoid (or minimise) co~rosion of pipework. It is important that the water phase has salinity similar to the application conditions, both for electrical type meters (capacitance / conductivity / microwave) and for dual-energy gamma densitometers. The concentration of the water phase is calculated from its density, which is periodically measured as a function of temperature. The water density is normally measured immediately before a test programme, as the density gradually changes due to evaporation of water. The gas phase is nitrogen. The density of nitrogen can be estimated with sufficient accuracy at the low operating pressure using the ideal gas equation, with a gas molecular weight of 28. TUV NEL uses a more exact equation of state for reference flowrate calculation. ~ ~ 6~' South East Asia Hydrocarbon Flow Measurement Workshop 7~' - 9"' March 2007 2.6 Calibration of the Red Eye meters The Red Eye meters were calibrated by flowing single phase oil and single phase water through the meters prior to starting the multiphase flow tests. Manual intervention was required during the tests to select the optimum combination of wavelengths depending on the water cut, 2 out of the 4 wavelengths being used for any one measurement. This process is somewhat automated in the standard (water-oil) model, but had not been fully implemented for high GVF operation. However, since the exact reference data was not available to the meter operator at the time of the tests, the water cut algorithm selection was necessarily based on the readings from the Red Eye itself, as it would be in an operating situation. 2.7 Data recording and processing The test facility was run until the flow was sufficientfy stable to perform a test. Since the test conditions were almost all in the slug flow regime the operator's experience was relied on to determine this stability time. Typically it took less than 5 minutes between test conditions. Each test condition was recorded for a period of 5 minutes, with the Red Eye set up to record data at 1 second intervals. The Red Eye data files included time, water cut and four infrared absorption figures. Only the water cut was used for further data analysis by BP. An average was taken of the water cut over the test, along with standard deviation and confidence to check for data quality. TUV NEL provided data for oil flowrate (litres/sec), water flowrate (litres/sec), gas flowrate (litres/sec), temperature (°C) and pressure (barg). Again the measurement was provided for the 5 minute period of the test, calculated from 100 three-second samples of the reference readings. All data was reported from the meter at line conditions, i.e. at the temperature and pressure at the multiphase meter. No reference data from TUV NEL was provided to Weatherford during the tests. 3 TEST RESULTS 3.1 Meter results: 2005 test campaign Figure 10 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal and vertical flow tests conducted in August 2005. Figure 11 shows the error in these measurements plotted against the reference gas volume fraction and Figure 12 shows the error in water cut measurements plotted against the reference water cut. Overall the water cut measurements were within about t5% of the reference values, with a tendency to under-read water cut. It was not clear at this stage whether this was due to the particular water cuts selected for testing, or a slight non-uniform distribution of the oil and water in the horizontal pipe, and therefore further testing was required. 3.2 Meter results: February 2006 test campaign Figure 13 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal tests conducted in February 2006. Figure 14 shows the error in these measurements plotted against the reference gas volume fraction and Figure 15 shows the error in water cut measurements plotted against the reference water cut. With the exception of the tests at around 60% water cut, all the water cut measurements were within about ±5% of the reference values. There is a quite clear variation of the errors in water cut measurement with water cut, with the abrupt switches in errors at different water cuts across the range related to the sele~tion of pairs of wavelengths used to determine water cut; it is likely this could be optimised to improve the measurements. There is a much smaller variation with GVF, and although this is not clear from Figure 14, it is best demonstrated by plotting results for individual water cuts against GVF, as shown in the next section. • • 6`" South East Asia Hydrocarbon Flow Measurement Workshop 7"' - 9~' March 2007 3.2 Meter results: November 2006 test campaign Figure 16 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal tests conducted in November 2006. Figure 17 shows the error in these measurements plotted against the reference gas volume fraction and Figure 18 shows the error in water cut measurements plotted against the reference water cut. The key difference between these tests and the tests conducted earlier in the year is an improvement in the mid-range water cut measurement (50% and 60% water cut). This improvement is a result of algorithm development, with no change to the meter hardware. Using the improved interpretation algorithm, all the water cut measurements were within about t5% of the reference values. 3.3 Meter results: comparison of 2005 and 2006 test campaigns Figure 19 shows the water cut measurements from the Red Eye meters against the reference water cut for the test campaigns in August 2005 and February and November 2006. Figure 20 shows the error in these measurements piotted against the reference gas volume fraction and Figure 21 shows the error in water cut measurements plotted against the reference water cut. Apart from the measurements at the lowest water cuts, and at 50% and 60% water cut, these figures show the good consistency between the results from both test campaigns, suggesting that there is limited impact of a static mixer in multiphase flow conditions. The differences at 50% and 60% water cut are a result of the improved interpretation algorithm. Figure 22 to Figure 34 show the water cut measurement erro-s plotted against GVF for each individual water cut range. These plots quite clearly show the limited scatter in the water cut errors as a function of GVF, and also the good consistency between the results from the two test campaigns. At each specific water cut there is a scatter of only t1 0~ 2% in the water cut errors, up to GVF values over 90°/a. 4 CONCLUSIONS The test results show that the principal influence on the water cut measurement accuracy under these multiphase flow conditions is the water cut itself, with a relatively small influence of the gas fraction. Typically at any particular water cut there is a scatter of about t2% in the water cut errors across a range of gas fractions from 70% to 95%. No other in-line multiphase flowmeter (without full or partial separation) is able to measure water cut within a scatter of t2%, particula~y at high water cuts, under these c~nditions of high gas volume fraction. The tests have also shown that there is a retatively limited impact of the presence of a static mixer on the test results, or of the orientation of the meter (horizontal or vertical). While these tests show that good measurements of water cut can be obtained in high gas fraction multiphase flow conditions, it should be noted that the gas phase used in the tests was nitrogen, which is completely transparent to infra-red light at these wavelengths. It is expected that hydrocarbon gas will have an impact on the measurement, and the meter should therefore be tested in a test facility using hydrocarbon gas. A secondary evaluation also needs to be conducted to determine the impact of alcohols (methanol, etc.) on the water cut measurement. These test programmes were conducted over short timescales in an ideal laboratory environment with well characterised and `clean' fluids. It is recommended that further data is obtained for the longer term performance of the meter in the laboratory and more importantly in real production fluids. ACKNOWLEDGEMENTS The test work at TUV NEL and analysis of the test results was funded by a BP subsea metering technology project. The Red Eye meters and support personnel for the test programme were provided by eProduction Solutions. The support of both organisations and their permission to publish this work is gratefully acknowledged. 5 ~ • 6`h South East Asia Hydrocarbon Flow Measurement Workshop ~m _ 9m March 2007 Figure 1: Near-infrared absorption spectrum Fiber Optic Bundie Collector Optics Probe Assembly Sapphire Windaw Sapphire Winda~,v NIR Emitter Figure 2: Red Eye water cut meter cross-section 6 ~ ~ 6`h South East Asia Hydrocarbon Flow Measurement Workshop ~in _ 9~n March 2007 Figure 3: Red Eye meter installation (August 2005 horizontal test) Figure 4: Red Eye meter installation (August 2005 vertical test) ~ i 6"' South East Asia Hydrocarbon Flow Measurement Workshop 7~n _ 9"' March 2007 Figure 5: Red Eye meter installation (February 2006 test) Figure 6: Red Eye meter installation (November 2006 test) 8 ~ • 6"' South East Asia Hydrocarbon Flow Measurement Workshop ~~n _ 9cn March 2007 5% water cut 25% water cut ; o0 ~_ 2 o~.~~ j" o«~~.~ w i ~ .~~ ~ ~ _--,~-~T.~ ~ z .~. .~ i - -- -«:._- I 9 • d !P• I • I • • •w~mreeluwY106 •a0 • O> • ~o N• ~ • O • O a~O b~ __.._"._""__- - - "__.-- a 9.0 - - ~ ~ Oo1~0 •~ • ^ • ~ p O • o •O~O ~ ~ ~ -_ _ _ " . _- _"__.......____" "__-_-~_T~y-~-_- • a.o e - __ -___'_____ . - - ___- ] i2o -_ _-__--_......'____'_"_'__-_____"' Q o v --- e e o o s oe o ---" ' -- -----"- - ~ ~ to A 30 ~p ~F~) gp )0 80 W tM 40% water cut ~ ~ ~ 9S F ~ s 'e $ € ~^ b P S ° ~ .~.Fm~~ ~-- -------. - e.o .__ __..____ . M - ~ _ ~ ~ o io xa a m ~~ 80 >o ap 9p ioo 60% water cut ^ ~~--- - y-.-.. ~. _ ___- ~ . •_ ~~'_.-- --- --s--4--r-- ~ ~ ~ o ta A l0 a0 80 >o ¢0 50 1C0 GVF (Y.) 50% water cut ~t ~~ .-.. ~ ~ j- ------- „ . •a •Jo b o• ~ - . - '___ n_- o ~a m x aa m eo m ao so iao GVF ~Y~ 75% water cut > ~.~~ ~- -- - .,~, i . ~..~ •o • a~ r •d - o . . e~ °" - --- -------T ro m ao ao ~ 1'XI eo ~a eo so iao o to zo x ~o G~ 1~ w ~0 eo m ~w Figure 7: Test matrices for TUV NEL test (August 2005, February 2006, November 2006) 9 • ~ 6"' South East Asia Hydrocarbon Flow Measurement Workshop 7'" - 9"' March 2007 82.5% water cut 87.5% water cut e ~ ~ 3 e ~ ~ R ~ ~ a a w m m ~~ m ro n w n 90% water cut 0 f0 1p ]p a La !o i0 O 90 lt 6VF~y 95°/a water cut ~.~~ :~..,~, .~...,,,~ s . d,. a .. . 0 0• e e 'eo .~. ~~. .~ p b a ,o p m a ~ ~ ro ~ ~,~ a~~) !0 TI M BY 100 0 aK~ 100% water cut ~ ~ o~~~ ~ .,,~ ~~ ~A •Ne1mXN.FlA08 ~~ .~mu.w.wos ~ •o s . E •o a ~ o a .o• . a o $ wa ~ ~ ~ 0 18A p o o O O O A ~0 M W N W W tW OVF (1L) 10 ~ >o .~. ~~ ~ zA . e ,~ . .. . ~ . . . . e ~ ~ ~ ~ ' iwo ~m 0 0 ~o x ao a eo ro • ws ~ 92.5% water cut 3 e ~ ~ Y 1 0 10 30 b b SO Bp T1 p] ~1~ 97.5% water cut ~ ~ ~ ~ • 6`" South East Asia Hydrocarbon Flow Measurement Workshop ~m _ 9m March 2007 ~ ~,i~E~ ~'-`.s»..- ' , ~± ry - ~~ ~ J ~ ~ , ,..v.. ~ ~ t ,~w~~. 1 ' ! ~. I 1~~~~._ ~ ~ •+~, ',-~`~~ e ~. I~~~~ ~~;_ ~ ~` ',:~~ .; ii/^ w _ Itali~ _,~*'` NI# ~ ~'~a ~.~y •^~~~.'~ ~py,~ ~'~Si+L1.:h . "'~1 7~' ~.'~;. .~~+~:. .f,~..l.i. ~A~. `~b`1. M ~wli~' ~ N'- %r ` t ~fIN1 ~ ~ ~i . ~~` : ~ ~~.~ ~ ,,,`~~~ir~~~A~~~'. ~.. :~~. . ~'.~; ,~--~~ Figure 8: Location of multiphase flow meter test facility Pressureand Three phase separ~or f I ow corit rol __--~: ~~ T-,.:.~ ~' ) Liquid Test meter - - ' nitrogen R~er~ce metering Pump Pump Test meter G as Figure 9: Schematic of TUV NEL multiphase flow test facility 11 • • 6`h South East Asia Hydrocarbon Flow Measurement Workshop 7`" - 9'" March 2007 ioo so 80 70 ~ 60 ~ u ~ d 50 io 3 . m ao m ~ 30 20 10 0 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 10: Red Eye water cut vs. reference water cut (2005 multiphase flow tests) zs 20 d u m 15 d d E i0 0 m 5 ~ 0 0 .a m ° -5 0 d -10 ~ u u`~ -15 m 3 -20 -25 ~- - *I- 5°h absolute error ^ Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertital x x x x x x x x x ~M --a -X X xX x x-# x x x x o o x'°t x o x x p o ~ x o~ x x °~~ o ox ~ o x o°o ~ °x o -- o --- - d`---_ a ~ ° ~ o 0 0 ~ I x -- x- x-------x - ----~x 0 10 20 30 40 50 60 ~0 80 90 100 Reference GVF (%) Figure 11: Red Eye water cut error vs. reference GVF (2005 multiphase flow tests) 12 • • 6"' South East Asia Hydrocarbon Flow Measurement Workshop ~~n _ 9cn March 2007 2s zo d 0 aCi 15 d w d ~ 10 O ~ y 5 7 O a ~ ~a ° -5 ~ O ~ ~ m -10 3 U d -15 io 3 -zo -2s 0 , o0 90 80 70 e . 60 ~ c~ ;: 50 3 d 40 d ~ 30 20 10 0 - ~ H- 5% absolute ertor • Red Eye 2G, NEL, Feb 2006, Horizontal i ~ •~ ~~~: ~y r , ~ • ~• , ~ ~ • 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 13: Red Eye water cut vs. reference water cut (February 2006 multiphase flow tests) 13 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 12: Red Eye water cut error vs. reference water cut (2005 muitiphase flow tests) i • 6`h South East Asia Hydrocarbon Flow Measurement Workshop 7m _ 9~n March 2007 zs 20 d ~ m ,5 N m ~ 10 0 w ~ 5 ~ 0 a ~ ` -5 0 m -~o 5 u d -15 3 -20 -25 _ _----- -- - ~ - - +/- 5% absolule error ' I • Red Eys 2G, NEL, Feb 2006, Honzontal II L-- -- --- ~ ~ • • - --- _ _ -------- - -- ----- - -~ ~-~~-~ .t .~. '• N.•.r•; . . ~ ~ • ~ 1 ~ • • -'L J. _ _ • ~ t . • • ~ . 3 ~.~~ ,~~ ~ • . .. • • I .• . I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 14: Red Eye water cut error vs. reference GVF (February 2006 multiphase flow tests) 2s zo m V m 15 ~ ai w d E io 0 « 5 7 a ~ A o -5 d -10 ~ U y -15 3 -Zo -2s ~-.i- sx e~a~ne a~~ '' i • Red Eye 2G, NEL, Feb 2006, Horizontal ~', ~ ~~ ~ - - - -- --- ----- - -- - - ~• • s'~ • • : ~ ~ I ~ ' ~ • . . ~ --.. - : ~~ ~ • S M M 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 15: Red Eye water cut error vs. reference water cut (February 2006 multiphase flow tests) 14 ~ + 6`h South East Asia Hydrocarbon Fiow Measurement Workshop ~m _ 9cn March 2007 i o0 90 80 70 u 60 m 50 ia 3 d ao a+ ~ 30 20 10 0 - ~ - , I ~~ --- y- 5% absdute ertor ~ • Red Eye 2G, NEL-Nov 2006, Horizonfal 'I ,,/, ./ -'~~ ,' •s • o~ /i % .~ . ~~. /~ a -`~ . ~ j';t~! ~ ~~ 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 16: Red Eye water cut vs. reference water cut (November 2006 multiphase flow tests) zs 20 c~i a~i 15 m `m ~ 10 O d 5 ~ ~ o ~ ° -5 0 I-~~~~ +l-5%absolutearrw..~ . .. .-~ -~,I I. ~ ~ • Red Eye 2G, NE~, Nov 2006, Haizontal ~ d -to ~ u d -15 ~ ~ -20 -25 ~ ~ --~..-~~- - -- ~ i ~~tl M„ • .~ .- ~• « • •• . y .. •• _. ~ • . .t . ; y • ~+- • ~ •.. • • - - ~~_-`j' ~ - I'• . . 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 17: Red Eye water cut error vs. reference GVF (November 2006 multiphase flow tests) 15 • • 6`" South East Asia Hydrocarbon Flow Measurement Workshop 7'" _ 9`n March 2007 zs zo d u m 15 `m w m ~ 10 O m 5 ~ O a ~ m ° -5 O ~ ~ d -10 7 U `m -15 ic ~ -20 -25 0 ,oo 90 SO 70 e . 60 3 U ~ 50 3 ~ ;; a0 a~ ~ 30 20 10 0 .~- sx ecsaute erto, ^ Red Eye 2G. NEL, Aug 2005, Honzontal ~, x Red Eye 2G, NEL, Aug 2005, Vertical i, i' ~ • Red Eye 2G, NEL Feb 2006, Horimntal ~~ ~ ~ • Retl Eye 2G, NEL, Nov 2006, Honzontal ~ -~ • ~ ,+ •~ • ., • .~ ~ • . '~~ ~ i~ - ,~ / 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 19: Red Eye water cut vs. reference water cut (2005 and 2006 multiphase flow tests) 16 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 18: Red Eye water cut error vs. reference water cut (November 2006 multiphase flow tests) • i 6'h South East Asia Hydrocarbon Flow Measurement Workshop ~m _ 9~n March 2007 2s 20 d V ` 15 w d ~ 10 0 y 5 3 0 a ~ o -5 m -10 ~ U W -~rJ 3 -zo •zs - --- - _ ~ - - •r• s% a~~~~e B„o~ - - - - _ ^ Retl Eye 2G, NEL, Aug 2005, Horizontal ~I x Red Eye 2G, NEL, Aug 2005, Vertical I~ ~ • Red Eye 2G, NEL, Peb 2006, Horizontal ~~, i • Red Eye 2G, NEL, Nov 2006, Horizonfel '~. x x x ~x » x xx x • X .X_• x a Y i~ x rs ~~ I~ x o . o•t ~ ~. »o ~' ;•. ;r` ~ . x x x x Iax ~ ~ j • ~ ~ - - ~ -~- - - ~ ~ ~° ~ ~ ~ o i ~ ~ •___ • oo- ~~o ti o,s ~ ~~ • ~ ~~6•• • •• •• • • •• • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 20: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests) zs 20 G7 U ` 15 w ~ ~ 10 0 ~ 5 « _ 0 0 ~ ta ° -5 0 m -~o ~ u d -15 3 -zo -zs --- _ - i - - - */- 5% absolute error ^ Red Eye 2G. NEL, Aug 2005, Horizontal ~ x Red Eye 2G, NEL, Aug 2005, Vertical ', i • Red Eyre 2G. NEL. Feb 2006, Honzortlal ~~~ • Red Eye 2G, NEL, Nov 2006, Horizontal ~~ x ._ _._ __ .--------- . . ~ ~. .-`-~-- .s • --~ --- ~ •• ~~- --- '. ------- ---- • ~ • o ~ • ° : ~ + • . • i i - ---- ~• - -- ~ - • • f ! •. ~- • ~ -- ~--~ ~ ~ ~ • f ~ • N t ~ . y 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (°/a) Figure 21: Red Eye water cut error vs. reference water cut (2005 and 2006 multiphase flow tests) 17 ~ • 6ih South East Asia Hydrocarbon Flow Measurement Workshop 7~' - 9'h March 2007 2s 20 d u m 15 ~ ~ d ~ 10 0 w W 5 ~ O ~ 0 A ° -5 `o --- tl- 5 h absdute error i o Red Eye 2G, NEL, Aug 2005, Hor¢ontal I x Red Eye 2G, NEL, Aug 2005, Vertical ~ • Red Eye 2G, NEL, Feb 2006, Horizontal '~ • Red Eye 2G, NEL, Nov 2006, Honzontal ' _ . _ _ . _ _ . . . _ _ . _ _ . . . . _ _ _ _ _ .. .. "6. _ _ _ _ _ _ _ x X i( # _ _ ! ' " _ - xKx ~ X i • •r~• xx~c ~ x • • w ~ • • x x x x xx ~ • ~ • '~ •b ~° oB ° ° •~ °~ •o ° ~ --- --------- --- - o i ^ • o ° ---- --- -----o --- o- - - m -10 7 u y` -15 m 3 -zo -zs ~ ~ , -. 0 10 20 30 40 50 60 70 BO 90 100 Reference GVF (%) Figure 22: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 5% water cut) zs 20 Gt U aci 15 w d E ~o 0 ~ w d s ~ 0 ~ 0 m e -5 O m -10 ~ ~ y` -15 A 3 -zo -25 ~ - - - +l- 5% absolute error ~~ ^ Red Eye 2G, NEL, Auq 2005, Horizontet ~ • Red Eye 2G, NEL, Feb 2006, Hodzontai I • Red Eye 2G, NEL, Nov 2006, Horizon[al '~ 0 0 0 ~---• tID • 0 0~ o ••~ i1 • 'I • • o ~ ~ 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 23: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 25% water cut) 18 • • 6'" South East Asia Hydrocarbon Flow Measurement Workshop 7~' - 9"' March 2007 zs 20 N V ` 15 a~ w m £ 10 0 m 5 ~ 0 ~ o ~ ° -s 0 ~ m -to ~ u `y -15 ia 3 -zo -2s +/- 5% absolute error i • ReA Eye 2G, NEL, Peb 2006, Honzontal I e Red Eye 2G. NEL Nov 2006, Horizontal I, • • • ~~ • • ~ ~ ~ • • • . . . ~. •• • .• . . . . . -----------'-•------ 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 24: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 40% water cut) zs 20 d C1 ` 15 d d ~ 10 O y 5 7 O ~+ 0 ~ m ° -5 0 ~ i - - - */- 5% absolute error ' ~ o Red Eye 2G, NEL, Aug 2005, Horizontel I • Red Eye 2G, NEL, Feb 2006, Horizontal ' I~ • Red Eye 2G, NEL, Nov 2006, HorizonUl I ~ • e e• • ~ • M • • 0 m ~ ~~ • ~~ ° ~~ o-~ S. o - o 'f-- ; ~ • ' o ~~ ~ d -10 ~ u `y -15 m 3 -zo _zs ~ 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 25: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 50% water cut) 19 . ~ 6`h South East Asia Hydrocarbon Flow Measurement Workshop ~~n _ 9~n March 2007 2s 20 d U m 15 W w G1 E io 0 ~ w d s ~ a ~ A ° -5 0 m -~o ~ u ~ -15 3 -20 -25 +/- 5 % ~absolute enor -~ • Red Eye 2G, NEL, Feb 2006, Honzontal I ~ ` • Red Eye 2G, NEL, Nov 2006, Horizontel I -------------------- --- - . • • . • ~ • . • ' - .. .. _ . - - • - -~~ -~ • - •• l • • . . • . .. • . . . • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 26: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 60% water cut) Zs 20 m u m 15 m £ 10 0 ~ s 5 0 W ~ a m e -5 O ~ ~ d -10 ~ u `y -15 A 3 -zo -zs -- -- _ _ ~ - - - M- 5% absduta ertor x Red Eye 2G. NEL, Aug 2005, Vertical I • Red Eye 2G, NEL. Feb 2006, Fbrizontal ~ • Red Eye 2G, NEL, Nov 2006, Hor¢ontal I ~__ . I -- ---- . • x X• ~tJ~ ~x • • • ~~~ ~' X~ • --- -+--~-r ------ - ~ 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 27: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 75% water cut) 20 ~ ~ 6`" South East Asia Hydrocarbon Flow Measurement Workshop 7`h - 9`" March 2007 25 2~ N V ` 15 w m £ 10 0 ~ w m 5 7 O a ~ m ° -5 O ~ d -10 7 U y` -15 ia 3 -zo -zs ~ _ - - ---- -- - ~ *I- 5% absWute error I • Red Eye 2G, NEL, Feb 2006, HorizonWl ~_. _ ._ ___ _ _..._...__ . ' w ~ • ti • : • • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 28: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 82.5% water cut) zs 20 ar U a~i 15 d d E io 0 w d 5 ~ 0 D 0 m ° -5 O ~ d -10 ~ u d -15 m 3 -zo -25 r- _ _ - -- -- - ~ - - +/- 5% absolute error • Red Eye 2G, NEL, Feb 2006, Honzontal ------ ~--- I • 5~---- ~~+-- ~ -f- ~-~ --- •~ • r • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 29: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 87.5% water cut) 21 • • 6`h South East Asia Hydrocarbon Flow Measurement Workshop 7`n _ 9"' March 2007 zs 20 d U a~ 1S d N £ 10 0 ~s d 5 7 0 ~ 0 a ~o ° -5 O - - - +l- 5% absolute ertor -~ ~ ~ - ~ ~ ~ x Red Eye 2G, NEL, Aug 2005, Verticel • Red Eye 2G, NEL, Feb 2006, Horizontal ~ • Red Eye 2G, NEL, Nov 2006, Horizontal x x X x ~ I xx X ~ - X - - x-- -~X--- - X ---- ~- --~ ------- x x ~ •• • • • ~ . . . . - - --- - - -- • -- - - - - d -10 ~ u d -15 A 3 -20 -25 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 30: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 90% water cut) 25 20 V a~i 15 d m ~ 10 0 d 5 ~ O O a ° -5 0 a' -10 ~ u m -15 A 3 -zo -2s i - ----- ---- - - -- ~ - - •I- 5% ebsolute error • Retl Eye 2G, NEL. Feb 2006, Honzontal I ------------- - - - ---- ------~-~~-I •~ • • ~ • t 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 31: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 92.5% water cut) 22 ~ ~ 6`~ South East Asia Hydrocarbon Flow Measurement Workshop 7"' - 9"' March 2007 25 20 ro u ~ 15 ~ ~ 10 O ~ w y 5 7 O a ~ ~ ~ - -5 t m -~o 5 u ro -15 R 3 -zo -25 0 ~~ ~1 m u ~ 15 w ro `~ 10 O ~ w m 5 ~ O ~ ~ ° -5 O - - - 4~• rJ°/a 8b80~U~B BAOf o Red Eye 2G, NEL, Aug 2005, Harizonfal • Red Eye 2G, NEL, Feb 2006, Horizontel 0 0 O --- -•--- --• -- ----------- m -10 ~ u `y -15 W 3 -20 -25 F i i I I I i i ~ 0 10 20 30 40 50 60 70 80 90 700 Reference GVF (°k) Figure 33: Red Eye water cut enor vs. reference GVF (2005 and 2006 multiphase flow tests at 97.5% water cut) 23 90 20 30 40 50 60 70 80 90 100 Reference GVF (°k) Figure 32: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 95% water cut) . • 6`h South East Asia Hydrocarbon Flow Measurement Workshop 7"' - 9~' March 2007 25 20 d V aLi 15 ~ w m ~ 10 0 ~ w m 5 7 O ~ ~ m a -5 O t m -10 ~ u `m -15 A 3 -20 -25 - - - +/. 5~O absolule arror ^ Red Eya 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Verticel • Red Eye 2G, NEL, Nov 2006, Hor¢ontal ~ o0 0 ^ o " " " ~N • ~• • ~ • ~~ O _ ~ _. e ! _ ~_ • ...--------------------------------..__...__..._--------- s~----- 0 10 20 30 40 50 60 70 80 Reference GVF (%) Figure 34: Red Eye water cut error vs. reference GVF (2005 multiphase flow tests at 100% water cut) 90 100 24 ~ • Flomeko 2005 6 - 9 June 2005 CLAMP-0N, SONAR-BASED VOLUMETRIC FLOW 6tATE AND GAS VOLUME FRACTION MEASUREMENT FOR INDUSTRIAL APPLICATIONS Daniel L. Gysling, CiDRA Corporation Douglas H. Loose, CiDRA Corporation Alex M. van der Spek, ZDoor BV 1 ABSTRACT A clamp-on, sonar-based flow measurement technology for simultaneously measuring volumetric flow rate and process fluid sound speed is described. The technology utilizes sonar array processing techniques to perform two independent measurements to characterize the process fluid, each well-suited for single and multiphase flows. FirsUy, the meter provides mixture volumetric flow by tracking the speed at which naturally occurring flow-generated pressure fields convect past an array of strain-based sensors clamped-on to existing process pipe. Secondly, the meter provides compositional information by measuring the speed at which naturally occurring sound waves propagate through the process fluid using the same clamp-on sensors. Measuring the speed of sound of a process fluid utilizing this sonar technique is analogous to measuring process fluid density and has many compositional based applications. A primary example of this is using process sound speed to accurately measure the amount of entrained gases in liquid~ontinuous mixtures. The ability to measure volumetric flow and process sound speed reliably and accurately in single and multiphase applications with a non-intrusive, clamp-on device significantly enhances the observabiliry of the many industrial processes. Data is presented from sonar- based volumetric flow and sound speed-based compositional measurements for a wide range of industrial applications, encompassing single phase liquid applications to large diameter, abrasive multiphase applications, widely-recognized as difficult, long-standing flow measurement challenges. 2 INTRODUCTION Volumetric flow is a critical measurement in process control and optimization for most industrial processes. The cuRent industrial flow meter market is often classified into two technology-based categories: old technology and new technology. Old technology flow meters include flow measurement technologies that have been in use for more than 70 years, It includes turbine meters, orifice plates and variable area flow meters. The new technology flow meters include technologies which have emerged over the last 30--50 years. These new technologies typically offer advantages over the old technologies in performance, functionality, and reliabiliry. The major types of new technology flow meters include ultrasonic meters, electromagnetic flow meters, vortex flow meters, and coriolis flow meters. Each type has evolved to serve various aspects of the diverse range of applications within the industrial flow mete~ landscape. This paper describes sonar-based flow meter technology which utilizes sonar techniques' to listen to, and interpret, pressure fields generated by turbulent pipe flows. Sonar flow measurement technology represents a new class of industrial flow meters utilizing measurement principles distinct from existing technologies. Sonar flow meters were first introduced into the oil and gas industry in 1998 for use in downhole multiphase flow metering applications2 3. Sonar flow measurement technology is currently being used in other industries such as pulp and paper, mining and minerals, hydro transport, chemicals and power generation. Process aeration is often an unwanted but unavoidable phenomenon that negatively impacts product quality or the ability to accurately determine the rate of flow. For instance, entrained air in the thin stock flow to the headbox of a paper machine may lead to pin holes in the BI0197 RevB 1 ! • Flomeko 2005 6 - 9 June 2005 produced paper or worse still to a web break resulting in production loss. Entrained air in the paper and pulp industry is such a pervasive problem4 that both mechanical and chemical means are used to remove air from the process. Likewise in production of crude oil, gas carry under in the liquid outlet of a twophase separator impairs the measurement of the rate of net oil flow as the watercut meter is affected by the presence of free gas. It is well known that the resulting errors in the net oil rate can easily be 100% or more solely because of a small error in the watercut. Just as often, however, process aeration is an integral part of the production process and the air or gas content must be kept within certain limits. By way of example, the injection of a small amount of air in the hydrotransport pipe lines in oil sand processing initiates the separation of oil from sand. Likewise in the separation of rock from minerals in flotation cells, gas is sparged in at the bottom of the cell and the gas holdup in the cells must be controlled to optimize the gravity separation of rock from mineral. The sonar techniques that enable the interpreta6on of the naturally occuRing pressure fields inside a pipe are also well suited to determine the velocity of propagation of acoustic p~essure fields. The velocity of sound thus determined is a very sensitive indicator of process aeration and it offers a superior alternative to today's mechanical, sample taking analyzers. The methodology involves characterizing the speed at which coherent pressure waves, either vortical structures or acoustic pressure fields, convect past an axial array of sensors using beam-forming techniques developed over several decades for underwater acoustic applications. Since coherent vortical structures are an inherent feature of turbulent boundary layers, no internal geometry is required to generate these structures. Likewise, in the majority of industrial processes the proximity of pumps, compressors, valves or sharp bends ensures that no source of sound is required. The sonar-based measurement is therefore entirely passive and it can be pertormed using an array of strain based sensors mounted on the outside of the pipe. With no process-wetted hardware, the sonar flow measurement technology is well suited for the corrosive and abrasive slurries commonly encountered in many practical applications. 3 FLOW RATE MEASUREMENT The overwhelming majority of industrial process flows involve turbulent flow. Turbulent fluctuations within the process flow govern many of the flow properties of practical interest including the pressure drop, heat transfer and mixing. For these reasons, turbulent pipe flows have been extensively studied over the years with roots back to Osbourne Reynolds and Lord Rayleigh in the late nineteenth centurys. 3.1 Turbulent pipe flow For engineering applications, considering only the time averaged properties of turbulent flows is often sufficient for design purposes. For sonar flow metering technology, understanding the time averaged velocity profile in turbulent flow provides a means to interpret the relationship between speed at which coherent structures convect and the volumetrically averaged flow rate within a pipe. For turbulent flows, the time-averaged axial velociry varies with radial position, from zero the wall to a maximum at the centerline of the pipe. The flow near the wall is characterized by steep velocity gradients and transitions to relatively uniform core flow near the center of the pipe. Figure 1 shows a representative schematic of a velocity profile and ~ $°n°• coherent vortical flow structures Figure 1: Coherent structures in turbulent pipe flows. present in fully developed turbulent pipe flow. BI0197 RevB . ~ Flomeko 2005 6 - 9 June 2005 The vortical structures a~e superimposed over time averaged velocity profile within the pipe and contain temporally and spatially random fluctuations with magnitudes typically less than 10% percent of the mean flow velocity. The Reynolds number (Re), based on pipe diameter (D), characterizes many of the engineering properties of the flow. The Reynolds number is a non-dimensional ratio representing the relative importance of inertial forces to viscous forces within a flow: Pipe flows with Reynolds numbers exceeding a critical value, typicaliy 2300, are turbulent. Those with Reynofds numbers below this value are laminar. The vast majority of flows in industrial processes is turbulent with Reynolds numbers far in excess of the critical value. In addition to demarcating a boundary between laminar and turbulent flow regimes, the Reynolds number is a similarity parameter for pipe flows, i.e. flows in geometrically similar pipes, scaled with radius, with the same Reynolds number are dynamically similare . Empirical studies have shown that velocity profiles in turbulent pipe flows are well represented by the 1 over n"' power law: ( 1y Ur~=l1-RJ (~)~ o \ 90% with n ranging from 6 to 10 as a weak function of Reynolds number. From a measurement perspective, the volumetrically averaged flow velocity V (mean velocity) or the volume rate of flow divided by the pipe's internal cross- sectional area is of interest. The relation between the ratio V/Uo and the Reynolds number is shown in Figure 2, which is based upon the power law (1). Apparently the ratio of the mean flow velocity to the maximum velocity slightly increases from a little below 80% just above the critical Reynolds number for turbulent flow to greater than 85% at Reynolds numbers over one million. It must be stressed that, given the velocity profile (1), very little fluid is actually flowing at the mean flow velocity. 85% 0 ~ 80% > 75% 70% 1. E+03 1. E+04 1. E+05 1. E+06 1. E+07 Reynolds number Figure 2: Mean vetocity normalized by Maximum velocity vs. Reynolds number. 3.2 Coherent turbulent structures Turbulent pipes flows are highly complex flows. Predicting the details of any turbulent flow is one of nature's great-unsolved problems. However, much is known regarding the statistical properties of the flow. For instance, turbulent pipe flows contain self-generating, coherent vortical structures often termed "turbulent eddies". The maximum length scale of these eddies is scales with the diameter of the pipe. These structures remain coherent for several pipe diameters downstream, eventually breaking down into progressively smaller eddies until the energy is dissipated by viscous effects. Experimental investigations have established that eddies generated within turbulent boundary tayers convect at roughly 80% of maximum flow velocity. For pipe flows, this implies that turbulent eddies will convect at approximately the volumetricalty averaged flow velocity within the pipe. The precise relationship between the convective velocity of turbulent eddies and the flow rate for each class of ineters can be calibrated empirically as described below. 3.3 Characterizing the unsteady pressure field The sonar flow metering methodology uses the convection velocity of coherent structure with turbulent pipe flows to determine the volumetric flow rate. The convection velocity of these eddies is determined by applying sonar arraying processing techniques to determine the speed at which eddies convect past an axial array of dynamic strain measurements BI0197 RevB • ! Flomeko 2005 6 - 9 June 2005 distributed along the pipe outer circumference. The sonar-based algorithms determine the speed of eddies by characterizing both the temporal and spatiai frequency characteristics of the flow field. For a train of coherent eddies convecting past a fixed array of sensors, the temporal and spatial frequency content of pressure fluctuations are related through the following relationship: w = kv (2). Here is the wave number, defined as k=2n/~ (1/m), w is the temporal frequency (rad/s) and v is the convective velociry of the unsteady pressure fluctuations. Thus, the shorter the wavelength is the larger k and the higher the temporal frequency. ~ In sonar array processing, the spatial - temporal frequency content of time stationary sound fields are often .~ displayed using "k-w plots". k-w plots are essentially two dimensional ~ power spectra in which the power of ~ ~ a pressure field is decomposed into ,. bins corresponding to specific spatial wave numbers and temporal '~ frequencies. On a k-w plot, the power associated with a pressure field .,~ convecting with the flow is distributed w~~~,~~ in regions which satisfy the dispersion relationship developed Figure 3: k-w plot showiag convective ridge above. This retqion is termed the "convective" ridge and the slope of this ridge on a k-w plot indicates the convective velocity of the pressure field. This suggests that the convective velocity of turbulent eddies, and hence flow rate within a pipe, can be determined by constructing a k-w plot from the output of a phased array of sensors and identifying the slope of the convective ridge. Figure 3 shows an example of a k-w plot generated from a phased array of transducers listening to a 16 inch pipe flowing water at approximately 350 I/s. The power contours show a well-defined convective ridge. A parametric optimization method was used to determine the "best" line representing the slope of the ridge. For this case, a slope of 3.2 m/s was determined. The intermediate ~esult of the optimization procedure is displayed in the insert, showing that optimized value is unique and constitutes of one well-defined maximum. 3.4 Sonar flow meter calibration The k-w plot shown in Figure 3 iltustrates the fundamental principle behind sonar based flow measurements, namely that axial arrays of transducers can be used in conjunction with sonar processing techniques to determine the speed at which naturally occurring turbulent eddies convect within a pipe. The next issue is to quantify the relationship between speed of the turbulent eddies and the volumetrically averaged flow rate within the pipe. To quantitatively evaluate this relationship, a number of geometrically similar sonar flow meters with diameters between 4 and 16 inch were tested with water at a flow meter calibration facility for flows ranging from 1.5 to 1500 I/s. The convection velocity determined using the sonar-based techniques, normalized by the volumetrically averaged flow rate supplied by the calibration facility as a function of Reynolds number ranged between 99% and 102% of the volumetrically averaged flow rate over the entire range of the test. A low-order Reynolds number based calibration, was developed from this data for this class of ineters. The calibration equation is developed in terms of the relative offset of the sonar based meter from the reference meter. The relative offset 0 is, in terms of the Reynolds number Re and a set of three coefficients C~, CZ and C3, unique to each sonar meter size given by (3). ~=C~+ Cc Re ' (3). BI0197 RevB • • Flomeko 2005 6 - 9 June 2005 Figure 4 shows the relative difference of the volumetric flow rate measured by the calibrated sonar meters and the reference flow plotted versus reference flow. Calibration data was recorded for the sonar flow meters with volumetrically averaged flow velocities ranging from 1-10 m/s. Using a single Reynolds number calibration (4) spanning the operating range of the three flow meters of different physical sizes, the sonar meter measured the volumetric flow ' h' 0 5°/ - «-0.~ P[4LMlctlo nSONA R6acRnwMe6erOsfa --- -esxc rm~~r=o.~ztc ^ sroeoawaesiwsonwriaoaz o ^ ~s,,,~„oT~~ SM8~008&1158e~10T10DB2 0 ~51188c~10T5UeP ^ SlOBOC100BSt775e~10T70DB7 n SMB08900BS1185c~tOT5D82 ^ SMB06900B6fOeSc~tOT1WB1 ^ SlD60B900B6111 Sc~ 70 TSDB7 ------^------------------------------------------------ ^ s ^ ' ~ . . ^ ~ ^ ^ ~ ~ ~ ~' ° ~ ,- ° C O 0 0 '_'_______'____~___'____'_____'____________b__'____"~ rate to wit m . a accuracy. It is important to note that this flow metering approach has no fundamental size limitations and should be applicable to turbulent pipe flows of all diameters and Reynolds numbers. Furthermore, similarity laws suggest, and data from Figure 4 support, that the relationship between convection velocity and flow rate from geometrically similar meters of any size is be govemed by same Figure 4: C~Iibration data. Reynolds number based calibration. It can be concluded from the data presented that the 95% confidence level of the sonar based flow measurement equals 0.42%. 3.5 Industrial applications Numerous industrial applications for the sonar based flow measurement have been developed in close co-operation with end users over a period of more than 2 years. The industrial applications are to be found were the clamp on, non intrusive, large bore capability of the sonar based principle results in undisputed advantages in terms of life cycle cost, reliability or the sheer impossibility to make any other measurement device work. Examples of such are: • Hydro transport of oil sand8. • Thick stock flow in paper and pulp9. • Air conveyed transport of particulate material. • Two phase flow of water and oi110 ". • Sewer water processing. • Flow of coating pastes. • Magnetite flow in minerals processing. All of the above examples of industrial flows are characterized by their abrasive and/or corrosive nature. In many cases this necessitates the use of special pipe materials or the use of lined (Teflon, rubber, concrete) pipe. The phenomenon of pressure fluctuation induced circumferential pipe strain is universal and independent of the precise nature of the pipe material or lining. As a result a sonar based measurement can, in most cases, be applied without a process shut-down, without cutting the pipe and without elaborate operational procedures or safety measures. In selected cases the operating principle of the sonar based meter removes a calibration difficulty inherent in the traditional measurement principle. For instance, in the flow rate measurement of magnetite suspensions by electromagnetic flow meters the ferro magnetic nature of the suspended particulates affects the meter's calibration. As a result the meter may drift with magnetite concentration. Figure 5 shows two frequency distributions of the relative difference between a sonar based and electromagnetic flow rate measurement for both high (1.70 kg/dm3) and low (1.65 kg/dm3) density magnetite suspensions in the feed flow to a BI0197 RevB • • 30000 24000 c 18000 ~ 0 v tz~oo sooo Flomeko 2005 6 - 9 June 2005 100°/ 10000 80% 8000 ~ c 8000 ~ 0 aox ~ aooo xo% zooo o% 100% 80% m 60% w io ~ ao^~ ~ ~ zo~ o^~ Figure 5: Frequency distribution of the relative offset of sonar versus mag meter. series of reverse flotation cells. As in this specific example neither meter was "nulled" relative to the other, either the high density histogram or the low density histogram may be used as a reference for the other. It follows that the difference between the finro meters, sonar and an electromagnetic, has shifted by about 5% with the change in the magnetite concentration. This is believed to be due to the fact that the calibration of the electromagnetic flowmeter is dependent on the actual concentration of magnetite in the flow. A flow meter that is not affected by the detailed make up of the fluids flowing and any particulates therein is a very clear advantage. It is to be noted that in other comparable cases, where non magnetic particulate material is suspended in the flow, the difference between sonar and an electromagnetic flow meter is not affected by the density. 4 MEASUREMENT OF GAS CONTENT Using a similar, and in many cases the same, hardware platform it is also possible to measure the velocity of sound of acoustic waves propagating in the process piping. The propagation of acoustic waves occurs at frequencies much above the frequency domain of vortical pressure fluctuations, therefore the same sonar processing can be applied to determine both the acoustical velocity and the voritical velocity at the same time. The relation between speed of sound in twophase mixture and the volumetric phase fraction is well known in case the wavelength of sound is larger than the pipe diameter and hence also significantly larger than any process in homogeneities such as bubbles. 4.1 Velocity of sound in liquid/gas mixtures The mixing rule'Z, known as Wood's equation13, expresses the fact that in a mixture the compressibility of the mixture equals the volumetrically averaged compressibility of the pure components. For the mixture density a similar rule holds: the mixture density equals the volumetric average of the pure component densities. Because the velocity of sound in a fluid equals the square root of the compressibiliry over the density, the two mixing rules can be written as: 1 ~O 1- ~p + PCZ Pg~g Pt~i (4). P = 9~Pg + (1- ~P)P~ Here, ~ is the volume fraction of gas at line conditions, c is the speed of sound, p the density and the subscripts g and I refer to the gas and liquid phase respectively. Figure 6 illustrates the relation between mixture sound speed and gas content for an air water mixture. In most industrial processes, at moderate temperature and pressure line conditions, the compressibility of the gas phase is orders of magnitude larger than the compressibiliry of the liquid phase. Inversely, the density is dominated by the liquid density. As such, it will be necessary to measure the process pressure (when varying) as both the gas density and the BI0197 RevB 0% 5% 10% 75% 20% 0% 5% 10% 15% 20% • • Flomeko 2005 6 - 9 June 2005 liquid density are significant when determining the gas volume fraction from the mixture sound speed. Conversely, neither the velocity of sound in the liquid nor the velocity of sound of the gas is a significant factor for mixtures where one phase is gaseous. In fact, the denominator of the first term in the Wood's equation equals the product of process pressure and polytropic exponent of the gas demonstrating that the gas content at line conditions can be determined using the velocity of sound independent of the gas molecular weight or the gas temperature. Hence, the determination of the gas content using mixture speed of sound is independent of the gas type 0 d 'll b ~ E 1 00 v m a ~ ~ 100 ~ 0 ~ ~ ~ x ~ 10 ~~ ,~ ---•-S Da~ . ~ ~ - 4 bar \~'• '~~•-~ . . --•- . ~ _, \ '' '~ - _ `~,~~~ ..'__. -_- - 5bar ~-~__ ' ' •• '- : - . .. ..._ , an w~ e accurate irrespective of the type of gas, which can be either air, carbon- dioxide, hydrogen or any mixture thereof. 0% 5% 10% 15% 20% Gas wlume iraction Figure 6: Mixture sound speed vs. gas volume fraction. (4). The distensibility for thin walled, untethered pipe is given by: D _ 2R Et For mixtures confined to a pipe, a correction to above formulae (4) is necessary in order to account for the relative change of pipe cross sectional area upon intemal pressure variation. This so called distensibility14, D, is an additive term to the first equation of (5), where R is the pipe's internaf radius, t is the wall thickness and E the pipe materials' Young modulus. In steel pipe, the distensibility is quite small because of the large value of the Young modulus of steel. In aluminum, glass or even plastic pipe, however, the distensibility must be accounted for. The effect of the pipe distensibility is lower the apparent, measured speed of sound. For instance in a water filled 4" plastic pipe with a wall thickness of 5.5 mm and a modulus of 3.5 GPa, the measured speed of sound will be 420 m/s at zero aeration. This is a striking difference with the free space velocity of sound in water of 1480 m/s. 4.2 Measurement of the velocity of sound As described above, the relationship between mixture sound speed and entrained air in bubbly liquids is well established. However, as will be developed below, in bubbly flows, these relations are only applicable for the propagation of relatively low frequency, long wavelength sound. While this restriction does not present any significant obstacles for the sonar meter, it does present significant challenges to ultrasonic sound speed measurement devices. Ultrasonic meters typically operate in 100 kHz to several MHz frequency range. For these meters, entrained air bubbles have length scales on the same order as the acoustic waves generated by the ultrasonic meters. This poses several problems for ultrasonic measuring devices. Firstly, the bubbles scatter the ultrasonic waves, impairing the ability of the ultrasonic meter to perform a sound speed measurement. Secondly, ultrasonic meters rely on information derived from only a small fraction of the cross sectional area of the pipe to be representative of the entire cross section, an assumption that breaks down for flows with non- uniform distributions of in homogeneities, such as stratification of entrained air towards the top of process lines. BI0197 RevB i ~ Flomeko 2005 6 - 9 June 2005 Sonar flow meters use an approach developed and commercialized specificaliy for multiphase flow measurement in the oil and gas industry in which multiphase challenges described above are routinely encountered. Sonar meters measure the propagation velocity of operationally generated sound in the -100 to 1000 Hz frequency range. In this frequency range, sound propagates as a one-dimensional wave, using the process pipe as a wave-guide. The wavelength of sound in this frequency range (>1 m) is typically several orders of magnitude larger than the length scale of the any bubbles or flow non-uniformities. The long wavelength acoustics propagate through multiphase mixtures unimpeded, providing a robust and representative measure of the volumetrically averaged properties of the flow. For the sound speed measurement, the sonar flow meter utilizes similar processing algorithms as those employed for the volumetric flow measurement. As with convective disturbances, the temporal and spatial frequency content of sound propagating within the process piping is related through a dispersion relationship. w = kc (6). As before, k is the wave number, defined as k=2~/A. (1/m), w is the temporal frequency (rad/s), and c is the speed at which sound propagates within the process piping. Unlike disturbances which convect with the flow, however, sound generally propagates in both directions, with and against the mean flow. For these cases, the acoustic power is located along two acoustic ridges, one for the sound traveling with the flow at a speed of c+ V and one for the sound traveling against the flow at a speed of c- V. ~ ~ ~ Figure 7: k-w plot for 3% entrained air in water 4.3 Industrial applications Figure 7 shows a k- w plot '50 generated for acoustic sound field recorded from still water containing -3% entrained air by volume in an -~ 8 in, schedule 80, vertically oriented Plexiglas pipe. The k-w plot was constructed using data ~ from an array of strain based sensors clamped to the outside of the pipe. Two acoustic ridges are clearly evident. Based on the ~ slopes of the acoustic ridges, the measured sound speed for this for this mixture was 70 m/s, consistent ~ with that predicted by the Wood equation. Note that adding 3% air by volume reduces the sound speed of the bubbly mixture to less than 10% of the sound speed of liquid only water. As was mentioned in the introduction, there are two applications of the full bore measurement of entrained gas of distinctly different character. First there are those where process aeration must be controlled or where process aeration must be avoided altogether. Examples of such are: • Natural froth lubricity flows. • Gas sparging in flotation cells. • Dissolving carbon dioxide in beverages. • Entrained air in the thin stock flow to a paper machine's headbox75. • Entrained air in filling stations for domestic household products. Second there are applications where entrained gases negatively affect the process indirectly by affecting other types of ineters. Examples of this second kind are: BI0197 RevB w~~,~ ~i~~ ~ Flomeko 2005 6 - 9 June 2005 ~ • Errors in consistency measurement of paper stock.t6 • Errors in the determination of net oil using watercut meters". • Errors in Coriolis determined volume flow as a result of product aeration18. • Errors in custody transfer metering resulting from product flashing or aeration. The sonar based measurement of process aeration using the velocity of sound covers almost 5 orders of magnitude, from 0.01 % to above 20%, and is therefore universally applicable to a wide variation of process conditions. By way of example Figure 8 gives the amount of ~ entrained air in a volume of paper 0 6 v 0 5 ~ ~a LL m ~ 3 0 > 2 N N c~ ~ 0 stock just before and just after the dosing of a commercially available defoamer chemical. Given the continuous character of the measurement and given the fact that this full bore measurement is, unlike a sampling system, representative of the true air content the ability to control defoamer dosing presents itself. Such dosing control will not only help reduce defoamer volume it -~20 -so o so ~2o will also help reduce process Time [s] variability. Thus product qualiry is positively impacted whilst at the Figure 8: Defoamer dosiug application same time cost is reduced. Conversely, in applications where the amount of air or gas in a process must be kept at a stable level in presence of gas consumption by chemical reaction, this sonar based measurement can provide hitherto unavailable compositional information even on large diameter reactor vessels.. Just reversing the time scale in Figure 8 is sufficient proof of this claim. 5 CONCLUSIONS Sonar based flow monitoring enables the direct measurement of the convective transport velocity of turbulent eddies in pipe flow and it enables the direct measurement of the velocity of sound propagating through the pipe. Both measurements can be made using an array of strain based sensors clamped to the outside of the process piping. Evidence is presented to prove that the convective transport velocity of turbulent eddies is proportional the volumetrically averaged mean velociry. A Reynolds number based, empirical calibration is given which yields 0.5% accuracy for Newtonia~ fluids. Thus, a novel technique based upon naturally occurring phenomena in pipe flow allows the realization of a calibrated flow meter. Industrial applications of the sonar based flow meter in abrasive and corrosive fluids are discussed. An example in magnetite flows is given where the passive nature of the sonar based instrument proved to be a distinct advantage. It is shown how the velocity of sound in a twophase medium can be used to derive compositional information such as gas volume fraction. The necessary correction for the effect of the enclosing pipe is developed. The effect of fluid and gas properties on the calculated gas content is discussed. Neither the temperature nor the gas' molecular weight has any influence, only the liquid density and the process pressure must be known. An industrial application of the gas volume fraction measurement is presented. This defoamer dosing example is one of many which have been found. BI0197 RevB • ~ Flomeko 2005 6 - 9 June 2005 6 ACKNOWLEDGEMENTS The results presented in this work have benefits from several years of collaborative efforts to develop sonar-based flow measurement. The authors gratefully appreciate the efforts of the many colleagues and caworkers that have contributed to results presented herein. 7 REFERENCES 1 NIELSEN, R.O., Sonar signal processing, Artech House Inc, Norwood, MA, 2001, ISBN 0-89006- 453-9 2 KRAGAS, T. K., et al., " Downhole, Fiber Optic Multiphase Flow Meter: Field Installation" Presented at the Society of Petroleum Engineers Annual Conference, SPE Paper #77654, September, 2002. 3 KRAGAS, T. K., et al., "Downhole Fiber-Optic Multiphase Flowmeter: Design, Operaring Principle, and Testing," Presented at Society of Petroleum Engineers Annual Conference, SPE Paper #77655, September, 2002. 4 MATULA, J. P. and KUKKAMAKI, E, "New findings of entrained air and dissolved gases in pm wet end: mill case study," TAPPI JOURNAL, Apri12000, Vol. 83 5 LANDAU M.T., MOLLO-CHRISTENSEN, E., Turbulence and Random Processes in Fluid Mechanics, 2nd Edition, Cambridge University Press, Cambridge, UK, ISBN 0-521-42213-2, 1992. 6 SCHLICHTING, H., Boundary Layer Theory, McGraw-Hill, New York, ISBN 0-07-055334-3, 1979 7 BERANEK, L.L., VER, I.S.," Noise and Vibration Control Engineering," Section 14.6, John Wiley and Sons, New York, ISBN 0-471-61751-2, 1992 8 GYSLING, D.L., MUELLER, E., Application of sonar based, clamp on flow meter in oil sand processing, ISA 2004 Exhibit and Conference, Edmonton section, April 2004. 9 GYSLING, D.L., LOOSE, D.H., Sonar based volumetric flow meter for pulp and paper applications, CiDRA Corporation, Wallingford, CT, 2003, unpublished work. 10 GYSLING, D.L., VAN DER SPEK, A.M., Fiber optic downhole multiphase flow meter: flow loop evaluation for oiUwater mixhues, Downhole Instrumentation seminar, North Sea Flow Metering Workshop, Glasgow, Scotland, 23 October 2000. 11 GYSLING, D.L., VANDEWEIJER, T., VAN DER SPEK, A.M., Development of a permanent downhole twophase flow meter, SRI mulriphase metering and pumping conference, Houston TX, February 2000 12 MC WILLIAM, D. DUGGINS, R.K., Speed of sound in bubbly liquids, Proc Insm Mech Engrs, Vol 184, Part 3C, 1969-1970. 13 WOOD, A., A textbook of sound, New York, NY, lst edition, 1930 14 LIGHTHILL, J., Waves in Fluids, Cambridge University Press, Cambridge, 1980, ISBN 0-521- 29233-6 15 GYSLING, D.L., LOOSE, D.H., Sonaz based volumetric flow and entrained air measurement for pulp and paper applications, TAPPI Spring Technical Conference, paper 58-1, Chicago, IL, May 2003. 16 STOOR, T., AMMALA, A. NIINIMAKI, J., Measurement of air content of pulp suspension - sonar method, APPITA 2005 pulp and paper conference, Auckland 16 -19 May 2005. 17 GYSLING, D.L, LOOSE, D.H., Using sonar bsed gas volume fraction meter for improved net oil rate measurement, Canadian School of Hydrocarbon Management, Toronto, 2005. 18 GYSLING, D.L., BANACH, T. Accurate liquid phase density measurement of aerated liquids using speed of sound augmented Coriolis meters, ISA, Houston, October 2004. BI0197 RevB 10 i ~ -~~. ~i ~SPE - Internatianat , ~: SPE 100893 New Class of Meter Solves Old Probiem Impacting Well Test Accuracy E.R. Ward, SPE, BP Exploration (Alaska) Inc. Copyright 2006, Society of Petrdeum Engineers This paper was prepared for presentation at the 2006 SPE Weslem Regional/AAPG Pacific SectloMGSA Cadilleran Section Jdnt Meeting held in Ar~chorage, Alaska, U.SA., 8-10 May 2006. This paper was selected for presentatlon by an SPE Program Committee fdlowing review ot informado~ contained in an abstract submitted by the author(s). Contents of ihe paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are suDject to correctlon by tlie author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its of6cers, or members. Papets presented at SPE meetings are subject to publication review by Editorial Committees of the Sociely of Peholeum Engineers. Electronic reprodudion, distribution, or staage ot any part of this paper for commercial purposes without the written consent of the Sodety of PeVdeum Engineers is prohibited. Pertrussion to reproduce in print is restricted to an abstrad ot not rtare than 300 words; illustrations may not be copied. The abstract rtwst contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract For the first time in a BP-operated asset, the impact of entrained free gas (not solution gas) in the liquid outiet line of a well test separator is quantified for the purpose of correcting gross fluid volumes and density measurement. This paper describes the results of deploying a sonar based, clamp-on gas void fraction (GVF) meter at a test facility in the Prudhoe Bay Unit (PBU) on Alaska's North Slope. Introduction The PBU has been in production since 1977. Over the life of the field several different Test Separator configurations have been utilized. Approximately 16 years ago, PBU started to use the density water cut method on 2-Phase Mini Test Separators to overcome problems that were encountered on the conventional3-Phase Units. In general these units operated successfully; success was measured by repeatable water cut results that enabled the petroleum engineers to improve management of the wells and have more confidence in production changes as a result of well workovers. Cold viscous crude oil has now been introduced into the PBU production facilities increasing the range of the oil API gravity from 22 to 32 API now down to 17 API. This brought a whole new set of problems. As part of this project two new mini 2- Phase Test Separators were installed. A review of the liquid leg densities of the units handling viscous oil indicated the possibility of free gas with a resultant gas void fraction (GVF). This particular test facility employs a coriolis meter to measure density and gross flow rate of the oiUwater mixture. It was confirmed that discrepancies in allocation factors and individual net oil measurements, especially for cold high viscous crude oil, was due in part to unrecognized gas carry- under in the liquid outlet. Measured GVF associated with wells flowing `non-viscous' oil, the less viscous crude (22 to 32 API) ranged from 0- 2.0 %, whereas the GVF of wells flowing viscous crude (17 to 22 API) was between 0- 8% at normal vessel liquid levels increasing to >20% at reduced separator levels. The additional secondary phase measurement enables PBU to now report real time corrected densities and volumes using an in-house method to calculate water cut. In addition to viscous crude, we believe that application of this technology to smaller, somewhat under-sized separators with less stable operations will provide value across the industry. Well testing importance is increasing on the maturing fields of the North Slope of Alaska as it is not oniy used for the critical function of field management that ensures optimum production from a field; it also is a regulatory requirement set by the State of Alaska and may be used for Production Volume Accounting on fields with co-mingled production facilities. This paper is a brief report of the findings of a preliminary test and a more extensive pilot project of a strap-on sonar based GVF meter on both `non-viscous' crude oil and satellite field viscous oil. The preliminary test was a quick check to determine if the GVF meter could measure a meaningful GVF on the two crudes. With a favorable result to the preliminary test the pilot project was instigated and the unit was installed and fully integrated into the well testing system. Since being installed in October 2005, the unit has been used for on-line well testing. The objective was not only accurate GVF measurement to improve water cut and gross fluid volume accuracy but also to check for long term stability. A stable Zero GVF measurement is a critical issue especialiy when the unit is used for all types of crude oil and on many wells having little to no GVF. To quantify the impact of GVF on the Test Separator operations in PBU, a 1% GVF equates to an understatement of water cut (WC) by 5% and a direct 1% over statement of gross fluid flow. As the title of this paper indicates this meter provides a solution to a long standing problem. This is the final piece of a puzzle that has taken many years to solve. In order to have a better understanding of how our approach has developed the first few sections of this paper will provide a brief overview of ~ ~ SPE 100893 the PBU and a history of Well Testing, Oil Allocation and Test Separator improvements in the PBU. Overview of Greater Prudhoe Bay (GPB) produced tk~rough the PBU facilities. Well testing is again mainly for field management but more importantly for regulatory purposes to prove the field is being operated and managed in a prudent manner and to maximize overall fluid recovery. GPB is a Production Unit of several oil fields (formations). The Initial Participating Area (IPA) within PBU is by far the largest and has been the main driving force in the development of the Test Separator Systems described in this paper. The most recent business need has been the introduction of small satellite fields to the IPA facilities and the problems of cold viscous oil. The PBU was from concept split into two operating areas by the owners with the agreement of the State of Alaska; the Western Operating Area (WOA) operated by BP and the Eastern Operating Area (EOA) operated by Atlantic Richfield Company (ARCO). In addition there was a different ownership split between the Gas Cap and the Oil Rim Participating Areas. After the BP/ARCO merger, BP is now the sole Operator of PBU and the field has been unitized with aligned working interest ownerships in Gas Cap and Oil Rim Participating Areas. The Test Sepazator operations described in this paper are from the WOA. Impacts of Well Testing As with all oil and gas fields, PBU well testing is used for field management. A very critical function used to optimize production rates and total hydrocarbon recovery from the field. With the early ownership differences between the Gas Cap and the Oil Rim, well testing was critical in the determination of the Gas Oil Ratio (GOR), one of the parameters used to select a well for inclusion in the Gas Cap or Oil Rim. As gas production increased beyond the agreed associated gas volume (determined at a 1000 GOR) the importance of well testing in this area reduced and the gas condensate allocation was then by an agreed liquid volume factor in the gas and simply determined by measuring the overall gas volume. The introduction of satellite field production into the IPA Processing Facilities created the problem of production allocation to the conect field. There was a different tax / royalty regime for IPA and the PBU satellite fields. By prior agreement with the State of Alaska well allocation was the selected method for individual field production. The overall volume of crude oil was measured to custody transfer standards; allocation and well testing determines the production split between the IPA and the individual satellite fields. This obviously increased the importance of well testing and PBU in collaboration with the State of Alaska undertook a major program to upgrade and improve oil allocation and well testing operations. With the merger of ARCO and BP the PBU Gas Cap - Oil Rim ownership difference has been eliminated. Also the State of Alaska has recently equalized the t~ation rate for all oil Oil Allocation Methodology As the PBU evolved over time, so has the Oil Allocation Process changed to meet the new challenges. WOA has three production facilities known as Gathering Centers (GC) where oil, gas and water are separated, the gas is dehydrated before shipment to the Gas Plants and re-injection into the field. The EOA also has three production facilities known as Flow Stations (FS). Oil is shipped to Pump Station 1(PS 1) of the Trans Alaska Pipeline System (TAPS) for metering to custody transfer standards. Alyeska Pipeline Service Company (ALPS), the company operating TAPS, operated two metering systems, one each for EOA and WOA. As production has declined ALPS reduced metering to one combined meter set for EOA and WOA. Also GC 3 passes partially processed oil to FS 3 so only five production facilities are now producing directly to TAPS. All of these changes have had an impact on the allocation process. The following simplistic statistical model demonstrates the impact of inetering accuracy on the allocation process. Taking the WOA as a model there are three levels at which oil metering is made; Fiscally at PS 1, Production Metering at the outlet of the GC and individual well production (Well Testing). In order to measure a total volume of 300 MBPD to an accuracy of 1% the choice is to either measure with one 300 MBPD meter with an accuracy of 1%, or three 100 MBPD meters with an accuracy of 1.75% or three hundred 1 MBPD meters with an accuracy of 17%. "The WOA has gone from initial allocating process of allocating from PS 1 to the GCs and then to the associated wells to allocating directly from PS 1 to the all wells and back to the intermediate GC step process. The reason for the reversal was that the number of wells had grown significantly and inaccurate testing was being hidden. The wells needed to split up in to smaller groups so as to determine the problem areas. Brief History of Test Separators The following describes the fixed in place Test Separators. If at any time these units were having operational problems Portable Separators were utilized to ensure the required well testing was performed and the overall allocation process was accurately maintained. The initial test separators were Test Banks (3 Stages of Separation) in the GCs. This ensured the oil volume measurement was of sales quality crude corrected to Stock Tank Barrels (STB). As the field developed Test Sepazators were installed at the Well Pads operating at elevated pressures. This introduced the problem of "Oil Shrinkage", the change in volume of live crude at test separator conditions to STB. ~ • SPE 100893 To overcome this problem PBU carried out a lazge project of correlating test results from the Well Pad Separators to the same well tested in the Test Bank. From this large data base an algorithm were developed that provided two factors, Oil Shrinkage and Solution Gas (SCF per unit volume) to be applied to the Test Separator results. Recently PBU updated this data base utilizing a customized equation of state to improve the accuracy of these factors. The initial Well Pad Test Separators were large 150 Barrel 3-Phase units. Turbine meters were used for oil, water and gas. Master Water and Oil Meters were installed to check the accuracy of the on-line meters. A capacitance probe was installed in the oil leg to detect the water cut up to 20%. In general these systems worked well but problems started to appear when the water cut and GOR started to increase. This was especially true when PBU came off the production plateau. Several improvements were made including replacing the liquid turbine meters with vortex units and modifying internals of the separators. The significant problem with the capacitance probe system was that it could only be customized on a per well pad basis and individual wells on the same well pad were e~chibiting significant different physical properties which impacted the water cut accuracy. PBU had installed three mini (40 Barrel) 3-Phase Test Separators that were experiencing significant problems. The results made any field management of the wells in that area very difficult. In 1989 PBU decided to install a direct mass flow meter using the density water cut method on the liquid leg of the separator which was converted to a 2-Phase unit. This method proved so successful that it was installed on eight of the 3-Phase Units. In addition the three GC Test Bank Separators have been reduced to a single stage unit using the density water cut method. The two new satellite field Mini (30 Barrel) 2-Phase Separators are all based on this method. These units did have a microwave water cut meter installed in the liquid leg, but they have never been used on-line. Water Cut Calibration Methods for Density Based Water Cut Measurement All water cut analyzers need to be customized to specific well fluids. This may even be on a per well basis. The proprietary system installed required a`pseudo' oil density that would be temperature compensated using API Volume Correction Tables to give the oil density at line conditions. The first calibration method implemented simply fixed the water density and adjusted the oil density until the water cut matched spinout tests of the crude oil for each well. This was later improved by taking live samples to the laboratory where an analyzer measured the oil and water densities at line conditions and the' pseudo' density was calculated. Both methods were satisfactory but required careful co-ordination of the well in the Test Sepazator during sampling and were very man-hour intensive. With the updating of the eight 3-Phase Test Separators to 2-Phase Units, the addition of the two new 2-Phase Units for the viscous oil and the associated significant increase in well count the existing methods of calibration became virtually impossible to maintain. In addition the laboratory analyzer proved not to be satisfactory and was taken out of service. All of these problems lead to a fundamental reevaluation of the calibration methods and even the density method itself. New Approach to the Water Cut Density Method The following is only a brief outline of the in-house developed method that will assist with understanding the main topic of this paper; GVF measurement and the application to test separators. The basic intent of the method was to reduce sampling requirements while not impacting metering accuracy. The method is based on mass which does not change for pressure and temperature variations or for mixing two fluids together even if they are in different phases. Live crude is just stock tank barrel crude oil with gas in solution. Therefore the density of live crude can be predicted by simply adding the mass of the oil and the mass of the solution gas together. The key to understanding this system is oil shrinkage and solution gas. These pazameters aze fundamental to well testing at elevated pressures and temperatures. Typically a well test determines the volume of live oil at separator conditions; the oil volume is then shrunk to provide the daily production volume in STB terms. The density of stabilized crude and dry gas can be determined at both base and line conditions (Pressure and Temperature compensated) using API and AGA 5tandards. The density of water can be determined by well established and internationally accepted algorithms at both line and base conditions. The hydrocarbon (Oil plus Gas) density at line conditions is the sum of the oil line density with oil shrinkage applied plus the mass of solution gas on a per unit basis. The water cut is determined using the standard equation for the mixture of two fluids of known densities from the measurement of the line fluid density of the combined fluids. The unique part of the method is that the actual oil, gas and water volumes at line conditions can be determined. Therefore it is possible to mass balance the liquid leg by comparing this calculated mass to the measured mass flow from the direct mass flow meter. The method adjusts the solution gas in the density model until 100% mass balance is achieved. This has been demonstrated to improve the water cut accuracy. Benefits of the New Approach The oil shrinkage and solution gas factors are based on pressure, temperature and GOR. Therefore the metering on the Test Separator is now fully integrated as the off gas flow impacts the liquid leg measurement for oil and water. More specifically the hydrocarbon fluid density in the liquid leg is fully compensated to all pressure, temperature and GOR conditions. The only pazameters to be input to the method are the base specific gravities of dry oil and water. This significantly reduces the sampling complexity as only the well fluids at STB conditions are required and not at the line conditions. i ~ SPE 100893 As the method provides on a real time basis the STB water cut, it can be compared directly to the laboratory determined water cut which is made at 0 PSIG. There is a significant difference between the on-line water cut and the STB water cut especially with oil shrinkages of up to 30%. Problems on the Viscous Oil Test Separators Most of the early problems were associated with the fact the units were open to the Artic environment and meters were not installed in the most advantageous way. These difficulties were siowly overcome and the new density method was installed on the separators. A review of the measured density in the liquid leg of the separators indicated a significant quantity of gas in the liquid leg which had a detrimental impact on both the total fluid volume and the water cut determination. The addition of GVF in the liquid leg means there are three unknowns but the calculation method only provides two equations. The third unknown, GVF had to be quantified for the density method to work. Selection of the GVF Meter BP was performing wet gas meter tests and during a presentation of this test a sonar based strap-on unit was presented that was claimed to measure GVF in the 0-20 % range. The unit is passive; it listens to audio frequency noise signals in the fluid and using sonar techniques determines the speed of sound (SOS) of the fluid in the pipe. In this frequency range the wavelengths are several feet, therefore the transducer is measuring the physical properties e.g. free gas that is present a significant volume of the fluid and not just a slice across the pipe. The relationship between the SOS and gas in a liquid (GVF) is very well established and documented. Preliminary Tests It was decided to perform a preliminary test on the liquid leg of a Test Separator that tested both PBU and satellite crude wells. The objective of these very simple tests was to determine if the unit would measure a GVF and whether it would track expected GVF values when the level in the vessel was raised or lowered. Two units were installed; one upstream of the mass meter (horizontal) and a second downstream of the mass meter (vertical down). The intent of the preliminary tests was not only to confirm satisfactory operation of the GVF meter but also to try and select the best position for a more extensive test. The results of two days of trials were very favorable. A GVF was measured in both crudes in the range of 0- 30%. The GVF measurement performed as expected; it increased in value for a lowering vessel liquid level and decreased in value for an increasing vessel liquid level. Typically both units tracked; however on high GVF values (> 15%) the downstream meter indicated up to twice the upstream unit. This was believed to be a piping issue with gas trapped in an inverted U section of pipe and the flow of fluid was not great enough to sweep the buildup of free gas. See Figures 1 and 2 for the GVF plots of these tests o.~ 0.8 ~ o.s ~ ~ o.~ e LL p 0.3 > . n o.z o., 0 sm:ooen:~sao srmrmostrzt~t snenaos~~n:x~ vzaveosi~xaa aizoriaosn,u~ y1WtOp617A1.S0 Figure 1- Downstream GVF Meter on a Typical PBU Well (26°API and 98°F) as ~o .......,~,=tream 25 - Dw~retream ~ zo ~ S e ~ ,s ~ ~ ,o o i I f - I I I ymaooa e:w ynmoa r.az mams e:u snxooe ~oAe m~om »:~e ynrxoos ~x:so Figure 2- Comparison of Upstream and Downstream GVF Meters on a Cold Viscous Well (18°API and 54°F) Extended Pilot Test As a result of the favorable preliminary test it was decided to install a unit into the well testing system and to monitor its performance. The new in-house density approach is programmed into a stand alone flow computer that has fully flexible customer programming capability. The program was updated to include the GVF function in both the density calculation and the gross volume calculation. In addition the free gas was added to the off gas and the free gas was included in the mass balance of the liquid leg. To enable the operation to be monitored closely an extensive data gathering system was also configured into the flow computer and the Supervisory Control and Data Acquisition (SCADA) System. The SCADA System performs the well test function and the following parameters were retrieved in addition to the standard data for well testing. • Gas Void Fraction • On-line Measured Density • GVF Corrected Density • Calculated On-line Hydrocarbon Density • Calculated On-Line Water Density ~ • SPE 100893 5 • Mass Flow • STB Oil Flow • STB Water Flow • On-line GOR • STB GOR • Mass Balance % • Solution Gas Correction Factor Data was gathered approximately every 20 seconds. This real time data has enabled PBU for the first time to monitor very closely how the density method operates on a 2- Phase Separator. Review of Prelicninary Results of the Pilot Test The water cut methodology is based on fluid densities so tracking how the hydrocarbon and water densities vary on-line and how the measured liquid leg fluid density compazes to these densities is critical. For example the GVF values we have witnessed on these tests can take the measured density from less than the hydrocarbon density to higher than the water density. That is from 0% water to 100% water. The test separator is at an unmanned site and the only monitoring is restricted to measured / calculated variables; it was not feasible to bring back the status of the sonar unit. The dilemma is to know when an accurate GVF is being measured. The GVF transmitter was setup to freeze at the last known good answer. The GVF is not expected to be constant; therefore no "plateaus" should be expected on a plot of GVF. Reviewing the GVF transmitter status when this happens reveals two basic reasons; either poor signal quality or invalid speed of sound data. The downstream unit was selected as the primary meter for the test. Initial results looked promising; however we witnessed excessive swings in the indicated GVF (0 to 20 %+) with the associated large variations in water cut. This was a repeat of the high GVF measured during the preliminary test caused by a buildup of free gas in the inverted U section. The upstream unit was now selected and all tests were made using this unit. The first criterion for success was to determine if the GVF conected line density lies between the hydrocarbon and the water densities. If this is satisfied the metering methodology will be able mass balance the liquid leg of the separator. The method will not be able to mass balance the liquid leg if this criteria is not met. A Portable Test Separator is used to check well tests especially if the results are questionable. This portable separator is manned on a 24/7 basis and it is customized for each well test. This is considered the best well test we can achieve. Therefore the second criterion was to compare the well test result from the on-line separator to the last test using the portable separator. testing cold heavy viscous crude the results presented and discussed in this paper are for a viscous well. The initial tests on one particular well showed little to no GVF but as time progressed tests started to have large GVF swings and plateaus on the GVF data plot. The status of the unit was low signal quality and invalid SOS data. The first reaction was to question whether there was enough noise to enable the meter to function. After all the unit in use had the greatest distance to the liquid control valve, the expected source of the noise. A data "snap shot" was submitted to the manufacturer who stated the signal strength was good but the unit was not able to successfully analyze the SOS data. It was noted that when the wells are tested with the portable separator unit chemicals are injected into the crude, in particular anti-foam. Anti-foam was injected into the well flow-line. Figure 3 shows the response of the GVF Meter and the density water cut methodology to this anti-foam. The plot is for 8 hours with the anti-foam injected at appmximately 5 hours into the plot. The well test was for 4 hours and this plot shows the first 3 hours of this test. There was an immediate improvement to the whole system. Parameters no longer had wild variations and the GVF corrected density was now solidly in between the hydrocarbon and water densities and steady. For the well in question the measured on-line density was significantly below the calculated on-line hydrocarbon density. u,~oa~M cvFCwo~ay -•-•-HCC~~o~~ ...----w~.ce~o~~y cvF ss s~ sz ~ ~ a ~ a~ ° ~~ ~ ~ ~e o so ,zo ,eo zao soo aeo azo Minubs ,z ~ ~o ~ 8 ~ s Figure 3- the impact of Anti-Foam on the pertortnance of the GVF Meter on Viscous Crude Oil The following well test result using the fixed separator and the new methodology including the GVF Meter and the standard SCADA well testing system was obtained and compared to the last Portable Test Separator test Portable Se arator Fixed Se arator Oil BPD 366 498 Water BPD 29 42 GOR 1142 1272 Water Cut % 7.3 7.8 In general the unit operated satisfactorily on PBU crude. However as the main reason for using the GVF meter was Table 1- Well Test Comparison of Portable to Fixed Test Separator ~ ~ SPE 100893 Conclusions The preliminary results of the pilot test to date look very promising; the objectives of the test are being met, i.e. to check the long term stability and pedormance of the GVF Meter under differing conditions. The presence of free gas in the liquid leg of the mini Test Separator when testing cold viscous wells was postulated; the GVF Meter has provided a quantitative measurement of this free gas. The secondary objective was to try and determine limitations of GVF Meter which we have achieved. When testing viscous wells with water present it is important to inject anti-foam to make the system operate correctly. Please note these wells have gas artificial lift. Only the results of one well are provided here because formal review all the data from all wells needs to be collected before it can be disseminated. Preliminary reviews indicate that a GVF is present in all well testing even on the PBU wells. However three of these GVF Meters will be installed on three mini 2-Phase Test Separators working on viscous and PBU crude oil. Several years of work has gone into perfecting the approach to the density method water cut. The addition of the GVF capability is the last piece of the puzzle to ensure accurate well testing. Acknowledgements I thank the management of BP Exploration (Alaska) Inc., Conoco Phillips Alaska Inc. and Exxon Mobil Corp. for their support and for granting permission to publish this paper. I thank Fred Bakun for all the work he provided in developing the oil shrinkage and solution gas factors that enabled the new approach to density water cut to be developed. Also for all the patient hours we spent in detailed discussion to fine tune the overall density method. I would also like to thank: Richard Volz of E&P Technology Group, BP America Inc for his support of this pilot program which enable BP Corporate to provide funds towards the pilot program and for his encouragement to perform these tests and publish this paper. Michael Bolkovatz, Hal Tucker, Rob Kruger and Bruce Weiler for their support and encouragement as well as their technical insight that was invaluable to assist with solving this problem. Douglas Loose for his valuable support during installation and commissioning of the GVF Meter. His technical assistance with solving the GVF performance problems during the pilot tests proved to be valuable for solving the operational problems. Nomenclature GVF = Gas Void Fraction % API = American Petroleum Institute AGA = American Gas Association PBU = Prudhoe Bay Unit (Oil Field on the North Slope) IPA = Initial Participating Areas GPB = Greater Prudhoe Bay (PBU plus Greater Point Macintyre and other satellite fields) WOA = Westem Operating Area of the PBU EOA = Eastern Operating Area of the PBU GOR = Gas Oil Ration SCF / Barrel GC = Gathering Center (Production Facilities in the WOA) FS = Flow Station (Production Facilities in the EOA) TAPS = Trans Alaska Pipeline System ALPS = Alyeska Pipeline Service Company. PS 1= Pump Station 1 of TAPS MBPD = Thousand Barrels per Day STB = Stock Tank Barrels (Base Conditions 0 PSIG & 60°F) SCF = Standard Cubic Feet (Base Conditions 14.65 PSIA & 60°F) PSIG = Pounds per Square Inch Gauge PSIA = Pounds per Square Inch Absolute SOS = Speed of Sound WC = Water Cut % ~ ~Q ~ ~ Quality Assurance Plan for the Weatherford Alpha VSRD (formerly known as Gen 2.0 Multi-Phase Flow Meter) The Quality Assurance Plan (QAP) for the Weatherford Aipha VSRD consists of two major components. The first is ensuring the meter is functioning properly when installed and the second is field operations, maintenance and calibration of the meter once it is installed. Factory Acceptance Tests (FAT) will be performed on the meters prior to shipping. The FAT procedures were outlined in our original AOGCC Application document and are shown below. The second component of the QAP is the field operations, maintenance and calibration of the meters once installed in the field. An outline of these procedures is attached at the bottom of this document. Factory Acceptance Tests (FAT) The following factory acceptance tests will be conducted prior to field installation: 1. Hydrostatic pressure testing will be performed according to the meter's pressure rating. 2. A single-phase (water) calibration of the sonar array and a verification of the nozzle discharge coefficient will be conducted. Due to well behaved Reynolds characteristics of the Sonar meter and documented properties of the Venturi nozzle, the single-phase water calibration has been found sufficient. 3. The Red Eye probe will be calibrated on air. Air calibrations are unique for each Red Eye unit. 4. The densitometer will be calibrated by the vendor on 100% air and 100% water. 5. New meter designs or configurations will be flow rate tested to check the performance of the meters. The test conditions will be guided by the intended application of the meter and the capabilities of the test facility and based on manufacture's recommendations. Field Operations, Maintenance and Calibration The first level of quality assurance is the routine monitoring of the facility allocation factors and the repeatability of the well tests. This work is performed as a standard part of our field operations. The second level deals with the maintenance and calibrations of the meter. A list of second level activities is shown below: l. The Red Eye probe will be calibrated on dry oil samples from the field. (the Red Eye oil calibration can be done using a different unit to the one installed, so there is no requirement for the meter to be filled with dry oil). ~ ~ 2 3 4 The densitometer will be calibrated on a single phase liquid of known composition (e.g. water, diesel or methanol) after installation. The Flow Station and/or Gathering Centers' crude oil shipping meter allocation factors will be monitored for any significant changes in oil allocation factors. Production Engineers and Operators will monitor individual well test rates for repeatability and unexpected changes. On-line meter diagnostics will flag devices used in the Alpha VSRD system that are out of manufacturer specification. Most new devices provide a wide range of diagnostics that can be used to send flags on out or range or questionable performance values. These flags will be used to alert operators and engineers to possible problems. 6 7 8. 9 10 Piggy back tests using existing well test facilities or portable well tests may be used to verify unexpected performance by the meters. Known volumes and rates may be pumped through the meters to verify performance in situ. Periodic grab samples may be used to check the WC data from VSRD if there are significant variations. These samples can also be used to measure fluid density and update Alpha VSRD data files. Currently most producing wells are sampled for oil / gas / water to monitor fluid changes. This sampling is dependent on reservoir locations and depletion mechanism. Generally most wells are sampled every 6 months to two years for oil API and compositions, gas gravity and compositions, and water compositions. This sampling data will be used to update meter data when appropriate. If necessary samples will be taken for the multi-phase flow meter densitometer and Red Eye watercut probe calibration or for watercut determination. Periodic meter calibrations will be performed per manufacturer's specification or what is determined to be prudent for field operations. A list of required calibrations is shown below: • Venturi differential pressure, pressure and temperature transmitter - calibration once a year or per manufactured specifications. • Sonar - no routine calibrations and maintenance is required - replaced if fails • Red Eye Watercut Sensar - no routine calibrations and maintenance is required - replaced if fails. • Densitometer - shutter and wipe tests per NRC regulations. Calibration should be performed annually or per field requirements using a single phase fluid of known density (e.g. diesel, water or methanol) ~ 29 ~ ~ Colombie, Jody J (DOA) From: Myers, Steve [Steve.Myers@asrcenergy.com] Sent: Thursday, January 01, 2009 1:34 PM To: Williamson, Mary J(DOA); p.mehdizadeh@cox.net Cc: Jerry.Brady@bp.com; andrew.hall@uk.bp.com Subject: Re: Unit 5 approval So all understand, the way this unit is constructed it is impossible NOT to use CDS as there is no bypass; all well effluents are directed through CDS before entering TopFlow and/or gas sent to orifice. Regards....Steve ----- Original Message ----- From: Williamson, Mary J (DOA) <jane.williamson@alaska.gov> To: Parviz Mehdizadeh <p.mehdizadeh@cox.net> Cc: Brady, Jerry L<Jerry.Brady@bp.com>; Myers, Steve; Hall, Andrew (ABZ) <andrew.hall@uk.bp.com> Sent: Wed Dec 31 20:33:02 2008 Subject: RE: Unit 5 approval I'm sorry if I misunderstood - but I was under the impression that you were not using the CDS. Regardless, I did not see field test data that supports final approval of the CDS. I didn't even see that tests were marked showing the CDS was used. Do you indeed need/plan to use the CDS at MPU? If so - you need to show me further information. Furthermore - I would think you'd want to have tests from places with higher GVF - like V pad, and with the Vx to help support your upcoming Liberty project From: Parviz Mehdizadeh [mailto:p.mehdizadeh@cox.net] Sent: Tue 12/30/2008 8:09 PM To: Williamson, Mary J (DOA) Cc: Brady, Jerry L; Steve Myers; Hall, Andrew (ABZ) Subject: Re: Unit 5 approval This approval has a major error. It is assumed that Unit 5 was operated without the use of the CDS separator. In many of the Milne Point wells we have successfully used the CDS separator. Guess we will have to work this out with AOGCC again. Parviz Williamson, Mary J (DOA) wrote: > > Here's the final approval for Unit 5. > > Happy holidays! > > Jane > > Jane Williamson, PE > > AOGCC Senior Reservoir Engineer > (907) 793-1226 > 1 ~#'~28 Supplementai Data for AOGCC~02-08 • Supplemental data for the ~40GCC Iteport 12/02/0~ ASRC iJnit 5 Field Qualification Tests This report provides supplemental data requested by Jane Williamson of AOGCC in regards to the ASRC Unit 5 Field Qualifications. A report describing field qualification of ASRC Unit 5 was originally presented to AOGCC during the week of Sept 8, 2008. A Teleconference was then arranged to discuss the details of the Unit 5 performance. The discussion in the current supplemental report is intended to address questions submitted by Jane Williamson in her email of Sept. 29, 2008. These questions fall essentially in the following categories: 1. Unit 5 in comparison with Unit 1- oil, gas, WC Excel raw data 2. Corrections for Permittivity/ conductivity 3. Corrections for viscosity, Reynolds number The following information is supplied to address the above issues. Table 1 shows the piggy back test results from early qualification tests. As noted in our initial report these were the only piggy back and tank tests conducted during the qualification tests. Lack of availability of reference Unit 1 and HSE concerns resulted in the remaining portion of the qualifications tests to be pursued without piggy back tests as will be discussed later. The oil and gas rate as well as the WC data are presented in Table 1. In addition Table 1 provides grab sample water cut (S WC) data that was also used for reference. A third method of referencing the data - i.e. tank strapping was also used for qualification. The tank tests results are shown in Table 1. Since the qualification tests were conducted over the August 2007- April 2008 period, it was necessary to go back and "reprocess" some of the older tests based on the knowledge gained from the more recent tests. One major issue that came to our attention during the March-April 2008 testing period was that permittivity and conductivity of fluids measured from salinity of produced water or API gravity of the oil was not representative of the in-situ permittivity/conductivity of fluids as was seen by the multiphase meter. An in-situ permittivity/conductivity protocol was developed to correct this problem. This protocol was field tested in April of 2008 and formally adopted for all tests that were conducted from that time on. However since this information was not available when the early piggy back tests were conducted, we had to go back and reprocess the early data for the permittivity and conductivity. The reprocessed data is the data shown for Unit 5 in Table 1. Page 1 of 5 Suppiemental Data forAOGCC•02-08 Table 1- Piggy Back Tests • ~ Unit 5 Tank - BBL Accumulated Well Date Oil-BPp Gas - MSC~D %WC SWC %WC Oil - SPD Gas-MSCFD Tank Unit 1 Unit 5 MPS-12 8/10f07 ,'~~: ~~~ a~~~ _~° '~' 8896 884'0 512 483 84 83 92 MPS-08 8/12/07 65%a 62% 729 903 MPS-17 8/10/07 ~:~ `_ '4 ' ~ 84% 79% 705 1215 ~ MPS-17 8/12/07 78 78 72 MPS-29 8/9107 ' 78% 7S% 453 29 MPS-04 8/11/07 t 97% 92% 112 19 MPS-19 S/11/07 ~.~;; .~` x~ g2% 95% 95 19 MPS-25 8/10/07 90% 90°k 407 118 53 53 58 MPH-04 8/13/07 . 26°l0 22% 1$7 1U MPH-13 8/13/07 ' S9% 56% 9$ d$ MPH-16 8/12/07 ~"'° ° '- 23% 25°/b 679 958 MPI -03 12/14/07 5°k 19fi 97 13 MPI-03 12/18/07 : 4% 1% 104 19 MPI-04 12/18/07 ': 55% 49°l0 181 1A3 MPI-O6 12/15/07 ~~;~ ~~~ 62% 57% 139 122 ~ MPI-14 12/16/07 `: 47% 59% 254 '!10 MPI-17 12/14/07 ° ;•<~ "- ~: 20% 34% 755 355 MPI-19 12/17/07 ~ U~:~ 11 % 17% 423 323 The repracessing was used to revaluate a11 tests conducted in the early stages of qualification as well as some of the tests in April - May 2008 to confirm that correction protocol for fluid properties was working. The reprocessing was discontinued in May 2008 after the results showed no changes in measurements between the original and the reprocessed test data. This was taken as the indication that the fluid property input protocol developed in April 2008 was working properly. The spreadsheet shown in appendix 1 has been used to establish corrections for permittivity and conductivity values for a test. Another major issue that came to our attention during the early qualification tests was the impact of well s~ream composition and flow rates on discharge coefficient of the Venturi used in the TopFlow meter. Andrew Hall has developed a smart spreadsheet to calculate the discharge coefficient of the Venturi based on the following input parameters: • Well flow rate, WC, GVF • Operating pressure and temperature of the well stream • Oil, Water and Gas density • Venturi Geometry These parameters are measured during the sta.bilization period -actually these fluid properties are also needed for permittivity/conductivity determination. The oil, water and gas density is used to estimate viscosity at the operating temperature and pressure. The calculated Reynalds number, Venturi geometry, and velocity profile based on flow rates are then used to estimate the Discharge Coefficient for the test. The calculated VDC has varied from 0.75 to 0.99 in the tests conducted. Page 2 of 5 . ! • Supp~emental Data for AOGCC 12-02-08 Two methods are used for the continuous "quality control" check on the well tests conducted since the field test report that was submitted to AOGCC in September 2008. The first method is to continue sample WC analysis in every test. This method essentially amounts to continued field verification testing as recognized by AOGCC Guideline - Section 4.1.2. Figure 1 shows the difference in grab sample WC and Unit 5 WC values during August of 2007 to November 2008. One would note the substantial improvements in the WC accuracy (narrowing of scatter band) as more effective testing protocols are implemented and Unit 5 crew has gained experience working with equipment. Since accurate WC values impact measurements of oil as well as gas rates in Unit 5 measurements, the data in figure 1 can be taken as an indicator of improved well testing quality. so 40 30 ~ 20 d v = 10 i ~ 0 ~ ~ -10 v L ~ ~ -2~ ~ -30 -40 -50 • MP-B 6 MP-E ~ x MP-G x MP-H • MP-I + MP-J o MP-K o MP-S - - - -+/- 5 % I ~ -~---- -- x • x x • ~ o + - - - - - - * - - - - - - - - - - - o + -x ~ * x - +t ~+,co - ~*- - - - - + ~y , ~ +~ • +~ + x - - - - - - --- - - _ - - --- ~r - x ~ _ a-- ~~ - - - - - o • ~ +~ a 0 ~ n ~ ~o ~ 0 • • 04-28-2007 08-06-2007 11-14-2007 02-22-2008 06-01-2008 09-09-2008 12-18-2008 Figure 1- difference in WC values between grab samples and Unit 5 during the entire course of field testing The second quality control method that has been used is the comparison of the Unit 5 field test results against the historical values. As an example, Figures 2-4 show this historical comparison for Milne Point K-pad wells. These plots show the WC, gross fluid, and gas rate data for all K- pad wells tested. We find good tracking of Unit 5 tests with historical well test data as well as the grab samples used as the reference for the WC data. Page 3 of 5 , • • Supplemental Data for AOGCC 12-OZ-08 ,oo% _ _ . _. _ ____ _-----_ __...___. __..___._ _ _. _ _ __--.----_ ---.__ _~___ _ . ______~_ _ __ __ _T__, -- I ss ~ , _- . ~ so -- - -- -~~ x 85% _~ ~ ~ - ~ 80% - - - -~ --- - ~-- - - -- ~_ . . i~ _---~-- __.._-----'--~ ~ 75% ~o% I ss~~ , i ~ -- - ~I - -- ----- _ - --- - _ _ . --- - - _ _ _ _ _ __ ------~ ----~ ~ 60°!0 55° 6 - ~ -Historic WC --~ ~-Unit 5 WC ' ~-SO WC , i 0 5 % MPK-02 MPK-05 MPK-06 MPK-09 MPK-13 MPK-13 MPK-17 MPK-17 MPK39 MPK~30 MPK37 MPK37 MPK-38 MPK-38 ~ - -- --- Figure 2- Comparison of WC data from Unit 5, garb sample (SOWC), and Historical values for all welis at Milne Point K-pad. Vertical bars indicate "estimated" variation in the historical WC data. Figure 3- Comparison of Gross Fluid rate for Unit 5 and Historical values for all wells at Milne Point K- pad. Vertical bars indicate "estimated" variation in the historical data. Page 4 of 5 ~ Supplemental Data for AOGCC 12-02-08 ~ 450000 ----- -.__.___ _.__- __._..~___.__.~ .._._._..__ _--_._.A _--_._-.___.---__ _______e____.___..---_~_ 50% ~ i 400000 -- - 45% i 40% 350000 - --- 300000 ---------- ------------= ~ BHP CHANGE ~ ----- - 35°k i I - 1p Hz % Change I ~ Amps °,5 Change ~'~0 i 250000 --- - ------------- ----------------~_Historic Gas Rate~ I-~-Unit 5 Gas Rete I '------ --- ---' 25% _ _ __ _ ___ _ _ __ ----_-- ____ _ ---- -- --- --- _ _ __ -- - I ~0~ 5 - 1 0000 15% 700000 10% ~ 5 5% 0 0°k MPKA2 MPK-05 MPK-06 MPK-09 MPK-13 MPK-13 MPK-17 MPK-17 MPK-30 MPK30 MPK-37 MPK-37 MPK-38 MPK-38 ~ _ _ _ - - ---- - Figure 4- Comparison of Gas rate for Unit 5 and Historical values for all wells at Milne Point K-pad. Vertical bars indicate "estimated" variation in the historical data. Page 5 of 5 ~ 27 Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, October 20, 2008 11:32 AM To: Colombie, Jody J (DOA) Subject: FW: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Page 1 of 1 Attachments: Gen 2 0 field trial summary data for Jane 091108.x1s; Prudhoe Wet gas Meter Test for Jane 091108.ppt Please place this a-mail and attachments in the file for the Gen 2 application. From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Thursday, September 11, 2008 2:18 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane, As a follow up to our meeting yesterday, we are sending you the following data for inclusion as part of our Weatherford Gen 2.0 application. 1. Excel table of the Gen 2.0 and Unit #1 well test results. 2) Data to support our capability to measure liquid rates at the very high gas volume fraction. I have included a power point with 4 slides that provides you with information on a test of the sonar and V- cone in the gravity drainage area of Prudhoe Bay. We hope this along with discussions yesterday help to address your questions. The enclosed can be considered as a part of our submission and used to supplement the report. Please contact me if you have any questions or comments on this data. Best regards, Jerry «Gen 2 0 field trial summary data for Jane 091108.x1s» «Prudhoe Wet gas Meter Test for Jane 091108.ppt» 10/24/2008 Li uid Rate Gas Rate Watercut Temp at Pressure at Flowrate Flowrate Ftowrete lowrate GOR ~ GVF at Oil Oil Temp at Pressure at Test Unk 1 Unlt 1 Gen 2.0 Unit 1 Gen 2.0 Unit 1 Gen 2.0 Unit 1 Unit 1 Unk 1 Density Viscosity Reynolds Gen 2.0 Gen 2.0 Well Date de F si b d b d Mscf d Mscf d % % scflstb % k Im3 c Number de F si Comments V-02 1 /31/2008 3:00 82.8 280.8 801.0 776.2 1663.2 1669.6 32.7 % 38.6 % 2151 94.85 868.3 10.8 6162 68.2 349.8 V-03 2/3/2008 14:00 86.0 311.1 676.7 773.0 1990.8 2023.9 45.5 % 41.5 % 2618 95.14 876.9 8.0 7260 91.4 410.7 V-04 1 Y28/2006 15:00 101.0 296.4 1458.2 1387.2 1599.6 1749.9 38.0 % 32.7 % 1261 91.21 845.9 5.6 18756 106.9 398.7 V-101 2/5/2008 21:00 105.4 380.2 2239.6 2224.0 2490.6 2337.8 96.3 % 91.6 % 1051 87.36 893.1 1.2 124463 107.8 510.6 V-102 1/29/200811:00 100.1 281.8 1701.5 1833.4 1764.1 1844.3 86.5% 70.2% 1006 89.76 884.6 2.6 51569 103.5 427.0 V-103 1/31/2008 16:00 82.1 334.6 1130.7 1190.1 1360.6 1432.9 69.3 % 61.0 % 1204 68.53 895.7 11.3 9549 83.9 421.0 V-106-8 1/30/2008 13:00 103.5 306.7 1744.4 1627.4 1588.0 1545.1 94.7 % 83.4 % 846 87.26 897.4 1.4 89665 107.0 407.3 V-108 2/4!2008 4:00 69.1 318.2 1001.1 885.4 1484.7 1370.2 54.7 % 57.3 % 1548 91.40 901.2 12.9 7161 73.4 407.1 V-111 2/4/2008 18:00 58.4 287.8 639.8 602.3 1583.3 1466.1 7.2 % 12.2 % 2434 94.88 905.4 36.3 1496 59.2 347.6 V-113-B 1/27/2008 12:00 65.9 264.7 813.0 755.7 1888.2 1958.9 54.6 % 52.6 % 2592 95.13 898.0 20.6 3438 66.5 387.2 V-122 2/5/2008 8:00 109.1 353.3 3031.0 3172.2 2664.9 2561.2 61.6 % 59.3 % 814 84.69 875.7 3.7 60767 113.9 556.4 V-202 2/1/20085:00 55.3 298.4 1486.9 1573.0 2062.4 2498.4 2.0% 10.3% 1588 92.07 925.3 82.6 1338 55.9 442.8 V-203-A 1/28/2008 2:00 53.4 306.2 1749.6 1806.1 3382.7 3469.8 0.0 % 2.5 % 1921 92.81 926.8 72.2 1949 52.3 488.8 V-203-8 2/2/2008 12:00 50.2 311.8 1501.4 1669.6 3169.8 3070.5 0.0 % 2.4 % 1839 92.32 927.7 64.4 1924 50.2 487.4 V-204 2/1/2008 20:00 48.4 308.5 683.4 977.0 3436.9 3205.9 35.8 % 22.2 % 3281 95.71 937.3 192.1 412 51.4 427.5 Lost heat during test resulting in bad test data V-205 2/3/2008 1:00 38.3 319.3 328.1 383.0 2796.1 2772.7 0.0 % 0.6 % 7240 97.95 953.7 653.1 68.3 38.6 450.5 • C~ • This test used sonar and V-cone • Gen 2.0 uses sonar encapsulated venturi - Gen 2.0 superior to sonar and V-cone Encapsulated venturi allows for greater turn-down ratio Provides reliable sonar data at lower velocities v • Uses the same basic technology as Gen 2.0 ~ -Sonar and pressure differential gas measurement meter 50 45 40 H 35 ~ 30 d R L 3 25 0 ~ 20 vs Q ~ 15 V 10 5 t5% 0 i~ ~ ~ 0 5 10 15 20 25 30 35 Test separator gas flowrate (MMscf/d) 40 45 50 • • 1200 ~ 1000 N ... m 800 3 0 ~ soo V 400 d C O U j 200 0 All these points _ within t10% "~ o ~ " o ,' ,' ,- , ,- , unreliable /low liquid '~~' ,'~~ rate from test i ,' separator ,' ~ ~ 0/ ,' ,f `'~~ V-cone transmitter ----__ ,~" ~- ' ~ ~ suspected out of ~ .' _ _ range ~ '~ ,' '------ ' /~-- -_ ~ - V-cone transmitter ~ Liquid rate verified ~ p ~`, certainly out of ~~ with ASRC Unit 1 ~ range 0 200 400 600 800 1000 1200 • • Test separator liquid flowrate (stb/d) 100000 90000 80000 70000 v N ~ 60000 C9 ~ 50000 ~_ V 40000 0 30000 U 20000 10000 ,, O , V-cone transmitter suspected out of range / . ~ / //Qq./ // 15000 • 0 ~- 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 Test separator GOR (scf/bbl) Request for AOGCC to approve Gen 2.0 meters on DS-O1 and Victor pad Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, October 20, 2008 11:32 AM To: Colombie, Jody J (DOA) Subject: FW: Request for AOGCC to approve Gen 2.0 meters on DS-01 and Victor pad Another e-mail for Gen 2 application. From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Thursday, October 09, 2008 1:43 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Request for AOGCC to approve Gen 2.0 meters on DS-O1 and Victor pad Jane, As we discussed on the phone, BP would like to begin design work to install the Weatherford Gen 2.0 multi-phase flow meters at several pads for well testing and allocation. However, we do not want to proceed with this work until we have state approval. You have suggested that the AOGCC would likely approve application at specific pads as you continue to work the overall approval to use the meter across the North Slope. Again for clarity, BP is only asking to use the meter in areas that are similar to the wells that we tested at Victor and Echo pads. These meters will be used as a replacement of current well testing kit. The first two pads we have currently targeted at Prudhoe Bay are DS-Ol and Victor pads. We would like AOGCC approval to install Gen 2 at these two pads in the next few days. This action would allow you to proceed with overall approval of our original Gen 2 application and prevent us from loosing any time on the deployment of these meters. Remember that BP is looking at a phased in approach with these meters and the sooner we can get them installed the quicker we will have more data to base the rest of our deployment on. Thanks! Jerry Page 1 of 1 10/24/2008 Additional Data for our Weatherford Gen 2.0 Application to the AOGCC • Page 1 of 5 • Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, October 20, 2008 11:34 AM To: Colombie, Jody J (DOA) Subject: FW: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC last a-mail for Gen 2 application. From: Hall, Andrew (ABZ) [mailto:andrew.hall@uk.bp.com] Sent: Monday, October 13, 2008 2:43 AM To: Williamson, Mary J (DOA) Subject: RE: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane I apologise for using confusing notation. We tested wells V-1 O6A, V-1 I3 and V-203 twice each during the ~6eld test 'I~he first test of V-106 we did not get Unit 1 and Unit 5 data because of some operational issues with Unit 5. 't'hey bypassed the units to keep warm fluids flowing through the test skid and I requested a repeat of the well test on the next shift. I labeled the second test V-106-B. I did not use the first test. The first test of V-113 was abandoned mid way through due to a plant trip. Again I requested a repeat of the well test on the next shift, numbered the new test V-1 ] 3-H. There was not enough data in the first test to be useful. V-203 was tested twice, on different days, just because there are only 4 Orion wells and we thought it useful to get more tests, and I labeled these V-20:i-A and V-20:i-B. I did not ask for tests on V-107 or V-109 just from time constraints and because we had already tested more of the I3orealis wells than the other formations. Also I recall to bring V-101 on line - which I thought was interesting because of its high water cut - we had to cut back on some of the other wells. Regards Andrew From: Williamson, Mary J (DOA) [mailto:jane.williamson@alaska.gov] Sent: 12 October 2008 03:21 To: Hall, Andrew (ABZ) Subject: RE: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Andrew, In going through the data you sent, in the collumn named Well. you have tests shown for V-203-A, and V-203-B. Are these 2 separate tests for the V-203 Well? The well name in our records is V-203. Also in the Well collumn of your data sheets you note V-106-B, V-113-B. Our files show the names V-106A and V-113 Respectively. Following are the Oil Producers we have filed in our database (excludes laterals of motherbore) with API # and Permit Number noted. V-01, V-07, V-115, V117 were not producing during the test period. Did you attempt tests on V-107 and V-109? They were producing at the time but no tests are noted. 10/24/2008 Additional Data for our Weatherford Gen 2.0 Application to the AOGCC • Page 2 of 5 PI WELL # PTD # ell Name Pool Formation Status Dt. est Gen 2? Producing 1 /26/08-2/5/08? 50-029-23210-00-00 2040900 -01 Prudhoe Bay Oil Pool Sadlerochit 11-Jul-04 No No 50-029-23209-00-00 040770 -02 Prudhoe Bay Oil Pool Sadlerochit 18-Jun-04 es es 50-029-23124-00-00 022150 -03 Prudhoe Bay Oil Pool Sadlerochit 31-Dec-02 es es 50-029-23322-00-00 061340 -04 Prudhoe Bay Oil Pool Sadlerochit 01-Dec-06 es es 50-029-23372-00-00 071410 -07 Prudhoe Bay Oil Pool Sadlerochit 10-Dec-07 No No 50-029-23074-00-00 020560 -101 Borealis Oil Pool Kuparuk 02-May- es es 50-029-23070-00-00 020330 -102 Borealis Oil Pool Kuparuk 3-Jun-02 es es 50-029-23117-00-00 021860 -103 Borealis Oil Pool Kuparuk 07-Jan-03 es es 50-029-23083-01-00 2041850 -106A Borealis Oil Pool Kuparuk 30-Oct-04 es es 50-029-23108-00-00 2021550 -107 Borealis Oil Pool Kuparuk 28-Dec-02 No es 50-029-23112-00-00 021660 -108 Borealis Oil Pool Kuparuk 25-Nov-02 es es 50-029-23120-00-00 2022020 -109 Borealis Oil Pool Kuparuk 12-Nov-02 No es 50-029-23161-00-00 031030 -111 Borealis Oil Pool Kuparuk 15-Aug-03 es es 50-029-23125-00-00 022160 -113 Borealis Oil Pool Kuparuk 18-Feb-03 es es 50-029-23195-00-00 040270 -115 Borealis Oil Pool Kuparuk 04-Apr-04 No No 50-029-23156-00-00 2030900 -117 Borealis Oil Pool Kuparuk 01-Jul-03 No No 50-029-23328-00-00 2061470 -122 Borealis Oil Pool Kuparuk 05-Jan-07 es es 50-029-23153-00-00 2030770 V-202 Orion Oil Pool Schrader Bluff 03-May es es 50-029-23285-00-00 2051680 V-203 Orion Oil Pool Schrader Bluff 16-Feb-06 es es 50-029-23217-00-00 2041310 V-204 Orion Oil Pool Schrader Bluff 01-Sep-04 es es 50-029-23338-00-00 061800 V-205 Orion Oil Pool Schrader Bluff 18-Feb-07 es es From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Thursday, October 09, 2008 1:35 PM To: Williamson, Mary J (DOA) Cc: Hall, Andrew (ABZ); Parviz Mehdizadeh; Pospisil, Gordon Subject: FW: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane, Below is Andrew's answers to your questions. I am in hopes that this will help speed our application along. It would be very helpful to us to have approval by the end of the month. Thanks! Jerry Answers to Jane's questions 1. I used a Reynolds number calcu ated from Rc ~~= 4 * total mass flowrate / (pi * liquid viscosity * nozzle i.d.) So Re is based on total mass flowrate and liquid viscosity. I have not used the effect of free gas on mixture viscosity. The fluid in contact with the pipe walls is liquid; frictional loss which leads to the reduction in discharge coefficient is a function of flowrate and the fluid properties in contact with the pipe. We got good consistency between field results based on this Reynolds number and the laboratory calibration of the meter in oil. 10/24/2008 Additional Data for our Weatherford ~ 2.0 Application to the AOGCC Page 3 of 5 2. 1 used liquid viscosity (and PVT) calculated by SLB. They sampled the fluids and measured density and. dead oil. viscosity for each test. SLB's reparted liquid viscosity then. takes into account temperature, gas dissolution ('Live' oil viscosity) and water cut effects. 'I emperature effect is a straightforward log viscosity vs 1/'I' relationship; live oil viscosity is calculated from a live oil viscosity correlation, and water cut effect is an emulsion viscosity correlation. I don't know what correlations SLB are using but we could do a similar calculation. This will be done for the (field Gen. 2.0. Note that we are calculating viscosity and hence Reynolds every 1 minute during the 8-hour test. "I'he values I quoted are an average over the whole test. Actually this is quite an important point, because even in the low Reynolds number tests, we might see a substantially larger Reynolds number during a liquid slug (when the mass flowrate is higher) than the average for the test, so there is probably less sensitivity of the mass flowrate to the discharge coefficient -Reynolds number curve than you might think. 3. Water shakeouts were collected every I hour during most of the tests, by iJnit 1, Unit 5 and SI:,B. Normally it is 1/2 hour but we reduced the sample frequency to-avoid 1=125 issues in the Unit 5 operating area. 8 samples is not really enough for a good statistical average. However, normally these samples agreed well between the three locations. Exceptions were V-03 and V-103 where individual shakeout samples could vary ti-om 5% to 70% water cut due to the unstable nature of these wells. Table 15 2.: tati~tcal analysis of manual sample wa#er cu#s. I.:i1 11-1'~!: +~11 ~iw~.l~lr.c '11~Ir'~.., ~. ~1 111'h6 .~I~Ile v.arl~r.l .IlldWtl •.r'-'f"'.• J~-; r, .,., y. ._.r. GS', eei avn .qr .Lln~ 115~i csnl •"~• ah}w' 95 ~nl. _A ____ _._._ . -._. __. _. _.- . ___ I .... ~ d;.5"::. ~ 4.9ti 54 lz. ~ . j ' .a ~ 37644. 1-_T• Lb'L 9J :::'., . 1~. Iii, l1: _... -'ti llfC . '.I ~ _ 1 ~ ~ ~ i . ' _ ~_ 1 . , ra It >n lt, I I n gti . ~ .. l'. F~ti ,, d:. Y 11 ', ... ~ I F1i ~.. Note: these are hand samples and this data is not metering for Unit 1, Unit 5 or Schlumberger. 4. see Excel attachment If you need a phone call I suggest about Ipm Alaska / l Opm UK one day. Thursday would work. I-lad a good discussion with. Mike Mullally and Gordon Stobie on the phone yesterday. DS 1 will need to use a wet gas model for most of the wells. Andrew From: Williamson, Mary J (DOA) [mailto:jane.williamson@alaska.gov] Sent: 08 October 2008 05:06 To: Brady, Jerry L; Hall, Andrew (ABZ) Cc: Parviz Mehdizadeh Subject: RE: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jerry and Andrew, I'm still working on the review of the V-Pad test comparison. Sorry it's taking me so long -lots of things on my plate. I'm trying to do a thorough job reviewing, recognizing that this would be the first "certification" we've done for any MPFM system. It would be 10/24/2008 Additional Data for our Weatherford Gen 2.0 Application to the AOGCC ~ Page 4 of 5 hel~Oful to get a few more pieces of information. 1) I would like to see how Reynolds number was calculated. 2) Were total fluid viscosities measured (not just the oil -combined emulsion)? If so what are they? 3) Were shakeouts/fluid samples collected to determine water cut? How do these compare? 4) Would it be possible to provide the V pad separator tests that correspond to the Unit 1 and Gen 2 tests? I need to be able to explain differences in oil rates inferred from the measurements of the Unit 1 vs Gen 2. While I know that Parviz believes comparisons should be done for fluid and gas rates, not oil rates, in the end -oil is the "pay" fluid and we have to address this. I'm not as concerned when there are no or little differences in ownership and royalties (PBU), these factors could come into play for some of the fields/pools you've applied for. So far, I'm seeing the largest oil rate differences with the higher water cuts, mainly in the Borealis (Kuparuk). This might be explained by the different methods for water cut measurements, entrained gas in the fluid leg of Unit 1, correlation differences, differences in operating pressures at the 2 units, and PVT correlations. I thought I'd see bigger differences at high viscosity, lower reynolds number -but I'm seeing just the opposite. Perhaps that's taken care of with the correlations. I've spoken a bit with Parviz about it, but I would like to speak by phone with Andrew. It would be best if we could setup a specific time for Andrew to call. Jerry, I'm not so concerned with the oil rate questions for the Prudhoe Bay drillsite applications we discussed by phone today - V pad and DS 1, If you need approval from the AOGCC in a hurry for those applications, I think I can do that. Again, with no differences in ownership/royalties/tax treatment - it's a matter of what's ok for reservoir management, and I'm comfortable. You may require separate approval from DOG for Orion (maybe also Boreallis) PAs, but I don't think this will be a big deal. This blanket approval you've requested is more difficult, though. Jane ,Jane 1NiCCiamson, PT AOGCC Senior Reservoir Engineer (907) 793-1226 From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Thursday, September 11, 2008 2:18 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane, As a follow up to our meeting yesterday, we are sending you the following data for inclusion as part of our Weatherford Gen 2.0 application. 1. Excel table of the Gen 2.0 and Unit #1 well test results. 2) Data to support our capability to measure liquid rates at the very high gas volume fraction. I have included a power point with 4 slides that provides you with information on a test of the sonar and V- cone in the gravity drainage area of Prudhoe Bay. We hope this along with discussions yesterday help to address your questions. The enclosed can be considered as a part of our submission and used to supplement the report. Please contact me if you have any questions or comments on this data. 10/24/2008 Additional Data for our Weatherford 2.0 Application to the AOGCC ~ Page 5 of 5 Best regards, Jerry «Gen 2 0 field trial summary data for Jane 091108.x1s» «Prudhoe Wet gas Meter Test for Jane 091108.ppt» 10/24/2008 Request for AOGCC to approve Gen 2.0 meters on DS-O1 and Victor pad Page 1 of 2 • Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Thursday, October 09, 2008 2:47 PM To: Brady, Jerry L Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh; Taylor, Cammy O (DNR); Davidson, Temple (DNR) Subject: RE: Request for AOGCC to approve Gen 2.0 meters on DS-01 and Victor pad Jerry, I'll proceed with the order for early deployment at DS-1 and V-Pad, and I may be able to get orders for all PBU pools at the same time, or shortly thereafter. It would be nice if you could send a letter under Cordon's signature reiterating your request. A phased approach is reasonable. I would also prefer such a phased approach for long term approval for the remainder BP operated areas. Similar to your remark below, additional data would provide for a more solid framework for AOGCC approvals from a technical and legal standpoint and would provide a good basis for future orders. I believe such an approach would help you in the long term and could actually save you time. I perceive relatively small risk to the ownership interests within PBU and I believe the employment would aid overall reservoir monitoring and management. That said, you should probably speak with Temple Davidson (269-8784) and/or Cammy Taylor (274-7691) to make sure you receive any DOG approvals that may be required. You may need specific approval for Orion (maybe Borealis?) for V-Pad. I'm not sure in the case of DS-1 or other PBU pools. I'm cc'g them on this a-mail. As I've expressed in the past, I think the progress you've made here is very exciting and I can see a lot of potential in existing and future developments. Jane From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Thursday, October 09, 2008 1:43 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Request for AOGCC to approve Gen 2.0 meters on DS-Ol and Victor pad Jane, As we discussed on the phone, BP would like to begin design work to install the Weatherford Gen 2.0 multi-phase flow meters at several pads for well testing and allocation. However, we do not want to proceed with this work until we have state approval. You have suggested that the AOGCC would likely approve application at specific pads as you continue to work the overall approval to use the meter across the North Slope. Again for clarity, BP is only asking to use the meter in areas that are similar to the wells that we tested at Victor and Echo pads. These meters will be used as a replacement of current well testing kit. The first two pads we have currently targeted at Prudhoe Bay are DS-O1 and Victor pads. We would like AOGCC approval to install Gen 2 at these two pads in the next few days. This action would allow you to proceed with overall approval of our original Gen 2 application and prevent us from loosing any time on the deployment of these meters. Remember that BP is looking at a phased in approach with these meters and the sooner we can get them installed the quicker we will have more 10/15/2008 Request for AOGCC to approve Gen 2.0 meters on DS-O1 and Victor pad Page 2 of 2 data to base the rest of our deployment on. Thanks! Jerry 10/15/2008 Additional Data for our Weatherford Gen 2.0 Application to the AUGL(; • • Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Thursday, September 11, 2008 3:31 PM To: Lusher, James A; Davidson, Temple (DNR) Cc: Maunder, Thomas E (DOA); Roby, David S (DOA); Brady, Jerry L Subject: FW: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Yage t of l Attachments: Gen 2 0 field trial summary data for Jane 091108.x1s; Prudhoe Wet gas Meter Test for Jane 091108.ppt Jim and Temple, Tom and I met with Jerry Brady, Gordon Pospisil and Parviz Mehdizadeh yesterday concerning some questions we had in regards to BPXA's July 8 application to the Commission for use of the Gen 2 multiphase flow meter system for well tesing and production allocation in currently established BPXA operated pools. I requested an excel version of the individual well tests of the Gent vs. the Unit 1 portable test separator, with fluid properties/operating conditions noted. For wet gas application, they also sent the attached ppt file. Jerry indicated that these items can be placed in the public record. Jerry is anxious to get the Gen 2 AOGCC approval to help them ensure continued funding in progessing the field application of this technology. For the AOGCC record in this determination, I would appreciate a letter, preferably by Wed Sep. 17, as to whether your respective agencies have any objection or specific concerns which the Commission should consider in finalizing an order concerning the use of the Gent metering system in properties where you have a royalty share. Note that BPXA is not requesting, at this time, that the Gen 2 system be used as a replacement to "tact Meters" for custody transfer. If you wish to contact Jerry, his work phone is 564-5291, and cell is 440-8465. ,Jane ~1NilCiarnson, 1'E AOGCC Senior Reservoir Engineer (907) 793-1226 From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Thursday, September li, 2008 2:18 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane, As a follow up to our meeting yesterday, we are sending you the following data for inclusion as part of our Weatherford Gen 2.0 application. 1. Excel table of the Gen 2.0 and Unit #1 well test results. 2) Data to support our capability to measure liquid rates at the very high gas volume fraction. I have included a power point with 4 slides that provides you with information on a test of the sonar and V- cone in the gravity drainage area of Prudhoe Bay. We hope this along with discussions yesterday help to address your questions. The enclosed can be considered as a part of our submission and used to supplement the report. Please contact me if you have 9/16/2008 Additional Data for our Weatherford G n 2.0 Application to the AOGCC Page 2 of 2 any questions or comments on this data. Best regards, Jerry «Gen 2 0 field trial summary data for ,lane 091108.x1s» «Prudhoe Wet gas Meter Test for Jane 091108.ppt» 9/ 16/2008 Li uid Rate Gas Rate Watercut Temp at Pressure at owrate Flowrate owrate Flowrate GOR ~ GVF at Oil OII Temp at Pressure at Test Unit 1 Unit 1 Gen 2.0 Unit 1 Gen 2.0 Unit 1 Gen 2.0 Unit 1 Unit 1 Unit 1 Density Viscosity Reynolds Gen 2.0 Gen 2.0 Well Date de F si b d bpd Mscf d Mscf d % % scflstb % k /m3 cp Number de F si Comments V-02 1 /31 /2008 3:00 82.8 280.8 801.0 776.2 1663.2 1669.6 32.7 % 38.6 % 2151 94.85 868.3 10.8 6162 68.2 349.8 V-03 2/3/2008 14:00 86.0 311.1 676.7 773.0 1990.8 2023.9 45.5 % 41.5 % 261 B 95.14 876.9 8.0 7260 91.4 410.7 V-04 1/28/2008 15:00 101.0 296.4 1458.2 1387.2 1599.6 1749.9 38.0 % 32.7 % 1261 91.21 645.9 5.6 18756 106.9 398.7 V-101 2/5/2008 21:00 105.4 380.2 2239.6 2224.0 2490.6 2337.8 96.3 % 91.6 % 1051 87.36 893.1 1.2 124463 107.8 510.6 V-102 1/29/2008 11:00 100.1 281.6 1701.5 1833.4 1764.1 1844.3 86.5 % 70.2 % 1006 89.76 884.8 2.6 51569 103.5 427.0 V-103 1131/2008 16:00 82.1 334.6 1130.7 1190.1 1360.6 1432.9 69.3 % 61.0 % 1204 86.53 695.7 11.3 9549 63.9 421.0 V-106-B 1/30/2008 13:00 103.5 306.7 1744.4 11127.4 1568.0 1545.1 94.7 % 63.4 % 846 87.26 697.4 1.4 89665 107.0 407.3 V-106 214/2008 4:00 69.1 318.2 1001.1 885.4 1484.7 1370.2 54.7 % 57.3 % 1548 91.40 901.2 12.9 7161 73.4 407.1 V-111 2/4/2008 18:00 58.4 287.8 639.8 602.3 1583.3 1466.1 7.2 % 12.2 % 2434 94.88 905.4 36.3 1496 59.2 347.6 V-113-8 1127/200812:00 65.9 284.7 613.0 755.7 1888.2 1956.9 54.6% 52.6% 2592 95.13 898.0 20.6 3438 66.5 387.2 V-122 2/5/2008 8:00 109.1 353.3 3031.0 3172.2 2664.9 2581.2 61.6 % 59.3 % 814 84.69 875.7 3.7 60767 113.9 556.4 V-202 2/1/2008 5:00 55.3 298.4 1486.9 1573.0 2062.4 2498.4 2.0 % 10.3 % 1588 92.07 925.3 82.6 1338 55.9 442.6 V-203-A 1/28/2008 2:00 53.4 306.2 1749.6 1806.1 3382.7 3469.8 0.0 % 2.5 % 1921 92.81 926.8 72.2 1949 52.3 488.8 V-203-8 2/2/2008 12:00 50.2 311.8 1501.4 1669.8 3169.8 3070.5 0.0 % 2.4 % 1839 92.32 927.7 64.4 1924 50.2 467.4 V-204 2/1/2008 20:00 48.4 308.5 683.4 977.0 3436.9 3205.9 35.8 % 22.2°/ 3281 95.71 937.3 192.1 412 51.4 427.5 Lost heat during test resulting in bad test data V-205 2/3/2008 1:00 38.3 319.3 328.1 383.0 2796.1 2772.7 0.0 % 0.6 % 7240 97.95 953.7 653.1 68.3 38.6 450.5 • C] • Uses the same basic technology as Gen 2.0 - Sonar and pressure differential gas measurement meter • • This test used sonar and V-cone • Gen 2.0 uses sonar encapsulated venturi - Gen 2.0 superior to sonar and V-cone Encapsulated venturi allows for greater turn-down ratio Provides reliable sonar data at lower velocities 50 45 40 N 35 ~ 30 a~ ca 3 25 0 ~ 20 Q ~ 15 U 10 5 t5% O'- fl--". 0 '~ ~ 0 5 10 15 20 25 30 35 Test separator gas flowrate (MMscf/d) 40 45 50 • U • • a% O r ` '~ ~ ~ w i ~ ~~ ~ ` ~ ~ ~ '~ ~ ~ ~~ ~ N ~ ~ O N ~ `~ c a .. c ~ ~ ~ O fA N '~ ~ ~ ~ ~ V U ~ ~ ~` ~ \ ~ ` ~ ` ~ ~ ~ Q ~ ,- I \~~ `\` -' ~ c ~ o O ~ ~ ` -- a~ ~ +~ (n ~ `~ \ ~ ~ T W ` O ` \ \ W . ~ ~ 3 \ ~ ~ ~~ ~ ~' ~ ~ ` ` U +~ R L1 ~ ~ ~ `Q ~ ~ ~ 3 a+ ~\ ~, s •3 'o - .~ a '~O - ~ 3 4: O i O ~ ~ ~ i ~ O ~ ~ ~ N w ^. ~ ~ N N r~ i ~_ ~ ~ N i ~ N ~ 7 ~ ~ O O O O O O O O O O O O N O 00 CO ~t N r ~ 0 0 N O O O O O O O O 0 O 0 0 N O O N .-. d a+ L 0 .a .~ .a O i d N r+ N d ~"' (p~q~s) a~eanno~~ pinb~~ dba~~ + auo~-n 100000 90000 80000 .~ 70000 v H ... ~ 60000 ~ 50000 V 40000 a~ O 30000 U 20000 10000 0 ±5000 ~- -O O V-cone transmitter suspected out of range .--Q Q-- -- - s 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 Test separator GOR (scf/bbl) Page 1 of 1 • Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Friday, August 08, 2008 11:39 AM To: Brady, Jerry L; Parviz Mehdizadeh; Hall, Andrew (ABZ) Cc: Maunder, Thomas E (DOA); Roby, David S (DOA) Subject: Draft comments on July 8 Gent application Attachments: BPMPM.doc Jerry, Andrew, Parviz, I went through the Gen 2 application and I'm providing some comments, though you should consider this as draft now, and there may be other comments forthcoming from Tom. As I've said before, the development of this device is quite exciting. The Gent still seems to be in a prototype stage, but it appears to be a great step forward. At this time, I'm not convinced that an open-ended approval in all properties, especially where there are differences in royalty, is appropriate. I do believe there are many places where the design will improve well testing for reservoir management - as you've shown for V pad. You indicated you're not sure where you will be putting these meters at this time. Maybe just 4 or so a year. You have a few places in mind but not a full plan in place. Perhaps we could discuss a mechanism of approval at this time, for the purposes of enhancement of well testing accuracy of existing separators, with a later notification of installation when your inhouse or WIO approvals are, and define criteria for when further approval is needed (getting input from DNR and MMS as appropriate- not sure why DOR would care unless there is a between unit and facilities sharing issue.) We'll need updates on how the meters are performing, and interpretation - is the meter working as it should, has it improved allocation, any operating problems, etc? Something much less time consuming than the report you've worked on -more like a permit form or a 2-3 page summary. I found both the Pioneer Oooguruk and your application a bit difficult to ensure required documentation is fully addressed as outlined in the Commissions Guidelines for Qualification of Multiphase Metering Systems for Well Testing" (see http•//www state ak us/local/akpages/ADMIN/ogc/MeterGuide.shtml ). The attached questions are related to sub-sections of these Guidelines. It would be helpful if you could go through these questions and answer them. Just send back by e-mail. It's not necessary to redo the application. Also, can you provide me with an electronic copy of the slides after our Monday meeting? Jane Williamson AOGCC Senior Reservoir Engineer, PE (907) 793-1226 9/16/2008 AOGCC/1\~ Draft Comments -July 8, 2008 Gen~pplication Sections noted from Commission "Guidelines for Qualification of Multiphase Metering Systems 1 (/04/04 3.1.1 Proposed locations and timing of the meters: BP has requested approval for well test allocation in all properties operated by BP. We are concerned about providing blanket approval without more information on the proposed locations and timing of installation over the next few years and knowledge of what conditions this meter will be placed in. Please verify further. 3.1.2 Appendix lA: Point McIntyre is produced into LPC as well as GC1. 3.1.3 Appendix lA: ELF no longer applies. Make sure the royalties are correct. 3.1.4 Statement that all working interest owners, royalty owners (including Alaska Department of Natural Resources, and Mineral Management Services), Alaska Department of Revenue. This is further verified by the planned meeting. 3.1.5 Complete. 3.1.6 Complete for V-Pad, but what about other potential areas? 3.1.7 Complete for V-Pad, but what about other potential areas? 3.1.8 Please provide a statement of expected accuracy over set of operating/fluid properties conditions. (a) Your main report shows uncertainties in comparison to the ASRC Unit 1 and V pad Separator. An additional appendix would be helpful which outlines the verification of the ASRC Unit 1. Also, what sorts of "corrections" and "algorithms" were required (any due to viscosity, Reynolds number, other). (b) The report on loop testing suggests that improvements are still needed and that this is in the prototype stage. Have I interpreted this correctly? (c) You are requesting a blanket approval through all properties and conditions. It appears you are claiming this can be used through full range of GVF, water cut, viscosity, flow regime - is that correct? a. The V pad separator results appear favorable - in fact much improved over the Loop tests. Why? Loop tests suggest "accuracy better than 20% at GVF below 80%", and slugging flows cause difficulties, especially above 80%GVF. "Additional work is required to improve the multiphase and especially sonar performance in unsteady flow conditions." (d) For reservoir management, there may be no problem with a +/- 20% accuracy at very high GVF's, but we need to make sure that your expectations are quite clear. If there are fiscal allocation effects, you will need to get into more detail as to the effects of the uncertainties. (e) Did you see any indication of bias? For instance in Figure 11 of the flow loop test. Would this suggest some bias of liquid flow rate over various Lockhart Martinelli numbers? 3.1.8.1 The Guidelines require review of accuracy to be stated for all phases. (a) I can't find anything stating or shown for oil rate accuracy. 3.1.8.2 Accuracy measurements Table 3 are relative to Unit 1. Again provide oil. 3.1.8.3 Loop test confidence was +/- 95% confidence. Same for Field tests? 3.1.9 No change in allocation methodology. I believe that is true, but as other installations besides V pad are installed, you should verify within existing conservation orders and perhaps consider if allocation technique/discussion needs AOGCC/MJW Draft Comments Page 1 of 2 8-8-08 AOGCC/l~ Draft Comments -July 8, 2008 Genpplication Sections noted from Commission "Guidelines for Qualification of Multiphase Metering Systems 11/04/04 update. For V pad, allocation is in accordance with Prudhoe Bay Unit Western Operating Metering Plan. 3.1.10 Contingency plan addressed for places where a test separator exists. 3.1.11 & 3.1.12 Perhaps a bit skimpy discussion on long term quality assurance and accuracy. See attached Pioneer for Vx meter. (a) Particularly, measurements of fluid properties (density at operating conditions), Composition of gas, Salinity of water (still not totally understanding the verification that salinity does not affect red-eye), viscosity of oil at operating conditions, viscosity of oil-water emulsion. This should be done for each well, not just by pool. 3.2 Relaxation of accuracy criteria. Thoughts for discussion, consideration. (a) Used solely for well testing for reservoir management? As in the improvement at V pad. No ELF, differences in Royalty (b) Will need to discuss with DNR, MMS for areas where royalty interests differ and whether other approvals will be required. i. Maybe limit requests for replacement/improvement of existin test separator systems? ii. Find some method of notification that installation planned? iii. Consider using uncertainty analysis looking at affect of more frequent well testing as compared with less accuracy for those areas where royalty is a concern. 4.0 Validation of Meter performance in Field -Excellent field testing! a few comments 4.1 Some discussion of the calibration of the Unit 1 should be included. 4.3 Reporting Field Results. 4.3.1 Review of oil accuracy in accordance with 4.3.1 (a) How does fluid viscosity affect the results? Could you discuss how/whether Reynolds number corrections required? Any other properties that are important? 4.3.3 Individual well test results in tabular form needed compared to the Unit 1 and V pad Separator. (a) For each well tested provide fluid properties including Gas, Oil, Water Density, Oil API, fluid viscosity. Can Lockhart Martinelli values be provided for the wet gas? (b) How are gas lift values figured in? How good are the meters for gas lift? Impact meter results? (c) Need PVT properties to get to standard conditions. Again, how is gas lift included? (d) Were any other tests performed, tank tests, other? AOGCC/MJW Draft Comments Page 2 of 2 8-8-08 • s Colombie, Jody J (DOA) Page 1 of 3 From: Williamson, Mary J (DOA) Sent: Thursday, July 17, 2008 1:12 PM To: Brady, Jerry L Cc: Roby, David S (DOA); Maunder, Thomas E (DOA); Birnbaum, Alan J (LAW); Taylor, Cammy O (DNR); Colombie, Jody J (DOA) Subject: RE: 070808 BP Cover Letter Jerry, Yes, I can see that BPs prior request for Unit 5 also requested under 20 AAC 25.228 and 11 AAC 83.371. Take a look at the public notice AOGCC put out in 2007 for the Unit 5 proposal. If you can't find the earlier notice in your files, David may be able to find it for you. The whole question here is what are you wanting to apply for at this time. The Commission has authority for the state to approve/require standards for well test equipment and allocation methodology per 20 AAC 25.230. It's a new ball game if the MPMs are being proposed instead of LACT meters between units, such as the Pioneer/KRU and Liberty/Endicott plans. If seeking "fiscal allocation" methods to replace LACT unit requirements, you would need approval from the Commission to waive requirements of 20 AAC 25.228, plus DNR and likely DOR will be very involved in this (and MMS for Northstar, and Liberty.) Alan Birnbaum is our attorney for the Commission and perhaps he can help you further. Cammy Taylor, Unit Manager at DNR has experience on this from Commission and DNR standpoint, and I think she would be of great help to you. I am cc'g both on this. If it can all wait till I get back, that might be best. Monday is ok with me. I'm outs here till July 30. Later Jane From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Thu 7/17/2008 8:19 AM To: Williamson, Mary J (DOA) Subject: RE: 070808 BP Cover Letter Thanks Jane! I will check on this. I am somewhat confused though. These are the same numbers we used last time. Were they also incorrect? Another topic, Andrew is not available on Friday. I will see if Monday can work. Jerry From: Williamson, Mary J (DOA) [mailto:jane.williamson@alaska.gov] Sent: Wednesday, July 16, 2008 8:50 PM To: Brady, Jerry L Cc: Pospisil, Gordon; Seamount, Dan T (DOA); Colombie, Jody J (DOA); Birnbaum, Alan J (LAW); Foerster, 7/18/2008 Page 2 of 3 • Catherine P (DOA); Norman, John K (DOA); Roby, David S (DOA); Maunder, Thomas E (DOA); Kline, Carol; Colombie, Jody J (DOA) Subject: RE: 070808 BP Cover Letter Jerry, Thank you for the exciting overview of the Gent today. Excellent technical work I reviewed the cover letter of the application again and I noticed a few things that you need to review with Gordon to make sure it is correct. It was my understanding that you are solely requesting use of this Gen 2 MPFM device for well testing and for use in production allocation within existing BP operated properties. . Your letter states you are requesting approval under 11 AAC 83.371 which is not under AOGCC authority. This is within DNR -Kevin Banks group. I would see if Cammy Taylor cammy,taylo.r@alaska.gov at 269- 8817can help you concerning this. I don't believe this regulation applies. . You also mention 20 AAC 25.228 -This doesn't apply unless you are requesting use in custody transfer applications. We would not be able to approve this without opportunity for hearing, and I'm fairly certain a hearing would be held if you do have this in mind. . If you are only requesting approval to use the GEN2 to enhance current test separation for existing pools, the Commission has the authority to approve under 20 AAC 25.230(a) and the Conservation Orders noted in your letter. . You should change the title of CO 547 to include all oil pools within the Prudhoe Bay Field, with the exception of Put River Oil Pool, Raven Oil Pool. . Your slides suggested you have a few specific projects in mind, but you stated you want to move toward full scale use of this technology. My preference would be a more measured, pilot approach, and I suggest you think about this, and specifically indicate where these will be used, say in the next 2 years or so. If you could limit the scope to what you will be getting to in the next 2 years, then I expect administrative approval wouldn't be a big deal. Of course we can notice for hearing in the larger scale and just see if there are comments/objections. I know you are in a hurry, but after considering this further, I need to take more time to collect comments from everyone and get our attorney to weigh in on the handling of your request. And, unfortunately, everyone is swamped with more pressing items at the moment. Therefor, I'll work on this when I get back. I will be on vacation from July 17 to July 29. It is really important to get this right from a legal standpoint. In the meantime, I suggest you work to set up a technical meeting with MMS (who will have their own requirements), DNR, and DOR. I believe your technical contact at MMS is James.Lusher(cr~MMS.gov. At DNR, Cammy will ensure it is coordinated. I'm afraid I have no idea who at DOR would be involved or if they need to be involved. I'm not sure if Dudley is the technical guy any more. I suggest you contact Jon Iversen, 269- 6620, Jonathon.lverse.n@alaska.gov for a SPOC. I really think your technical work is very exciting and I do think this should be shared with them. If you have further questions, Dave Roby may be able to help at 793-1232. Jcine 1NiCliamson, P~ AOGCC Senior Reservoir Engineer (907) 793-1226 From: Williamson, Mary J (DOA) Sent: Tuesday, July 15, 2008 12:41 PM To: 'Kline, Carol'; 'Brady, Jerry L' Cc: Pospisil, Gordon; Seamount, Dan T (DOA); Colombie, Jody J (DOA); Birnbaum, Alan J (LAW); Foerster, 7/18/2008 • • Catherine P (DOA); Norman, John K (DOA); Roby, David S (DOA); Maunder, Thomas E (DOA) Subject: FW: 070808 BP Cover Letter Page 3 of 3 Carol and Jerry, It appears that this is your official application for approval to use the Gen 2 Multiphase Meter System, which will require amendment to 7 Conservation Orders. If so, we request 10 hard copies of the signed cover letter and application, one for each conservation order file, and 3 for Commissioners and Staff. You've requested amendment of CO 551 for Northstar. MMS is a royalty owner there and you therefor need to add to your cc list Jeff Walker, Regional Supervisor of Field Operations, Mineral Management Service Alaska Field Office - 3801 Centerpoint Drive, Suite 500, Anchorage AK 99503. After we receive the hard copy of the application, the Commission will determine whether they wish to act upon these requests administratively or notice the applications for public hearing. Jane 1NiCCiamson, ~F AOGCC Senior Reservoir Engineer (907) 793-1226 From: Kline, Carol [mailto:Carol.Kline@BP.com] Sent: Monday, July 14, 2008 5:31 PM To: Williamson, Mary J (DOA); Seamount, Dan T (DOA) Subject: 070808 BP Cover Letter Dan Jane It appears that the zipped file of the complete Application Report for Weatherford Generation 2.0 Multiphase Metering System was too large and bounced back to me. The only difference between the one sent last week and today is the signature on the cover letter. Attached is the cover letter for your file. Do you require a hard copy? Please let me know. I'm happy to bring one to you, if necessary. carol kline Office: (907) 564.4744 Cell: (907) 223.9494 email: caroLkline(cr~.bp.com 7/18/2008 ~ 2s ~~s;~~ ~~~~w~~'I~ DEPARTMENT OF REVENUE Tax Division October 7, 2008 Daniel: T. Seamount, Jr. Chair Alaska Oil & Gas Conservation Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501-3539. Sarah Palin, Governor ^ State Office Building PO Box 110420 Juneau, AK 99811-0420 907.465.2320 ~ 550 W 7th Ave Suite 500 Anchorage, AK 99501-3555 907.269.6620 www. tax. state. ak. us Hand Delivered Re: Application by BP Exploration (Alaska) Inc. (BP) to the Alaska Oil and Gas Conservation Commission for use of the Weatherford Generation 2.0 Multiphase Metering System in the Prudhoe Bay, Endicott, Milne Point, Northstar, Put River, Raven, and Badami Oil Pools. Dear Chair Seamount: You have requested that the Department of Revenue, Tax Division (DOR) provide the Alaska Oil & Gas Conservation Commission (AOGCC) with a letter of no objection regarding AOGCC's authority to approve or deny BP's application for the use of the Weatherford Generation 2.0 Multiphase Metering System for well testing and production allocation within BPXA operations conducted in the Prudhoe Bay, Endicott, Milne Point, Northstar, Put River, Raven and Badami Oil Pools. DOR has no objection to BP's use of the Weatherford Generation 2.0 Multiphase Metering System as an alternative to conventional gravity based test separators for well testing and production allocation within the oil pools referenced in paragraph 1, above. This conceptual approval is limited to the facts as presented and does not constitute consent for use or approval of multiphase meters for production allocation between units or any other purposes. In BP's AOGCC "Application Report" for the Weatherford Gen 2 Multiphase Metering_ System (Application Report), BP stated that it would inform the DOR about the use of the metering system "when the application of the metering system affects such interests". However, DOR requests to be notified of any changes in BP Application for Weatherford Generation 2.0 Multiphase Metering System October 7, 2008 Page 2 the use of the metering system. Given the significant role that oil and gas production, including metering measurements and allocations of production and costs have on state revenues, and in light of DOR's regulatory responsibilities, the department feels it is necessary and appropriate for BP and the AOGCC to keep DOR informed of any changes in use or approval of BP's measurement systems. Given the evolving nature of this technology, DOR believes it would also benefit from being concurrently updated in any changes in use of the meters, regardless of whether BP believes use or application of the meters affects DOR's interests. DOR very much appreciates AOGCC's ongoing efforts to keep the department informed and updated regarding the use and application of multiphase meters as they continue to be used and implemented in Alaska production operations. If you have any questions, please contact John Larsen at (907) 269-8436, or in his absence, Lennie Dees at (907) 269-6624. Sincerely, Jon than Iversen Director cc by email: Kevin Banks, DNR Cammy Taylor, DNR Temple Davidson, DNR Jack Hartz, DNR Marcia Davis, DOR John Larsen, DOR Lennie Dees, DOR Gordon Pospisil, BPXA Jerry Brady, BPXA ~ 25 • DEPARTMENT OF' NATURAL RESOURCES DI [VISION OF OIL B: GAS Hand Delivered October 3, 2008 Daniel T. Sealnount, Jr. Chair Alaska Oil and Gas Conservation Couunission 333 W. 7`'' Avenue, Suite 100 Anchorage, Alaska 99501-3539 • SARAN PALIN, GOVERNOR 550 WEST 7T" AVENUE, SUITE 800 ANCHORAGE, ALASKA 99509-3560 PHONE: (907J 269-8800 FAX: (907) 269-8938 Re: Request by BP Exploration (Alaska) Inc. (BPXA) to the Alaska OiI and Gas Conservation Colnmisslon for approval to use multiphase measurement devices far well testing and production allocation within BPXA operations conducted in the Prudhoe Bay Field All Pools, Endicott Oil Pool, Milne Point Oil Paol, Northstar Oil Pool, Put River Oil Pool, Raven Oil Pool, and Badalni Oil Pool pursuant to 11 AAC 83.371, 20 AAC 25.228, and 20 AAC 25.230. Dear Chair Seamount: The Alaska Oil and Gas Conservation Commmission (Commmission) has requested a letter fiom the Department of Natural Resources, Division of Oil and Gas (Division), stating whether the Division objects to any request in the application of BPXA for the use of multiphase measurement devices, and ifso, the reasons for each objection. BPXA has requested approval fiom the Commission to use Weatherford Generation 2.0 Multiphase Metering System devices for well testing and production allocation within BPXA operations conducted in the Prudhoe Bay Field All Pools, Endicott Oil Pool, Milne Point Oil Pool, Narthstar Oil Pool, Put River Oil Pool, Raven Oil Pool, and Badalni Oil Pool. The Division conceptually agrees with the request. The Division defers to the Commission's tecluucal expertise in crafting the specific conditions for the requested approvals. The Division also has no objection to the Commission grantuig an interim, conditional, or temporary approval to allow use of these meters by BPXA. "Develop, Catserve, acid EnhaTrce Natural Resoeu•ces f or Present and Frrt~a•e AlasTraas. " A~C BPXA Weatherford Gen 2.0 10/3/08 Page ? of ? However, as BPXA has not yet finalized plaits for the timing and installation of the meters, the Division does not yet know which participating areas may receive the meters and how those meters will be installed and implemented. When BPXA has decided where to install the meters, and how they will implement them for well testing and production allocation, BPXA must request concui-i-ence and approval from the Division as required by participating area foiznation decisions and 11 AAC 83.371. If you have any questions please contact Temple Davidson with the Division at 907-269-8784. Sincerely, ~~~~ v2 Kevin R. Banks Acting Director cc by e-mail: Jonathan Iversen, DOR Jolnl Larsen, DOR Temple Davidson, DOG Jack Hartz, DOG Gordon Pospisil, BPXA Jerry Brady, BPXA ~~ gti't OF t~ ~!' ENT OFT • g iN Q~P ti~ United States Department ®f the Interi®r ~,_° 7 4 ~ yl ~G N S _~ MINERALS MANAGEMENT SERVICE "~~ ~. ~y~~ • ~'4RCH 33 ~a'9 Alaska Outer Continental Shelf Region M"""`E"'~' 3801 Centerpoint Drive, Suite 500 Anchorage, Alaska 99503-5823 SEP 3 0 2Q08 Mr. Dan Seamount, Jr. -Chairman Alaska Oil & Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Seamount: The MMS is submitting the below comments on the. BPXA July 8, 2008 request to AOGCC for authorization to use amulti-phase measurement device for the purpose of well testing and production allocation within selected BPXA-operated North Slope oil pools. The MMS appreciates the AOGCC invitation to the MMS to submit comments in recognition that the request includes the Northstar pool which is co-managed by the MMS and State. The MMS also wants to thank Jane Williamson for her efforts to include the MMS in discussions and information exchange on the BPXA request. The MMS generally supports BPXA,'s proposal. The MMS concurs with BPXA that approval of the request will allow BPXA to further demonstrate that multi-phase metering technology can provide allocation well tests comparable to a conventional test separator. With this goal in mind, the MMS provides the following comments. • Any application of these meters for measurement of oiUgas from the Northstar oil pool will also require approval separately from MMS (per 30 CFR Part 250.1202 Liquid Hydrocarbon Measurement). The MMS suggests BPXA clarify, or the AOGCC confirm, the intended purpose to use multi-phase meters for "production allocation." Among different regulatory authorities, "production allocation" has different regulatory and legal connotations. The MMS understands that in the context of this application, BPXA is not proposing multi-phase meters as a replacement to LACT Meters for custody transfer. It's not clear if BPXA is proposing to use this multi-phase meter system to allocate production among commingled production facilities. • The MMS encourages the AOGCC to define or require BPXA to develop a quality assurance program by which these meter systems are evaluated for accuracy and reliability and that this information be submitted to the AOGCC on a reasonable schedule. The application (page 3 of 1 1, Section 2) states that "In the event the proposed multiphase metering scheme does not produce the expected accuracy, we will revert to use conventional well testing techniques." The "expected accuracy" and exception criteria that would trigger reverting to conventional well testing techniques should be defined. The application (page 10 of 11, Section 6) lists a proposed schedule for field maintenance and periodic calibration. The MMS encourages AOGCC to adopt a schedule under which BPXA would demonstrate and verify that this is an appropriate maintenance and calibration schedule and what changes should be considered for different fluid flow or other operational conditions. The MMS appreciates the AOGCC for including us in your review process. This technology has important applications for the OCS and for future development opportunities in the State. If you have questions, please. contact Mr. Jim Lusher at (907) 334-5300. Sincerely, Je fir alker Re ~'o al Supervisor Field Operations cc: rJane Williamson, AOGCC Jerry Brady, BPXA # 23 Page 1 of 1 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, November 03, 2008 4:02 PM To: Colombie, Jody J (DOA) Subject: Concerning comments from DOR, DOG and MMS on BPXA Gen 2 application Attachments: Williamson, Mary J (DOA).vcf; Comments concerning BP's application for the use of the Weatherford Gen 2 MPFM system Jody, We received letters directed to Chairman Seamount from each agency providing comments related to the Gen 2, and you were asking whether a letter went out from the Commission requesting input from DOR, DOG and MMS concerning the BPXA Gen 2 application. BPXA gave a technical overview for all the agencies concerning the Gen 2 on August 11. BPXA's application was global (for all BPXA properties) and the DOG has royalty interests in the properties, MMS has royalty interests at Northstar. Because the agencies have their own requirements (royalty and tax accounting, etc), I individually asked the representatives to provide us with input regarding whether they have objections or comments regarding BPXA's application for our records. This was a verbal request. I do have an a-mail I sent to an MMS representative which I'm attaching, but I'm afraid I don't have any written documentation that I requested input from the other agencies. Jane 1~Villiamson, PE AOGCC Senior Reservoir Engineer (907)793-1226 11 /4/2008 • Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, August 25, 2008 5:31 PM To: Lusher, James A Page 1 of 1 Subject: Comments concerning BP's application for the use of the Weatherford Gen 2 MPFM system Jim, As we discussed, by phone today, I would appreciate your thoughts or concerns related to BP's application for the use of the Weatherford Gen 2 MPFM system for use in well test allocation for the Northstar Unit. We had discussed that certain requirements for meter verification over time be included in any order (periodic meter verification tests, requirements for sampling, reporting requirements, etc). If you have specific criteria you would suggest, I would appreciate your input. Jane Williamson AOGCC Senior Reservoir Engineer, PE (907)793-1226 11 /4/2008 ~ 22 • by Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. BP Exploration {Alaska) Inc, 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907} 564-5769 Fax: {907} 564-5706 Email; gotdon.pospisil~bp.com ~, .. ~' July 8, 2008 Dan Seamount, Jr. -Chairman Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 • ~€ it .i:.. ~ ~ ~ t~- - _ . . n~~n r, Re: Application Report for Weatherford Generation 2.0 Multiphase Metering System Amendment to CO 547 -Prudhoe Bay Oil Pool Amendment to CO 548 -Endicott Oil Pool Amendment to CO 550 -Milne Point Oil Pool Amendment to CO 551 -Northstar Oil Pool Amendment to CO 559 -Put River Oil Pool Amendment to CO 570 -Raven Oil Pool Amendment to CO 402A -Badami Oil Pool Dear Mr. Seamount: BP Exploration (Alaska) Inc. (BPXA), Operator of the fields shown in Appendix 1 of the attached Application Report, hereby requests authorization to use amulti-phase measurement device, as described in the Application Report, for the purpose of well testing and production allocation within BPXA operations conducted in the Prudhoe Bay Oil Pool, Endicott Oil Pool, Milne Point Oil Pool, Northstar Oil Pool, Put River Oil Pool, Raven Oil Pool, and Badami Oil Pool pursuant to 11 AAC 83.371, 20 AAC 25.228, and 20 AAC 25.230. The report describes the design, the expected performance and the anticipated applications of the Weatherford Generation 2.0 Multi-Phase Flow Meter. BPXA also requests an amendment to each of the aforementioned AOGCC Conservation Orders (CO) governing each pool in order to allow for the use of multi-phase meter technology as described in the Attached Report. The in-line multiphase metering system described in the attached report is based on the infrared water cut detector and sonar flow meter technologies, both developed by Weatherford. The system has been successfully tested at GPB V-pad and provides a metering solution for use in the full range of well conditions in the North Slope fields. The trial tests on V-pad concentrated on high gas fraction, gas lifted wells, but with conditions in the liquid-dominated multiphase regime. These meters were tested in a series and were statistically evaluated for accuracy, precision, and repeatability against a BPXA Request for Clarification~eting and Request for Hearing Page 2 known standard two-phase separator. Based on the result of this test and other experience gained throughout the world, BPXA has gained an improved understanding of the applicability and limitations of multi-phase metering to North Slope production wells. The AOGCC Application Report submitted herein compiles the data and literature that were used to qualify the design and establish performance levels for the Weatherford Gen 2.0 Multi-phase Flow Meter as a self contained unit. This document was prepared following the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued November 30, 2004 by the AOGCC. Approval of this request will advance the use of multi-phase metering technology for North Slope production measurements. It will allow BPXA to gain operational experience with this meter while demonstrating multi-phase metering technology can provide allocation well tests comparable to a conventional test separator. Additional benefits include improved testing frequency (no stabilization period required), production fingerprinting (no vessel dampening), reduced HSE risk (smaller footprint, fewer personnel, no vessel), and opportunity for lift optimization. Should you have any questions regarding this request, please don't hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Thank you for your assistance. Sincerely, '1 / l/ Gordon Pospisil Technology & Resource Manager Attachment Cc: Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA John McMullen, BPXA Sherri Gould, BPXA John Cyr, BPXA Jerry Brady, BPXA Alan Mitchell, BPXA Sonny Rix, ExxonMobil Dan Kruse, CPAI Glenn C. Fredrick, Chevron USR Scott Millington, Anadarko Daniel "Toby" Osborn, Doyon Ltd Mathew Fagnani, Nana Glenn Fredrick, Chevron Ignacid Herrere, Murphy Exploration Jane Williamson, Alaska Oil & Gas Conservation Commission Kevin Banks (Acting Director) Division of Oil and Gas - Department of Natural Resources Cammy Taylor -Unit Manager Department of Natural Resources Jon Iversen, Director Department of Revenue -Tax Division Jeff Walker, Mineral Management Service Alaska Field Office • • BP Alaska AOGCC "Application Report" for the Weatherford Gen 2 Multiphase Metering System 7/15/2008 p7asox aoccc c;~~a app ap~.a~z~ Table of Contents AOGCC "Application Report "for Gen 2 Multiphase Measurement System ................ 1. Introduction ............................................................................................................ 2. Proposed Applications ........................................................................................... 3. System Components and Measurement Strategy .................................................... 4. Field Test Program and Test Results ..................................................................... Table 1-Summary of wells tested, time, and duration ............................................. Table 2 - YVell Fluid Properties for Gen 2 Tests ....................................................... Table 3 -Summary of Gen 2 Measurement Uncertainties (RMS average values)..... S. Factory Acceptance Tests (FAT) ............................................................................ 6. Field Maintenance and Periodic Calibration ........................................................ 7. List of References ................................................................................................... 8. List of Appendices .................................................................................................. ........... 3 ........... 3 ........... 3 ........... 3 ........... 6 ........... 7 ........... 7 ........... 7 .........10 .........10 .........11 .........11 2of11 070808 AOGCC Gent app Rpt.doc AOGCC'Application Report"for Gen 2 Multiphase Measurement System 1. Introduction This document describes the design and anticipated performance of Weatherford Gent - hereafter referred to as Gen 2 multiphase metering skids -designed for well testing of wells in operating areas shown in Appendix 1. This report compiles the data and literature that was used to qualify the design and establish performance levels for the Gen 2 skid. This document is to be submitted to Alaska Oil and Gas Conservation Commission (AOGCC) as an "Application Report" to obtain their approval for using the Gen 2 multiphase metering system as an alternative to conventional gravity based test separators for well testing. The "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued by AOGCC, requires operators to submit this "Application Report" before new metering systems are used for production well testing and allocations. Section 3 of the AOGCC document outlines the type of information that the application has to provide. This BPX "Application Report" provides the information that is requested in the Section 3 of the AOGCC document. The Gen 2 in-line multiphase metering system described in this report is based on the infrared water cut detector and sonar flow meter technologies, both developed by Weatherford. The system has been successfully tested at GPB V-pad and provides a metering solution for use in the full range of well conditions on the North Slope. The trial on V-pad concentrated on high gas fraction, gas lifted wells, but with conditions in the liquid-dominated multiphase regime. The ASRC Unit 1 was adopted as the reference device for the test. Confidence in Unit 1 was established through spot sampling of water cut and by comparison to the well pad separator. 2. Proposed Applications The proposed multiphase metering systems are designed to be used either as permanent wellhead installation or mobile systems deployed in a field. Table 1 in Appendix 1 A shows the wells and production horizons in which BP is the operator or has working interest that may use the proposed multiphase metering unit. This Table also shows the working interest owners. All parties with working interest, royalty ownership, as well as the Alaska Department of Revenue will be notified about the use of the metering system when the application of the metering system affects such interests. The proposed application will use the multiphase metering skids for production allocation. In the event that the proposed multiphase metering scheme does not produce the expected accuracy, we will revert to use the conventional well testing techniques. The allocation methodology currently practiced will continue and would not be affected by the multiphase metering system. 3. System Components and Measurement Strategy The Weatherford Gen 2.0 multiphase meter concept consists of four principal components: 1. A Red Eye 2G near-infrared water cut monitor 2. A Cs 137 gamma densitometer 3. A passive sonar volumetric flow meter 3of11 Q70&08 AOGCC Gent App RpLdo~ 4. A Venturi nozzle differential pressure flow meter The proposed well head field configuration is shown in Figure 1. Figure 2 shows the Gen 2 installation in V-Pad trial tests conducted in January of 2008. Each of the metering components has been previously tested in wet gas and multiphase flow conditions as noted by the list of references. The innovation of the Gen 2.0 meter is to combine the four sensors to enable the optimum measurement of oil, water and gas flow rates across the full spectrum of composition, i.e. from 0% to 100% water cut, and from 0% to 100% gas volume fraction. The field tests reported in this document were performed to confirm loop test results for the Gen 2 meters and qualify this meter for field application. The sonar and nozzle are integrated into a single spool piece, with the densitometer and Red Eye meters located on downstream spools of restricted diameter (matching the diameter of the restriction at the sonar section); it is the intention that the four measurements will be integrated into a single spool, along with a static pressure and temperature measurement. The Red Eye 2G near-infrared water cut monitor has been extensively tested by a technology program led by the BP Gulf of Mexico (GOM). This has demonstrated the capability of the Red Eye to detect the water cut in multiphase flow streams containing up to 95% GVF with an uncertainty of ~5% absolute in the water cut measurement, almost independent of the GVF. A Red Eye has been installed at the UK National Engineering Laboratory (NEL) for nearly two years, undergoing a range of multiphase flow tests.2 One final comment on the Red Eye is that its measurement of water cut is expected to be unaffected by the composition of the water phase, i.e. independent of water salinity. This is because the dissolved salts in the water phase have no effect on the absorption of infra red radiation at the wavelengths used2. The gamma densitometer based on the 137 Cs Isotope uses the high energy 661 keV gamma ray. This device can be clamped to the outside of a steel pipe, and at 661keV there is little composition sensitivity of the absorption of the gamma ray, and so this instrument can be used to measure the density of the fluid mixture across a single path through the pipe, in this case a vertical path. This measured density can be directly related to the void fraction in the pipe. If the slip between the gas and liquid is known, then the void fraction can be converted to gas volume fraction. Note that `high energy' refers to the energy of the particular gamma ray, not the intensity. A high energy gamma ray is required to penetrate the steel pipe walls, but the intensity, or activity of the radioactive source material can be relatively modest, with a source activity of 100mCi more than adequate. The passive sonar instrument consists of an array of strain detectors mounted around the pipe circumference. This instrument interprets the propagation along the array of pressure pulses generated by the turbulence in the flow. This has been demonstrated to work well in a single phase (either gas or liquid) environment, and in a wet gas environment, with the measurement of total velocity (gas + liquid) in a wet gas stream almost independent of the liquid contents, a The tests at V-pad, presented in this report, were conducted in a liquid dominated multiphase stream to compliment the previous work. In this implementation the array of strain gauges is mounted on a section of restricted diameter. The reduction in the pipe cross section and consequent increase in gas velocity gives an improvement in the ability of the device to measure a velocity in a multiphase flow stream; this velocity is very strongly correlated with the gas velocity. 4 of 11 11-41}i118 \O(o(( Q~e~o_' ll~ii IZhLtleu Finally, the Venturi nozzle is based on a modification of the ISO 5167 standard ISA 1932 nozzle differential pressure flow meter and is included in this configuration order to make a measurement of the total flow momentum and hence mass flow rate. The choice of the nozzle type device over the more conventional Venturi was an attempt to condition the flow profile better for entry into the sonar measurement section, and a slight modification was made to the standard nozzle design in order to optimise the entrance effect of the flow meter area change on the sonar array in the meter throat. This device has been tested at Colorado Engineering Experiment Station and at NEL in wet gas flow conditions. The meter that was tested at V-pad in January of 2008 was 3-inch full bore ANSI 1500, with the diameter ratio (beta) of the nozzle being 0.541. The exact internal diameter at the inlet was 2.62 inch (66.64 mm) with the nozzle throat diameter 1.42 inch (36.05 mm) and the ID of the sonar section 1.58 inch (40.06 mm). Valves Encapsulated Sonar Sensors ~~ lbsolute ~ Linel Pressure --~~ Differential Pressure Temperature Photomultlpller ~~--- ~~~ RedEye Watercut Probe Gamma Ray Source Figure 1- Schematic of the Gen 2 Wel] Head configuration The measurement strategy for the Gen 2 system utilizes the "over reading" by Venturi and Sonar devices, caused by liquid content of the multiphase stream, to calculate the total and liquid flow rates in the multiphase stream. This is accomplished through a model developed for the Gen 2, which then calculates the GVF in the multiphase stream. The liquid density derived from the RE water cut meter and the multiphase fluid density provided by the densitometer, is used to partition the total flow rate into oil, water and gas flow rates at line conditions. The line condition flow rates are transformed to standard conditions through PVT calculations and reported as the output for the meter. Sofll 0708118 AOG(Y~ Gent App Rpi.doc Figure 2- Gen 2 Installations at V-Pad 4. Field Test Program and Test Results The testing was performed at Prudhoe Bay V-Pad between January 26`h, 2008 and February 6`", 2008, with 16 well tests completed in this period. Each well was stabilized through the test system for 4 to 6 hours, followed by an 8 hour well test. Table 1 show the wells tested, test time and duration. The fluid properties for these tests are shown in Table 2. The test results are summarized in Table 3. Figures 4 to 9 show graphs of well test results for gas rate, liquid rate, and water cut. In each graph the data from Gen 2 is plotted against the data from ASRC Unit 1 that was used as the reference. The graphs in Figures 4-9 are presented in support of the gas, liquid and WC uncertainty levels for Gen 2 shown in Table 2. These graphs include the error from the reference test separator. 6of11 070808 AUGCC Gent App Rpt.doc Table 1-Summary of wells tested, time, and duration W*II Test data Tast times Tait duration Prudttio~ Bey V~-ed pvishek) V-4t Wer net e V-02 a~-31-2aas a3:aq - ti :aa $ h«,s V-03 a2-~-2aa$ i 4:ab - 22:aa $ hoes V-04 a1-~$-340$ 15:aa - 23:ab $ haws Pn«dwe Bey V~Ped v-tat a~-~-~oa$ ~~:aa-a5:4a $n v-ta~2 at-2~-~4a$ ~ ~:oa - is_a cx~ $ nom V-t (L3 at-25-2aa$ aQ:aU - a3 ~,3 Test a6~doned Und 5 erat~ 41-31-300$ 18:00 - 00 04 $ haul "~-1 OF, of-30-244$ Qo:QO-0$Aa Unit t arrd Uhtt5 a;ssed 01-3a-2aa$ 13:aa - 21 ~a $ hoses V-147 VJer net tested V-t a$ a~-4a-~oa$ a~a:00 - ~~:aa $ hates V-14'~ LVet net tested V-111 02-04-200$ 1$:a0 -02:40 $ haws V-113 ot-2a-~4a$ 1a:aq-1$:1~ ~s~p-tit abandoned ai-27-200$ 12:aa - 2a~la $ haul V-117 INe®not anr~ e V-122 02-a5-2a0$ 4$:a0 - 1~6~1a $ haul Pn~o• Bey V~Ped (Sdred~r Blutf~ V-2a2 a2-41-~4~ 4~:aa -13:ao $ haws V 203 41-2$-2a0$ 42:00 - 100a $ haws - 02-(Y2-240$ 12:47 -2000 $ haws V-204 02-41-2aa$ 20:a0 - 04:Oa $ haws V-205 Q2-Q3-200$ a 1:a0 -09:00 8 haws Table 2 -Well Fluid Properties for Gen 2 Tests Gas Oil Water Formation/Well Density Density API Viscosity Density SG at 60 F cP at 60 F .886 14.1 @ Ivishak/V-04 0.882 g/cm3 28.2 68 F 1.013 g/cm3 .939 117 @ 66 Kuparuk/V-111 0.8 g/cm3 19.2 F n/a .938 273 @ 68 Schrader Bluff/V-204 0.75 g/cm3 19.4 F 1.014 g/cm3 Table 3 - Summary of Gen 2 Measurement Uncertainties (RMS average values) Meter Measurement Uncertain Relative to ASRC Unit 1- Gas Rate Li uid Rate Water Cut Gen 2 ~7 ~8 ~5 V-Pad Se orator f9 X14 ~9 Estimated Reference Uncertaint ASRC Unit 1 ~3 f5 ~2 7of11 07UR08 .~OC:CC Gcn2 ,app Rptdoc 5aa0 ~6<TJ ,.. •® ~. Z:~ ~ 2~ 0 eJ ,500 c ,am 0 • W FT C•n.0 p14;1. pn~11 • riFT (f~n.bplsiKUyn-F ~ _~~.5-. • • • ~ • ' ti ~~~ •• t cis'' .P' 0 tli~ ~~ a ~. Unit 1 gas tlowrate (MscHd) Figure 4 -Gas flow rates from Gen 2 • 9lbY1 FT Wn:t~pr ,r.N•4 ^ StBhYFT OM 20 pr iMi4n• I • BLB/HFT Wn30 pr iBtM1.4B~fl{ _ _ w. 9R. ------------------------------------------------------ • ,o~ >s o q -7Q9G O 4 N -70i ~C( ~+ -LNG -~9i -6096 m 59 eo 65 ro r5 aD 89 90 45 9m Unit 1 GVF (%) Figure 5 -Gas flow rate accuracy as a function of GVF 0 it ~ x0o0 0 ~ 95m _g 4 c 9om 5m 0 • WFTWn:.O puf{nrnr~ • MFT C»n204W1Ku{•N{ - .~ ~;rty - i r 7 • • ~I f • r! ~ • • . '~ 0 900 9om ism am0 :900 ~ ~ Unit 1 liquid tlowrake (st6ld) Figure 6 -liquid flow rates from Gen 2 8of11 O94 ~{ ~i O pyi t Y 109E ~ 09i w 7 •1096 .Q O ?094 -'1114 -~94 _Spii 16~(I;illS tQtf~C ( F~cr_' 4~^~) IZF:E.citic, • 8L9M/FT6M~:04WI~rMY~ • &HM~FT [w~:OpW~Kuprul~ • 8t&NFT Cw~:04uoi&nM«~BLtI . -«. M. • SD $ ® ~ 7D 75 E0 E6 90 ~ im Una 1 GVF (%) Figure 7 -Liquid flow rate accuracy as a function of GVF. The Schrader-Bluff "out of bound" data is believed to be due to the over-reading of reference (ASRC Unit 1) under the flow conditions. ,a>9` E094 70• 7 ~q V 'S09i q t79i N Cpp v ~79i 1091 094 • /1R Gn 30w••<u ~K~p ny • niT Wn:Ow•r <u ~BCfndr-&utf «. ciy • • • • ^' - y . - ^ ~Y~ R':. R' ~' l • 094 Unit 1 water cut (%) Figure 8 - WC measurements from Gen 2 9 of 1 1 • 3v+: as . ~mc Y 1Qi 7 v oac 3 -iogc 4 N C -20% _~{( 070808 AOGCC Gent App Rpt.}I. +o~. ^ • ^ ^ --------------------------- -t--- • -109: • nFT ff n:4vA1M fN Ifr{f~l} ~ riFT !ln:OvAIY eNIK~paruy • fIFT (ln:0w•u tNlBC~nbFBlfi1 - _. ~.ti. -`5091 i i r i 5D SS ~ ~ 7D 75 EO ffi fl0 fly Una 1 GVF (S4) Figure 9 -Gen 2 water cut accuracy as a function of GVF 5. Factory Acceptance Tests (FAT) iii The following factory acceptance tests will be conducted prior to field installation: • Hydrostatic pressure testing is performed according to the meter's pressure rating. • Liquid and gas flow rate tests will be conducted to check the performance of the meters. The test conditions will be guided by both the operating constraints of the test meter and of the flow facility. • A single-phase (water) calibration of the sonar array and a verification of the nozzle discharge coefficient are conducted. Due to well behaved Reynolds characteristics of the Sonar meter and documented properties of the Venturi nozzle, the single-phase water calibration has been found sufficient. • The Red Eye probe is calibrated on air as well as pure dry oil and produced water samples. Air calibrations are unique for each Red Eye unit. 6. Field Maintenance and Periodic Calibration The following items will be checked periodically: • The PVT tables would be updated monthly or as necessitated by operations to match a revised fluid characterization derived from representative field samples. • Correct operation of the primary devices will be tracked yearly to detect any offset (e.g. due to fouling). Establishing single-phase flow through the meter for a basic cross check between the nozzle and the sonar array provides the necessary primary device diagnostics. • Empty pipe calibration required as necessary for the densitometer. • Radioactive source site requirements -wipe test every 6 months. • Periodic calibration of DP/P/T transmitter. • Expected replacement of Red Eye monitor after 5 - 7 years. 10 of 11 07080 AOGCC Gent .~~pp Rpt.doc 7. List of References 1. "A PROTOTYPE WET-GAS AND MULTIPHASE FLOWMETER" E. S. Johansen (Weatherford Intl.), A. R. W. Hall (BP Exploration & Production),O. H. Unalmis, D. J. Rodriguez, A. Vera, V. Ramakrishnan (Weatherford Intl.) ,25th International North Sea Flow Measurement Workshop 16th - 19th, October 2007. 2. "Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions", Andrew Hall, BP Exploration & Production John Lievois, eProduction Solutions, Babajide Adejuyigbe, eProduction Solutions. 6th South East Asia Hydrocarbon Flow Measurement Workshop7th- 9thMarch 2007. 3. "Wet gas metering using sonar-based flow meters and piping pressure loss gradients," Gysling, D.L., Loose, D.H., Morlino, N. and van der Spek, A., 25th International North Sea Flow Measurement Workshop, Oslo, Norway, October 2007. 4. "New class of meter solves old problem impacting well test accuracy," Ward, E., SPE paper 100893, 2006 SPE Western RegionaUAAPG Pacific Section/GSA Cordilleran Section Joint Meeting held in Anchorage, Alaska, May 2006. 8. List of Appendices Appendix 1-Fields, Pools, and Wells Appendix 2 - "A PROTOTYPE WET-GAS AND MULTIPHASE FLOWMETER" 25th International North Sea Flow Measurement Workshop 16th - 19th, October 2007. Appendix 3 - "Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions" Appendix 4 -CLAMP-ON, SONAR-BASED VOLUMETRIC FLOW RATE AND GAS VOLUME FRACTION MEASUREMENT FOR INDUSTRIAL APPLICATIONS Appendix 5 - "New class of meter solves old problem impacting well test accuracy," 11 of 11 • • • • Appendix 1A Table 1-List fields, pools and wells affected by this proposal Working interest, royality interest, and tax treatment for leases Alaska Property Ownerships AOGCC BP Processing Facility Participating Area Pool Code AOGCC Pool Description Royalty Rate ~° ELF Exploration Chevron Conoco Phillips Exxon Mobil Doyon Ltd Nana Unocal Anadarko Murphy Total Badami Badami 060100 Badami 12.5%to 16.67°~ Separate 100 100 Endicott Eider 220165 Ivishak Undefined (Eider) 12.50% Separate 100 100 Endicott Endicott 220100 Endicott 12.5%1020% Separate 67.9221 0.0234 21.0206 0.1291 0.3874 10.5174 100 Endicott Sag Delta North 220150 Sag Delia North 12.5%to 20% Separate 98.1327 0.4668 1.4005 100 LPC Niakuk 640148 Niakuk 12.5% Consolidated Niakuk 26,360567 1.16 36.076746 36.402667 100 LPC Tract Operations 640147 GPMA Ivishak-Sag River 12.5°h Consolidated Niakuk 0 LPC West Niakuk 640149 Niakuk, Undefined 12.5% Consolidated Niakuk 26.360567 1.16 36.076746 36.402687 100 LPC North Prudhoe Bay State 640152 North Prudhoe Bay State 12.5% Separate 26.360567 1.16 36.076746 36.402687 100 LPC West Beach 640186 West Beach 12.5% Separate 26.360567 1.16 36.076746 36.402687 100 LPC & Prudhoe GC-1 Lisburne 640144 Lisburne 12.5% Separate 26.360567 1.16 36.076746 36.402687 100 Milne Point MPU Kuparuk 525100 Milne Point Kuparuk 12.5°h to 20% Separate 99.425769 0.574231 100 Milne Point MPU Sag River 525150 Milne Point Sag River 12.5%to 20% Separate 98.741072 1.258928 100 Milne Point MPU Schrader Bluff 525140 Milne Point Schrader Bluff 12.5%to 20% Separate 99269596 0.730404 100 Milne Point Tract Operations 525160 Milne Point Ugnu, undefined 12.5% Separate 100 100 Northstar Northstar 590100 Northsiar 20%plussupplemental Separate 98.5772 1.4228 100 LPC & Prudhoe GC-1 Point McIntyre 640180 Point Mclniyre 12.5% to 16.67% Consolidaied Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe All GC & FS Prudhoe IPAs (OR(GC) 640150 Sadlerochit 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GC-1 Midnight Sun 640158 Midnight Sun, undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GG2 Aurora 640120 PBU Aurora, Undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GG2 Borealis 640130 PBU Borealis, Undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GC-2 Orion 640135 PBU Orion, Undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GC-2 Polaris 640160 Schrader Bluff (Satellite), undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 G. 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BP Exploration 26.360561% BP Exploration 98.5772k j ~ Spylsland r ~ Chevron 1.160000% MuryhyAK 1.4228Y, me~ISMnd 1 ~~~~ P",y~kAr~ SAG RIVER PA" _ ~-~1 I 1 I~ 1 1 COLVILLE RIVER UNIT 1 ALPINE, FIORD•NECHELIK, N ~- ~ L L - I FIORD•KUPARUK, alikwk 1 1 I NANUO•NANUO,AND I .t~rJ,~rrr~ L 1 ~ilnePoint NANUQ•KUPARUK PAs p~ P 1 ~ _ ooHOx re ~, Z 1~ ~ SCHRADER BLUFF PA" I NORTH PRUDHOE PA' Approz.l0 Miles West 1 ~ DS sH 1 Dew Line I CPAI 78.00% ~ site ~elon L 1 NGPTHSTAa Anadarko 22.00% LI DS 30 L c l~ I Mew I ,. 1~ I I D 7 ~, z Reindeer Island dY 2madd ~ D& 3a 1 I ~~ ~ s ~~ MIne9 a~ 1 '~. 1 ~ g Algo Island DsaM 1 d E `~ - ,~ 1 PT. MCINTYRE PA' Ds sN 9 I I 1 - 1 G 1 Mine MIDNIGHT SUN PA ' °w 1 Stte _ ~ I.I ~ H I AURORA PA' l ~~ ,... - WEST BEACH PA' r 0531 DS 3K m I D53H Dss ~ I K POLARIS PA' sn~mplswe 1~ ~ ~~~ ; ~ STP I cPP DS 3S DS S4 3 IMdmyre DocN 1 ~~ DS 3G DS SB ¢ DS 3C 1 ~ ~ . ~ ~ ~ ~ ~ PMa ~PM2 I ,~ ~ ` CI .~.~ - eeseer I r l.~- ~ ~~ UStD . ~.~ L .~- I 1 .L 1 . 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White 100.0% ~ ' TAPS 1 oc BPPlpelineslnc. 46.8765% CPAI 28.2323% r 11" ~ ExxonMobll 20.4325% KUPARUKRIYERUNR WIIBama 3.0845% Meltwater PA"' Unocal 1.3742 I OS 2P .-..1 BPXA Cartography does not warrant that the data is accurate or fit for any particular use. User hereby indemnifies and holds harmless BPXA Cartography for any claims andlor liabil4ies which may arise from users use the data. DS9 d~epG (~ Dss I \ ~ _ DS1fi i \ DS17 \ LISBURNEPA' ~3;,.. 1 ~"me r ~_~ 1 ~ ~ ~.~.~~ ~ JACOBS LADDER UNIT - Anadarko 50.0% ~ ` _ BGAlaska 40.0% BADAMIUNIT 'a' ~. ~ ASRC 10.0% BADAMI SANDS PA a; Approx.? Mlles East ~~" ' ~ 1' I ' BPExploratlon 100.0% L. e_._._ _ i, ~~ ~ er~~ ~~ ' ,,...{ 1 ~~ ~ J 1.-._ ~ ,1 -~ ~r' r~ • • June 2008 25th International North Sea Flow Measurement Workshop 16th - 19th October 2007 A PROTOTYPE WET-GAS AND MULTIPHASE FLOWMETER E. S. Johansen (Weatherford Intl.), A. R. W. Hall (BP Exploration & Production) O. H. Unalmis, D. J. Rodriguez, A. Vera, V. Ramakrishnan (Weatherford Intl.) ABSTRACT A wet-gas flowmeter based on the field-proven downhole fiber-optic multiphase flowmeter has been developed. The flowmeter is based on an extended throat Venturi-nozzle and a Sonar flowmeter. This combination exploits the characteristics of these two devices in wet-gas flows. For the Venturi, there is awell-defined and large over-reading with increasing liquid-loading, whereas this has a significantly lower impact on the total flow rate measured by Sonar. The Sonar-Venturi wet-gas flowmeter has been in development over the past several years and has been tested extensively in industry flow loops. Particular emphasis has been placed on developing a flowmeter with a broad operating envelope that includes a large span of fluid properties, a high turndown ratio, and well characterized response both within and outside its intended operating envelope. The wet-gas performance has been demonstrated at the recently commissioned CEESI 3 phase wet-gas flow loop, yielding total and gas flow rates better than ~5%,* liquid flow rate better than X0.5 m3/hr in Type I wet gas,l and better than f20% in Type II wet gas. A Red Eye 2G near- infrared (NIR) water cut meter is used to differentiate the oiUcondensate and water. The Red Eye 2G has field proven performance in low gas volume fraction (GVF) flows for full range of water cut. A prototype version has demonstrated f5% water cut uncertainty in high GVF multiphase2 flows and initial testing of the Red Eye in wet-gas flows is showing great promise. The wet-gas flowmeter was also tested at the NEL multiphase flow facility to evaluate whether the measurement capability could be extended beyond the wet-gas envelope. Although the performance in low-pressure multiphase flows did not match the performance seen in high-pressure wet-gas flow, measurement capability was maintained and reasonable performance was demonstrated for the entire range of GVF. INTRODUCTION Test separators and portable well testing services are the most common technologies used to generate a measurement snapshot, typically every 30 days, but often less frequent. It is, however, widely accepted that real-time individual wellhead production monitoring is an effective tool to monitor the health and maximize the performance and ultimate recovery of producing oil and gas wells. Measurement technologies have been developed to monitor individual wells in real-time; however, the high cost has generally limited the install base to prolific wells or multiple wells multiplexed with multi-port selector valves. Furthermore, many are being used as mobile well- testing devices. Other factors complicating wide implementation include limited operating envelope, fragile mechanical and sensing characteristics, and sensitivity to changes in fluid chemistry or composition. To date, only a few meter types claim to operate both in wet-gas and All performance numbers quoted herein are relative measurements with 95% confidence interval, unless otherwise noted. multiphase regimes. Most other wet-gas or multiphase meters may report highly erroneous results outside their intended operating range. Therefore, as wells mature with increasing gas fractions and water cut, the flow measurement conditions at the wellhead necessitate flowmeters with a wider operating envelope and a lower sensitivity to compositional changes than is available today. The Sonar flowmeter technology platform offers the potential for acost-effective and robust flowmeter with a broad operating envelope that may bridge the gap between traditional multiphase flowmeters and high gas-fraction metering. Sonar flow measurement is derived from the field- proven downhole fiber optic multiphase flowmeter.3-5 It is non-intrusive, has no wetted sensors and offers excellent resilience to erosion and corrosion. Sonar flowmeters offer accurate and repeatable flow measurement with a small and well-behaved Reynolds number dependence and a large turndown ratio. Sonar can measure liquid and gas flows with no changes in hardware or software. The conventional types of differential pressure meters (e.g. Venturi, cone or orifice plate meters) still remain the flowmeters of choice in the vast majority of gas wells. The over-reading of such devices when there is liquid in the flow stream is well understood and documented in literature.6'~ However, the liquid content can be very difficult to estimate and hence correct for in the field. Consequently, the erroneous readings must be corrected by back allocation. Sonar tends to have a very well-behaved and low over-reading with liquid loading in wet-gas flows. The combination of a differential pressure meter with a Sonar flowmeter therefore offers an over-reading contrast that is exploited to yield the total and gas flow rates and the liquid content. FLOWMETER DESCRIPTION The Sonar-Venturi flowmeter is a combination of a Sonar sensor array located in the extended throat section of aVenturi-Nozzle, shown in Fig 1. The higher mixture velocity in the throat is favorable to the passive Sonar array as it improves signal to noise ratio and enhances mixing. The Sonar flowmeter consists of an array of electronic strain gauges (non-fiber optic) combined with fully integrated data acquisition and processing electronics housed in aspool-mounted enclosure. The prototype flowmeter also employs a multivariable pressure, temperature, and differential pressure transmitter for the Venturi. The flowmeter also includes Modbus and diagnostic communications over RS 485 and Ethernet. The entire assembly is powered by 12-36 VDC, consumes less than 10 W, and is Class I, Division 1 compliant. 2 multivariable transmitter Venturi nozzle Sonar data acquisition and processing electronics axial location of Sonar array flow Figure 1-Sonar-Venturi flowmeter schematic. Sonar Flowmeter Turbulent pipe flow contains self-generating vortical structures that convect with the fluid. These vortices remain coherent for several pipe diameters, and they decay as they convect through the pipe. Meanwhile new vortices are continuously generated by frictional forces acting between the fluid and pipe wall and within the fluid itself. An array of circumferentially mounted and axially distributed pressure sensors measures dynamic pressure fluctuations associated with the convecting turbulent eddies. The convection velocity is calculated from the unsteady pressures by array processing algorithms. The volumetric flow rate is directly proportional to the convective velocity measured by Sonar and a single Reynolds number calibration yields a flow rate for liquid or gas. with an uncertainty typically better than ±1%. The calibrated performance of the Sonar meter in single-phase (oil, water and gas) is presented in Fig. 2. A Reynolds number "turndown" of nearly three orders of magnitude is demonstrated for six different fluids at three different test facilities with no change in the three calibration constants. The calibration values are also consistent with what is typically seen in a fiber-optic flowmeter. In wet- gas conditions, the calibrated Sonar velocity yields a volumetric flow rate that is slightly higher than the actual mixture velocity. The over-reading of Sonar is well behaved with respect to liquid loading and is readily correlated with the Lockhart-Martinelli parameter. 5% e `~ 2% O i w 1% ~ o% _o u. -1% a> -2% 3% Venturi 4% 3% • NEL-Brine • NEL-Oseberg ^ NEL-Nitrogen O Weatherford-Water ^ Weatherford-Air ~ CEESI-Natural Gas ----- t 7% ---~-----------------o-----...--------~.;.....-----o- g • ° °• • o 0 -4% -5% ~- 1.E+04 1.E+OS 1.E+06 1.E+07 1.E+08 Reynolds Number, [-] Figure 2 -Baseline Sonar performance over broad Reynolds number range. The extended throat Venturi-nozzle performance was verified with the same dataset and was found to measure single-phase flow rates within X1.4%. The Venturi behavior is well described in literature. Tests conducted with the Sonar-Venturi combination throughout single-phase, multiphase, and wet-gas flow were consistent with published values of discharge coefficients. The turndown ratio of the differential pressure sensor is 84:1 from the multivariable transmitter specification sheet. In practice, the wet gas differential pressure on a horizontal Venturi-nozzle was observed to depart from the deLeeuw correlation at pressure turndown ratio of 30:1. Since OP is proportional to V2 the velocity turndown ratio for the Venturi-nozzle is at best 9:1 and, in practice, it can be as low as 5:1. Thus, in terms of flow velocity turndown, the performance of the Sonar meter far exceeds that of the Venturi-nozzle. Water Cut Meter The Red Eye 2G water cut meter is based on the principles of spectroscopy and relies on the large difference in the absorption of near infrared (NIR) radiation between oil and water. Differentiation is achieved by operating over a very narrow band of radiation with maximum intensity occurring at wavelengths where crude oil and water exhibit large differences in opacities. The Red Eye measures transmissions at multiple infrared wavelengths simultaneously and calculates the water fraction from the ratio of attenuation at different wavelengths. The technique operates consistently across the full range of 0% to 100% water cut, and is effectively insensitive to free gas. 4 100 90 0 80 ~ 70 c+"a ~ 60 .~ a 50 ~ 40 30 N g 20 10 0 - - - t 5% absolute error .~ ^ Red Eye 2G, NEL, Aug 2005, Horizontal e Red Eye 2G, NEL, Aug 2005, Vertical o~ ~O n 0 10 20 30 40 50 60 70 80 90 100 Reference Water Liquid Ratio, [%] Figure 3 -Performance of water cut measurement z 15 e 10 E O 5 H 0 0 W ~ -5 .~ a -10 as .. ea -15 - - - # 5% absolute error ^ Red Eye 2G, NEL, Aug 2005, Horizontal e Red Eye 2G, NEL, Aug 2005, Vertical o e° e e e e° e ----------- 8-------o -e ~----- e --e-- --- e e e e e ^ ^ °~ e ^ e ~ °e ^ ^ ^ e e e a ~e a ^~ e o `~ ^ ^ ^ ° 0 10 20 30 40 50 60 70 80 90 100 Reference Gas Volume Fraction, [%] Figure 4 -Performance of water cut measurement for wide GVF range? Data shown in Figs. 3 and 4 range from 10 to 95% GVF at low pressures.2 Even those points at the highest GVF do not constitute wet-gas flows with Lockhart-Martinelli parameter significantly higher than 0.3 (due to the low pressure and high liquid/gas density contrast)I. However, recent tests conducted at CEESI show very good sensitivity, correlation, and measurement capability in wet-gas flows at GVF up to 99.9%. The water cut measurement has been verified in separate studies and the remainder of the discussion in this paper will focus on the ability to measure liquid and gas flow rates by the Sonar-Venturi combination. 5 TEST ENVELOPE The flowmeter was tested at NEL (multiphase) and CEESI (3-phase wet gas) in August and September of 2007 respectively. The CEESI tests were conducted in the recently commissioned 3- phase wet-gas flow loop. 100 10 y E ~ 1 0 m 3 0.1 a J R 0.01 m a 0.001 0 0001 ^ NEL ^ ^ ~^ o CEESI ~ ® ^ o^ ~^ °~~ ° ^ ^ ®®ovo oa^~y GVF 50% ~ A • e 0 O GVF 90.9% ~ 0 _ o e o • ~ g GVF 99.0% ~ a ~ o ~ _ n GVF 99.9% ~ GVF 99.99% 0.1 1 10 100 Superficial Gas Velocity, [m/s] Figure 5 -Phase superficial velocity and GVF variations for NEL and CEESI test matrices. Figure 5 shows the entire test matrix for both facilities in terms of superficial liquid and gas velocities with no-slip GVF as isolines. From this view, it appears as though the two tests overlap, however, the test pressure at NEL ranged from 2 to 7.5 bar, whereas the test pressures at CEESI ranged from 14 to 55 bar yielding very different liquid/gas density contrasts (see table below). Consequently the high GVF points in the NEL test matrix are not representative of wet-gas conditions because the relatively low gas density results in a relatively low gas Froude number, Frg and a relatively high Lockhart-Martinelli parameter, XLM. The CEESI test envelope, on the other hand, covered Frg and XLM within the regions defined by API as Type I and Type II wet-gas flow.l CEESI NEL Pressure 14, 28, 55 bara 2 - 7.5 bara Tem erature 28-35 °C 22-42 °C WLR 0 -100% 1, 40, 75, 100% GVF (no sli) 97.5-100% 0 - 100% Total Volume Flow Rate 85-655 m /hr 14 - 460 m /hr LiquidlGas Density Ratio 16 at 55 bara 40 at 28 bara 98 at 14 bara 106 at 7.5 bara 485 at 2 bara Fr Sonar 1.5 - 20 0.07-2.6 Fr Nozzle 0.5 -5.5 0.02.-0.7 XLM 0 - 0.26 0.3-167 LM 0 - 0.72 0-1 6 WET-GAS TESTS CEESI Test Facility The CEESI (Colorado Engineering Experiment Station, Inc.) wet-gas facility, originally built in 1998, was designed for two-phase flow studies consisting of natural gas and hydrocarbon liquids. The loop has been recently redesigned for three-phase operation. Figure 6 shows the block diagram of the three-phase wet-gas loop used for the current tests. CIRCULATI^N HEAT COALESCING TURBINE ULTRAS^NIf CUMPRESSDRS EXCHANGER FILTER METER METER GAS CHR~MATOGRAPH TRIPLEX 2 0.5" PUMPS E^R C^RI^LIS CCJRI^LIS METER METER HYDR^CARB^N GAS-LIQUID LIQUID SEPARATOR LIQUID-LIQUID SEPARAT^R TRIPLEX 2 0.5" PUMPS C^RI^LIS CCJRI^LIS FOR METER METER WATER TEST TEST TEST TEST TEST LCJCATI^N 5 LUCATI^N 4 LOCATION 3 L^CATI^N 2 L^CATI^N 1 Figure 6 -Block diagram of wet-gas research loop, 4-inch test line Both a turbine meter and an ultrasonic meter measure the flow rate of the natural gas. The difference in mass flow rate between these two meters is monitored; if the difference exceeds a specified amount, the data is scrutinized for detrimental effects such as pulsation. If the difference is within tolerance, then all other meters installed in the research loop can be compared to the natural gas mass flow rate as measured by the turbine meter. Pressure and temperature measurements at various locations on the loop (including the test locations) are used to calculate local gas density. The hydrocarbon liquid and the water, which reside in the liquid-liquid separator, can be injected into the gas stream by positive displacement pumps (Triplex pumps). Coriolis meters measure the mass flow rate and the density of the liquids to be injected. The gas stream carries the liquid mixture through the meter test locations and on to the horizontal gas-liquid separator where it is then returned to the liquid-liquid separator. Stability of liquid density, gas composition, pressure, temperature and flow rate is monitored to determine steady state conditions. During each test point, a gas chromatograph obtains a sample of the natural gas on a 6-minute time interval. Using the average natural gas composition during the test point and the measured pressure and temperature at any given location in the test loop, the gas density at that location is determined using AGA-8. The composition of the gas has some seasonal variation with the methane composition ranging from approximately 83% to 95% during the year. The hydrocarbon liquid (ExxsolTM D80) is very similar to kerosene with less than 2 ppm sulfur. 7 e Figure 7 -Sonar-Venturi flowmeter installed vertically in flow loop. Figure 7 shows the vertical installation of the Sonar-Venturi flowmeter in the 4-inch wet-gas flow loop. The flowmeter was mounted immediately downstream of a blind T. Measurement Contrast The flowmeter has two independent measurements -the Sonar velocity and the Venturi DP. It has been established (as evidenced in literature and through tests at multiple flow facilities by the authors) that both instruments measure dry-gas flow-rates very well. In wet-gas flow, it is desirable for each instrument to have an over-reading that is dependent primarily on liquid loading and minimally on other flow parameters such as gas Froude number and line pressure. A modified version of the de Leeuw correlation (developed for horizontal flows) was found to work very well and has been adopted for the Venturi. The basis for the Venturi over-reading (ORV) and subsequent correlation is OR V = Q~.u~~uren~ (1) L S,~'?f with ORV = f,(X,Frg), (2) where the Lockhart-Martinelli parameter is defined herein, as: mA Pr 8 • The over-reading correlation for the Sonar meter (ORS) was established based on the measured flow velocity and the liquid mass quality (LMQ): ORS = Qt,apparent , (4) ~t,ref ~t,apparent ~m`4 ~ (~) ORS = f, (LMQ, Frg) ; (6) LMQ = ml ; (~) mt where V,,, is the Sonar mixture velocity after applying the Reynolds calibration. A necessary condition for solving for both unknowns (i.e., total flow rate and liquid loading), is to have two independent equations that characterize ORV and ORS. A convenient way to quantify the independence of the over-reading characteristics is to depict the contrast (i.e., difference in slope) of both over-reading trends. The apparent nozzle gas flow rate and the apparent Sonar bulk flow rate were divided by the reference total flow rate and plotted against XLM in Fig. 8. The contrast between the two trends is what allows for a successful iterative solution for the unknowns. 1.35 1.2 ~o 0 ~ 1.15 0 9.r o 1.3 1.25 c ;v 1.1 ~o a a ~ 1.05 0 o n~-~ ----------------- ~n 1 0.95 0.9 ~- 0.00 0.02 0.04 0.06 0.08 Lockhart-Martinelli, [-] o Nozzle o Sonar 0.10 0.12 0.14 Figure 8 -Difference in slope between the over-reading trends of Sonar and Venturi reveals the contrast between the two devices in wet-gas flow. 9 10% d ~ 5% 3 0 LL R .+ O H ~ 0% .O W d ::~ -5% -10% • ^ 14 bara 0 27 bara + 55 bara .....±5% + ~ + ++ ~ + ^ + + ++ + 0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2 Lockhart-Martinelli, [-] Figure 9 -Total flow rate relative error for wet gas. Figure 9 shows the total flow rate relative error predicted over all test pressures for the Sonar- Venturi flowmeter. Total flow rate is predicted well within ~5% for the test points across the full range of Lockhart-Martinelli parameter tested. The gas flow rate relative error is shown in Fig. 10. As expected, the gas rate performance follows the total flow rate since the liquid content by volume is negligible for a majority of the test matrix. 10% d .. ~ 5% 3 0 fA R c 0% •L Q W ::. -5% 0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 Lockhart-Martinelli, [-] -10% ^ 14 bara 0 28 bara + 55 bara .....± 5% o + + +~+ ,* ^ y + ++ + T Figure 10 -Gas flow rate relative error for wet gas. 0.2 10 • • 40% 30% a~ 3 20% 0 ~ 10% .~ = o% .~ 0 w -10% a~ R -20% -30% ^ 14 bara 0 28 bara + 55 bara i + ~ ^ ~ g ~ $ + # ++ I ++ ~+ ~ + -40% ~- 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2 Lockhart-Martinelli, [-] Figure 11-Liquid flow rate relative error for API Type II wet gas. Figure 11 shows the relative error in liquid flow rate for API Type II wet gas, defined by having XLM > 0.02. The dashed lines show that most of the points are contained within a X20% relative error band. Figure 12 shows the error in liquid flow rate for API Type Iwet-gas flows, where XLM < 0.02. In this case the data has been presented in absolute terms and is shown to be within X0.5 m3/hr. 1.0 t E 0.5 3 0 a 0.0 J C O W :3 -0.5 0 N Q ^ 14 bara 0 28 bara + + 55 bara ..... ± 0.5 m'/h + + + + + + + + + + +~ + + DD + + + + ~ + + + -----------------------•--...................-..---------.-...........---------........ft-----... -1.0 + 0 0.005 0.01 0.075 0.02 Lockhart-Martinelli, [-] Figure 12 -Liquid flow rate absolute delta for Type I wet gas. 11 • 1.5 ~ 1.0 E m R 3 0.5 0 LL .~ s 0.0 J C .` O w` -0.5 d .. _3 O N Q -1.0 -1.5 ^ 97%<GVF<99% ~ 99%<GVF<99.6% ^ ^ + 99.6%<GVF<100% ^ p+ ^p -------------- ,p o ~~ ~ ° ~ + ~ ~ ~ +o +4 ~ ~ + + + ++ + + Q I~ ~ ^ ---m-- ----- ---------- -------°------- ---------------------- 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Water cut, [-] Figure 13 -Error in liquid flow rate prediction vs. water cut. Figure 13 shows the effect of water cut on the measured liquid flow rate demonstrating that there is no discernable effect of liquid viscosity and to a certain degree density. MULTIPHASE TESTS The Sonar-Venturi is primarily designed for wet-gas flow; however, it was also tested at NEL to evaluate the performance in off-design conditions. An extension of the wet-gas iterative solution described above was devised for resolving the liquid and gas flow rates under multiphase flow conditions. While analogous ORS and ORV concepts are used in characterizing the multiphase response of the single phase devices, the defmitions of these quantities as well as their correlating parameters are different from the ones used for wet gas. The ORV in multiphase flows follows published methods and is analogous to variations in discharge coefficient in multiphase flow conditions.g'9 The Sonar over-reading was characterized in a form similar to the wet-gas methodology. No refinement was attempted for this first evaluation of multiphase performance and no effort was made to asymptotically match the multiphase and wet-gas models. 12 Figure 13 -Sonar-Venturi flowmeter at NEL multiphase test facility. The gamma densitometer in picture is for R&D only and has not been used in the Sonar-Venturi flowmeter calculations. The results were categorized using three gas volume fraction (GVF) ranges namely 0<GVF<60%, 60<GVF<80%, and 80<GVF<97.5%. It is worth emphasizing that even the highest GVF in this facility does not constitute wet-gas flows and that intermittent flow conditions occurs at all GVF above 30%. 400 350 300 s E 250 ~ 200 3 0 150 100 50 0 0 50 ~+ + + Q ~+ - e +' -+ {,, Reference --- t20% 100 150 200 250 300 Reference Total Flow Rate, [m'Ih] Figure 14 -Total flow rate in multiphase 350 400 Figure 14 shows the total flow rate for all GVFs ranging from 0 to ] 00% and all water cuts ranging from 5 to 75%. It can be seen that the total flow rate is predicted to within X20% for GVF<80%, however, at higher GVF the measurement is erratic. The velocity reported by Sonar at these 13 conditions is not deemed representative as a time-averaged total flow rate. Further refinement of Sonar processing is required to resolve these flow conditions accurately. 120 100 r 80 m R ~ 60 3 0 LL a 40 J 20 0 '~ - 0 20 40 60 80 100 120 Reference Liquid Flow Rate, [m'/h] Figure 15 -Liquid flow rate in multiphase. Similar to the total flow rate, Fig. 15 shows that liquid flow rate is measured to within 20% for GVF<80%. The effect of the inaccurate Sonar velocity between 80 and 97.5% GVF exacerbates the liquid error. 400 300 L ~ 250 ~ 200 3 0 w 150 R C7 350 100 50 ~^ ^ ^ v' ^, ' ~, ^.' ~~ Q' ^ 0%<GVF<60% 0 60%<GVF<80% + 80%<GVF<100% Reference ---±10% -~ + +, '+ + + -++ -++ ~+ + 0 n°# ~, nF ± ~~n * ,~ ~ +~ ,n ~+ .~+ ^ 0%<GVF<60% 0 60%<GVF<80% + 80%<GVF<100% Reference --- ±20% 0~ 0 50 100 150 200 250 300 350 400 Reference Gas Flow Rate, [m'/h] Figure 16 -Gas flow rate in multiphase. 14 • Figure 16 shows the gas flow rate. The gas rate is predicted to within 20% between 60 and 80% GVF, but larger errors are prevalent at lower GVF. Again, the measurement performance between 80 and 97.5% GVF is reduced due to low accuracy of the Sonar in this regime to the widely time- varying properties of the flow. Currently Sonar algorithms do not attempt to capture transient properties, but is rather reporting volumetric and time-averaged flow properties. It is worth noting that the Sonar processing algorithms can readily identify the slugs and offer potential to calculate both slug and bubble velocity and volume. CONCLUSIONS The Sonar-Venturi-(Red Eye) flowmeter constitutes ahigh-accuracy top-side evolution of the downhole fiber-optic flowmeter technology. The flowmeter combines Sonar sensors with an extended throat Venturi that enables measurement of liquid and gas rates in wet-gas and multiphase flows. Addition of a Red Eye 2G water cut meter enables distinction of oil/condensate and water. This flowmeter has been tested in a range of wet-gas and multiphase flow conditions at CEESI and NEL where it was found that for wet-gas flows the total and gas flow rates are measured to within ~5% and liquid rate is determined to be within X20% in API Type II wet gas and X0.5 m3/hr in API Type I wet gas. In multiphase flows, liquid and total rates are predicted to better than X20% at GVF below 80%. In low pressure highly unsteady slugging flows, there is a reduction in Sonar measurement capability and hence the measurement performance is reduced. This was evident between 80 and 97.5% GVF in the multiphase facility. Additional work is required to improve the multiphase and especially Sonar performance in unsteady flow conditions. The Red Eye water cut meter has been demonstrated in other work to be within f5% (absolute) over the full range of GVF and WLR and is not significantly affected by slugging flow conditions. ACKNOWLEDGEMENTS The authors gratefully acknowledge BP Exploration Operating Company Intl. for permission to present this work. We would also like to thank directly or indirectly contributed to this work. NOMENCLATURE Acronyms and Symbols A = Area, [m2] API = American Petroleum Institute CEESI = Colorado Engineering Experiment Station, Inc f = Function Fr = Densimetric Froude Number, [-] GVF = Gas Volume Fraction, [-] LMQ = Liquid Mass Quality m = Mass flow rate, [kg/s] NEL = National Engineering Laboratory NIR = Near-Infrared ORS = Over-Reading Sonar, [-] ORV = Over-Reading Venturi, [-] Q = Volumetric Flow Rate, [m3/s], [m3/hr] V = Velocity, [m/s] WLR = Water Liquid Ratio, [-] Limited and Weatherford our co-workers who have 15 XLM = Lockhart-Martinelli parameter, [-] 4P = Differential Pressure, [bar] Subscripts g = Gas 1 = Liquid m = Mixture s = Superficial t = Total REFERENCES [ 1 ] "State of the Art Multiphase Flow Metering" API Publication 2566, First Edition, May 2004. [2] Hall, A., Lievois, J., and Adejuyigbe, B., "Testing of the Red Eye Near-Infrared Water Cut Monitor for Application as a Water Cut Sensor in Multiphase Flow Conditions," Multiphase Pumping and Technologies, International Conference & Exhibition, Abu Dhabi, 10-14 February 2007. [3] Kragas, T.K., Johansen, E.S., Hassanali, H., and Da Costa, S. L.: "Installation and Data Analysis of a Downhole, Fiber Optic Flowmeter at BP's Mahogany Field, Offshore Trinidad," SPE 81018, SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of- Spain, 27-30 April 2003. [4] Johansen, E. S., Kragas, T. K. and Beaumont, P., "Downhole Fiber Optic 3-Phase Flowmeter Field Test at BP Mungo," 21st North Sea Flow Measurement Workshop, Tonsberg, 28-30 October 2003. [5] Sandoy B., et al. "Improved Reservoir Management with Intelligent Multi-Zone WAG Injectors and Downhole Optical Flow Monitoring," SPE 95843, SPE Annual Technical Conference and Exhibition Dallas, 9-12 October 2005. [6] De Leeuw R., "Liquid Correction of Venturi Meter Readings in Wet-gas Flow", North Sea Workshop 1997. [7] Stewart, D., et al. "Wet-gas Venturi Metering" North Sea Flow Measurement Workshop, T,ansberg, Norway, 2003. [8] Hall, A.R.W., Reader-Harris, M.J. and Millington, B.C., "A Study of the Performance of Venturi Meters in Multiphase Flow," 2nd International Conference on Multiphase Technology, Banff, 22 June 2000. [9] Vilagines, R. and Hall, A.R.W., "Comparative Behaviour of Multiphase Flowmeter Test Facilities," Oil and Gas Science Technology, Vol. 58, No. 6, pp. 647-657, 2003. 16 6th South East Asia Hydrocarbon Flow Measurement Workshop • 7th _ 9th March 2007 Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions Andrew Hall, BP Exploration & Production John Lievois, eProduction Solutions Babajide Adejuyigbe, eProduction Solutions INTRODUCTION Near infra-red spectroscopy is a well-known technique for chemical analysis and has been successfully applied to measurement of small quantities of water in a variety of media, such as paper, methanol, tobacco, etc. The Red Eye® 2G water cut monitor was developed to exploit the very characteristic attenuation of infra-red light by water as a means to measure the water cut in mixtures of oil and water. The water cut monitor uses four specific NIR wavelengths to provide a capability for water cut measurement across the full range from 0% to 100%. The monitor was known to operate reliably in the presence of a small quantity of free gas (up to 20%) from previous tests, and the purpose of this new test programme was to evaluate the capability of the instrument to operate in much higher gas volume fraction environments. This paper presents new data obtained in three test campaigns at the TUV NEL multiphase flow facility. The tests spanned the full range of water cuts from 0% to 100%, at a range of fluid mixture velocities, and with gas volume fractions in the 60% to 95% range. Most tests were for meters in a horizontal orientation, but some additional tests were included in vertical flow. The results exceeded expectations of water cut measurement uncertainty at these high gas fraction conditions, with very little dependence of the uncertainty on GVF. 2 RED EYE WATER CUT MONITOR 2.1 Description of the meter The Red Eye water cut measurement is based on near-infrared absorption spectroscopy. As shown in Figure 1, the dependence of absorption of near-infrared light on wavelength varies with the composition. At several key wavelengths, infrared light absorption is dependent on the behaviour of carbon-hydrogen and oxygen-hydrogen bonds in the molecules. Water, contains O-H bonds and hydrocarbons do not, therefore allowing infrared absorption to distinguish water from organic molecules. Furthermore, the characteristic wavelength associated with bending of the H-O-H bond in water is different from the wavelength associated with O-H bond stretch, so there exists the potential for water to be distinguished from other molecules, such as methanol, containing O-H bonds. The Red Eye 2G water cut meter extends the performance of the earlier 1 G meter, which used a single wavelength, to allow more accurate measurements of water cut at lower water- cut, by simultaneously measuring multiple wavelengths that include both the water and oil absorbent peaks. Scattering effects caused by emulsions, sand, or gas bubbles, are expected to have the same effect at all wavelengths and as such can be eliminated. Furthermore, changing salinity should have no effect on the measurement, since the water absorption is based on the water molecule itself, not what is dissolved in the water. The internal design of the meter is shown in Figure 2. The meter consists of a probe which is inserted into the flow either through a 1-inch NPT tapping or using a 1'/2-inch flanged connection and an electronics module mounted directly onto the probe. The only external connections required are for power (10 to 30 V DC @ 8 W) and output signal (4-20 mA analogue or RS-485 MODBUS outputs). 6th South East Asia Hydrocarbon Flow Measurement Workshop 7th _ 9th March 2007 • The main measurement section within the insertion probe has a small gap, with an infrared source on one side and detector consisting of a fibre optic bundle on the other. Between the optical source and detector and the process fluids are sapphire windows for their optical and mechanical properties including abrasion resistance. 2.2 High gas fraction test philosophy The meter had previously been tested at gas volume fractions up to about 20% GVF, demonstrating that gas at this level had only a minimal effect on the water cut measurement. However, the meter had never been tested at higher gas fractions prior to the BP test in August 2005. Initially this test, simultaneous with testing of other equipment, was just intended to explore the impact of high gas fractions on the meter, with no preconceived expectations of its performance under these conditions. 2.3 Installation of meters and test matrices The Red Eye meter was tested in horizontal and vertical flow without a mixer in August 2005; in a horizontal orientation with a static mixer immediately upstream of the Red Eye meter in February 2006; and in horizontal flow, without a mixer but in a pipe spool of restricted diameter (2.4 inch in a test line of 4 inch diameter) in November 2006. The meters were located approximately 80 feet downstream of the inlet to the multiphase test section. The test section adjacent to the meter was instrumented with a pressure transmitter and a platinum resistance thermocouple. These instruments provided the reference pressure and temperature measurements for correction of the reference gas volumetric flowrate to actual meter conditions at the Red Eye meter. The August 2005 horizontal flow test was conducted in series with another meter undergoing a performance test, and so the test matrix was determined by the requirements for the FAT, which required high flowrates. Tests were conducted at 5%, 25%, 40% and 100% water cut. The reason for testing at 100% water cut was to allow testing at high liquid flowrates. The schedule was also very tight, because of the need to deliver the meter to its field installation, and this did not allow additional time in this configuration for conducting further tests. Several other meters were also included in this test including a Weatherford sonar flow meter (also shown in Figure 3). The August 2005 vertical flow test was conducted immediately following the horizontal test, but with the commercial multiphase meter removed from the test line. Tests were conducted at 5%, 75% and 90% water cut. Following encouraging results obtained in the August 2005 campaign, it was decided to conduct a more systematic test, concentrating on the Red Eye meter alone. This was installed in February 2006, once again in a horizontal orientation, shown in Figure 5, and a test matrix was designed which spanned the previous tests, but now included more intermediate water cuts. The water cuts tested were 5%, 25%, 40%, 50%, 60%, 75%, 82.5%, 87.5%, 90%, 92.5%, 95% and 97.5%. It would also have been desirable to include some tests between 5% and 25%, but these conditions are difficult to set up and control in this flow facility. An additional test was conducted in November 2006 of other equipment, with a Red Eye meter included as part of the test, to maximise utilisation of the test facility. The water cuts tested were 5%, 25%, 40%, 50%, 60%, 75%, 90% and 100%, covering roughly the same ranges of conditions as the previous test. Figure 7 shows the planned and actual test matrices for both the 2005 and 2006 test programmes. 2.4 Reference system (TUV NEL multiphase flow test facility) The TUV NEL multiphase flow facility is located in the James Young Building in East Kilbride, near Glasgow, Scotland. This site is also the location of the UK National Standards for flow measurement (oil, water and gas standards). The TUV NEL multiphase flow facility consists of a 250 barrel separator which is filled with the water and oil phases. Nitrogen gas is generated on demand by evaporation of liquid nitrogen 6th South East Asia Hydrocarbon Flow Measurement Workshop 7t" - 9th March 2007 • which is stored in a 40m' tank. The nitrogen is used on a one-pass basis and is exhausted to atmosphere at the outlet of the separator. The oil is metered though Faure-Herman helicoidal turbine meters, either 1'h-inch or 3-inch depending on the flowrate required. These meters are calibrated in the UK National Standard gravimetric oil calibration facility at TUV NEL, using oil of an appropriate viscosity. The water is metered through standard flat-bladed turbine meters, either 1'/z-inch or 3-inch depending on the flowrate required. These meters are calibrated in the UK National Standard gravimetric water calibration facility at TUV NEL, using fresh water. The gas is metered through standard flat-bladed turbine meters, either 'h-inch, 1-inch or 3- inch depending on the flowrate required. The %2-inch meter was not used for these tests. These meters are calibrated in the UK National Standard gravimetric gas calibration facility at TUV NEL, using air. Both the oil and the water phases can be cross-contaminated with a small proportion of the other phase, due to limitations of the separator capacity. Generally the cross-contamination becomes most noticeable at higher liquid flowrates when the water cut is in the range 25% to 50%. The water content of the oil stream is detected using acapacitance-based water-in-oil monitor. This is specifically calibrated on the fluids in the test facility, and gives an uncertainty in the water cut of the oil stream of less than ±1 % absolute. The oil content of the water stream is detected using aCoriolis-based densitometer. This takes as an input the density of the oil and water as a function of temperature, and the temperature-corrected reading from the densitometer is used to calculate the oil content. This gives an uncertainty in water cut of the water stream of less than ±1 % absolute. Extensive testing at TUV NEL has demonstrated that the cross-contamination of the liquid streams has a negligible impact on the turbine meter accuracy over the ranges encountered. Tests have also shown that there is no dissolved gas in the separator outlets, and as the gas is generated from pure liquid nitrogen, it is completely dry at the reference gas flowmeters. Since the flows are metered on a volumetric basis, the temperature of the oil and water, and the temperature and pressure of the gas, is measured at the flowmeters. The volumetric flowrates are corrected to the measured temperature and pressure at the location of the test meter in the multiphase flow line to give the correct volumetric flowrates at the test meter at line conditions. 2.5 Fluid properties The fluids used were stabilised crude oil, salt water and nitrogen gas. The crude oil is topped to remove high volatility components, and mixed with kerosine in approximate proportions of 70% crude to 30% kerosine to restore the original viscosity. The crude oil is a mixture of crudes from different North Sea oil fields, including Forties, Beryl and Oseberg crudes. The density and viscosity of the crude oil mixture are periodically measured as a function of temperature The salt water phase consists of a solution of magnesium sulphate (MgSO4). This salt was selected by TUV NEL to avoid (or minimise) corrosion of pipework. It is important that the water phase has salinity similar to the application conditions, both for electrical type meters (capacitance /conductivity /microwave) and for dual-energy gamma densitometers. The concentration of the water phase is calculated from its density, which is periodically measured as a function of temperature. The water density is normally measured immediately before a test programme, as the density gradually changes due to evaporation of water. The gas phase is nitrogen. The density of nitrogen can be estimated with sufficient accuracy at the low operating pressure using the ideal gas equation, with a gas molecular weight of 28. TUV NEL uses a more exact equation of state for reference flowrate calculation. 3 6`h South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ 9cn March 2007 2.6 Calibration of the Red Eye meters The Red Eye meters were calibrated by flowing single phase oil and single phase water through the meters prior to starting the multiphase flow tests. Manual intervention was required during the tests to select the optimum combination of wavelengths depending on the water cut, 2 out of the 4 wavelengths being used for any one measurement. This process is somewhat automated in the standard (water-oil) model, but had not been fully implemented for high GVF operation. However, since the exact reference data was not available to the meter operator at the time of the tests, the water cut algorithm selection was necessarily based on the readings from the Red Eye itself, as it would be in an operating situation. 2.7 Data recording and processing The test facility was run until the flow was sufficiently stable to perform a test. Since the test conditions were almost all in the slug flow regime the operator's experience was relied on to determine this stability time. Typically it took less than 5 minutes between test conditions. Each test condition was recorded for a period of 5 minutes, with the Red Eye set up to record data at 1 second intervals. The Red Eye data files included time, water cut and four infrared absorption figures. Only the water cut was used for further data analysis by BP. An average was taken of the water cut over the test, along with standard deviation and confidence to check for data quality. TUV NEL provided data for oil flowrate (litres/sec), water flowrate (litres/sec), gas flowrate (litres/sec), temperature (°C) and pressure (barg). Again the measurement was provided for the 5 minute period of the test, calculated from 100 three-second samples of the reference readings. All data was reported from the meter at line conditions, i.e. at the temperature and pressure at the multiphase meter. No reference data from TUV NEL was provided to Weatherford during the tests. 3 TEST RESULTS 3.1 Meter results: 2005 test campaign Figure 10 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal and vertical flow tests conducted in August 2005. Figure 11 shows the error in these measurements plotted against the reference gas volume fraction and Figure 12 shows the error in water cut measurements plotted against the reference water cut. Overall the water cut measurements were within about ±5% of the reference values, with a tendency to under-read water cut. It was not clear at this stage whether this was due to the particular water cuts selected for testing, or a slight non-uniform distribution of the oil and water in the horizontal pipe, and therefore further testing was required. 3.2 Meter results: February 2006 test campaign Figure 13 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal tests conducted in February 2006. Figure 14 shows the error in these measurements plotted against the reference gas volume fraction and Figure 15 shows the error in water cut measurements plotted against the reference water cut. With the exception of the tests at around 60% water cut, all the water cut measurements were within about ±5% of the reference values. There is a quite clear variation of the errors in water cut measurement with water cut, with the abrupt switches in errors at different water cuts across the range related to the selection of pairs of wavelengths used to determine water cut; it is likely this could be optimised to improve the measurements. There is a much smaller variation with GVF, and although this is not clear from Figure 14, it is best demonstrated by plotting results for individual water cuts against GVF, as shown in the next section. 4 6cn South East Asia Hydrocarbon Flow Measurement Workshop 7tn -Stn March 2007 3.2 Meter results: November 2006 test campaign Figure 16 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal tests conducted in November 2006. Figure 17 shows the error in these measurements plotted against the reference gas volume fraction and Figure 18 shows the error in water cut measurements plotted against the reference water cut. The key difference between these tests and the tests conducted earlier in the year is an improvement in the mid-range water cut measurement (50% and 60% water cut). This improvement is a result of algorithm development, with no change to the meter hardware. Using the improved interpretation algorithm, all the water cut measurements were within about ±5% of the reference values. 3.3 Meter results: comparison of 2005 and 2006 test campaigns Figure 19 shows the water cut measurements from the Red Eye meters against the reference water cut for the test campaigns in August 2005 and February and November 2006. Figure 20 shows the error in these measurements plotted against the reference gas volume fraction and Figure 21 shows the error in water cut measurements plotted against the reference water cut. Apart from the measurements at the lowest water cuts, and at 50% and 60% water cut, these figures show the good consistency between the results from both test campaigns, suggesting that there is limited impact of a static mixer in multiphase flow conditions. The differences at 50% and 60% water cut are a result of the improved interpretation algorithm. Figure 22 to Figure 34 show the water cut measurement errors plotted against GVF for each individual water cut range. These plots quite clearly show the limited scatter in the water cut errors as a function of GVF, and also the good consistency between the results from the two test campaigns. At each specific water cut there is a scatter of only ±1 or 2% in the water cut errors, up to GVF values over 90%. 4 CONCLUSIONS The test results show that the principal influence on the water cut measurement accuracy under these multiphase flow conditions is the water cut itself, with a relatively small influence of the gas fraction. Typically at any particular water cut there is a scatter of about ±2% in the water cut errors across a range of gas fractions from 70% to 95%. No other in-line multiphase flowmeter (without full or partial separation) is able to measure water cut within a scatter of ±2%, particularly at high water cuts, under these conditions of high gas volume fraction. The tests have also shown that there is a relatively limited impact of the presence of a static mixer on the test results, or of the orientation of the meter (horizontal or vertical). While these tests show that good measurements of water cut can be obtained in high gas fraction multiphase flow conditions, it should be noted that the gas phase used in the tests was nitrogen, which is completely transparent to infra-red light at these wavelengths. It is expected that hydrocarbon gas will have an impact on the measurement, and the meter should therefore be tested in a test facility using hydrocarbon gas. A secondary evaluation also needs to be conducted to determine the impact of alcohols (methanol, etc.) on the water cut measurement. These test programmes were conducted over short timescales in an ideal laboratory environment with well characterised and `clean' fluids. It is recommended that further data is obtained for the longer term performance of the meter in the laboratory and more importantly in real production fluids. 5 ACKNOWLEDGEMENTS The test work at TUV NEL and analysis of the test results was funded by a BP subsea metering technology project. The Red Eye meters and support personnel for the test programme were provided by eProduction Solutions. The support of both organisations and their permission to publish this work is gratefully acknowledged. 5 6th South East Asia Hydrocarbon Flow Measurement Workshop 7th _ 9th March 2007 Figure 1: Near-infrared absorption spectrum Fiber Optic Bundle Collectaar Optics Probe Assembly Sapphire Window Sapphire Window NIR Emitter Figure 2: Red Eye water cut meter cross-section 6 6ch South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ 9cn March 2007 Figure 3: Red Eye meter installation (August 2005 horizontal test) Figure 4: Red Eye meter installation (August 2005 vertical test) 6th South East Asia Hydrocarbon Flow Measurement Workshop 7th _ 9th March 2007 Figure 5: Red Eye meter installation (February 2006 test) Figure 6: Red Eye meter installation (November 2006 test) 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7~n - 9`n March 2007 5% water cut ~ ~~ 30 ~ 6 160 uo +. o m6 +e a [IHOnmNai. Au0 2005 o Verb. Aup 2005 •w„mr..i.Fm 3ao6 4 • • 1P• •F~w~orz•, w. zmfi • ao • • o e•• ^ oG •6~ -- >G oo••G •• ^ a ^ ~ 00 o e - e e e e a oo - o 0 +0 30 30 10 50 60 10 BO SO t00 GVF PA) 40% water cut ~ ~~ ) ]6 60 X -- 10 3 t30 180 t80 0 t0 20 30 a0 SO 80 )0 BO BO t00 GVF (%) 60% water cut ~ ~~ •HOnzoMai. FeE 2006 30 onxo •, ov • M < • • • • • • • 6 - _ ___ • • • • • F 00 t00 3 7 130 180 - 0 +0 30 30 d0 60 10 BO BO 100 GVF (%) 25% water cut ~ ~~ S fi0 +0 +zo f60 mo OlbnzoMel. Auq 3005 •NaizoMel. FeE 200fi •MOnzoMl.Ibv 3006 • • • O O • O •OrO~ 0 +0 30 30 a0 50 60 ]0 80 BO 100 GVF (X) 50% water cut 6 80 X 00 100 4 +z0 +d 0 +6 0 e~:aMa enz~s : ~ ~ F av 200fi .. . • •c •p b a• G • p •• O I o O •o G 0 t0 30 30 a0 50 60 ]0 BO 90 +00 GVF (%) 75% water cut 30 6 0 • • ~ • 5• 00 t00 3 ~ 130 + 0 t0 20 b 60 EO i0 00 AD tOD GVF (X) Figure 7: Test matrices for TUV NEL test (August 2005, February 2006, November 2006) 9 6cn South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ 9cn March 2007 82.5% water cut •~~si. Fe9 zoos ~ ~ • ..a .e -- ~ fi - - .• x a° --~ ~ ,9 s uo tB0 0 +0 30 3o a0 `D 80 10 BO 90 t00 GVF (14) 90% water cut ~ ~~ fi p eo 6~° ioo 4 ,z ~aa iea 190 e .n e,aaa ro , Honro~., ra. zoos ., s • a.• w •o -_._- - - e q-• 4 0 0 t0 ZO 30 a0 50 60 70 90 80 100 GVF I%) 95% water cut i 8 5 D - fi • • • +0 0 ~9a 87.5% water cut 00 _.~~roma. FeO xaos • zo -- . '~' .9 .. . ~ a9 - - eo ,9 s izo +. o t6o 1B 0 0 t0 20 ?0 <0 50 fi0 )o BD W 100 GVF 1%) 92.5% water cut V V •w~:wna, F.e zoos zo - • .o .. . ~ e _ • eo +0 0 s ~ ,: tfi 0 to ZO 30 10 50 fi0 t0 80 W 100 GVF (%) 97.5% water cut zo .o Bo Bo goo uo uo +a o +o zo 30 .o so w io eo eo +ao +e o o +o :0 3a .o m ~o m m +oo GVF riG) GVF (X) 100% water cut ¢ ofi ~e d0 'a fi eo °w~.omi. nw zooa e~,~~.A~9399a •HOnro~iei. Fe0300fi r-w„zoos -_----- - • • •° s • d •G o c o • G • •° o o- 0 e o o ° ° o >s 10 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn _ Stn March 2007 ~ :r i +.. ~I G~ .'b~ ~ , ~~~~~...-. .7Axt1E r•~ x ' yr tK~~ i. tse>~~ ~ ~ ~~~ ~ i `•, _ .. ~ ~ ~~.~ .. `_~_ T _ y ~ 1~_ Figure 8: Location of multiphase flow meter test facility Pressure and Three phase separator f I ow coat rol .. _ `. Liquid Test meter - nitrogen Reference metering Pump Pump Test meter Gas Figure 9: Schematic of TUV NEL multiphase flow test facility 11 6th South East Asia Hydrocarbon Flow Measurement Workshop 7th _ 9th March 2007 100 90 80 70 '. +. 60 v :: 50 3 m 40 d 30 20 10 0 - - - +/- 5 % absolute error ^ Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical ^ ,^ 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 10: Red Eye water cut vs. reference water cut (2005 multiphase flow tests) zs 20 d V d 15 ry w m ~ 10 0 w y 5 3 O a 0 m °-- -5 0 - - - +/- 5 % absolute error ^ Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical as -10 3 V d -15 ifl -20 -25 x x x x x x --------------------------- xx x ------ X --~c-- ~--~ X ----XXX x-~------ X x x ° ° ~ x ° xx xx ^ ^ ° x x x x OPx ~ x ^~ x x ~~ o°x ~ ° ~ ^~O x °°o ~ °x ° ------------------------- ------0~-----a----- ° ° 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 11: Red Eye water cut error vs. reference GVF (2005 multiphase flow tests) 12 6ch South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ 9cn March 2007 zs 20 d U aci 15 a> w d E 10 w s Y 3 O ~ 0 m °-- -5 0 t: m -10 - - - +/- 5 % absolute error ^ Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical ^ X ^ 3 V d -15 ~. A -20 -25 ! I I + i ~ I I I I- I 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 12: Red Eye water cut error vs. reference water cut (2005 multiphase flow tests) 100 90 80 70 0 .. 60 3 v 50 3 ,mod, 40 d 30 20 10 0 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal ~~ J •~ ~. ~, ~ • i~ '• ~ • • 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 13: Red Eye water cut vs. reference water cut (February 2006 multiphase flow tests) 13 6th South East Asia Hydrocarbon Flow Measurement Workshop 7m _ 9th March 2007 25 20 m V aci 15 w d ~ 10 0 w y 5 0 a ~ e -5 0 m -10 3 v y -15 3 -20 -25 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal • • • • • ~ • • ~ ~ • • • • ~ ~~ • • • •• •• • • •• • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 14: Red Eye water cut error vs. reference GVF (February 2006 multiphase flow tests) 2s 20 d V aci 15 w d ~ 10 0 ~ 5 :~ a ~ ~- -5 0 d -10 v y -15 3 -20 -zs - - - +/- 5% absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal --M--------------------------------------------~--------•F -- ~• • ~~-- • • • ~ ~ • i • • « • • • ------------------ ------------- • ----~~-------- ~•--- - t------ • ~ t, y 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 15: Red Eye water cut error vs. reference water cut (February 2006 multiphase flow tests) 14 6`n South East Asia Hydrocarbon Flow Measurement Workshop 7tn - Stn March 2007 100 90 80 70 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Nov 2006, Horizontal , w N~ ,• ,; •`s . .• .s •, •~ -• ~- r' ° 60 ~: 50 A 3 m 40 d 30 20 10 0 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 16: Red Eye water cut vs. reference water cut (November 2006 multiphase flow tests) 25 20 m V a~i 15 d w m ~ 10 0 y 5 3 a 0 e -5 0 d -10 - - - +/_ 5 % absolute error • Red Eye 2G, NEL, Nov 2006, Horizontal • • • •• ~ j• ~ ~«'•1 ~•i ---------------------------------------- ---- ~-~-'~-j'••r--- `y -15 m -20 -25 I I I I I I ~ I I F I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 17: Red Eye water cut error vs. reference GVF (November 2006 multiphase flow tests) 15 6th South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ Stn March 2007 25 20 d V aci 15 w d ~ 10 0 w y 5 0 is \° °-- -5 0 m -10 - - - +/_ 5 % absolute error • Red Eye 2G, NEL, Nov 2006, Horizontal ` • •L • ~ •~ i" • M •• ~ • •• t =• ~_- • • •S • • •- iu -15 m -20 -25 I { i ~ i ~ i , i i 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 18: Red Eye water cut error vs. reference water cut (November 2006 multiphase flow tests) 100 90 80 70 e ~ 60 U :: 50 3 m 40 d 30 20 10 0 - - - +/- 5% absolute error ~ Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical ~i' • Red Eye 2G, NEL, Feb 2006, Horizontal r • Red Eye 2G, NEL, Nov 2006, Horizontal ~ ~ ~ • • l' . • ~~ •~ • •~ ~^ 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 19: Red Eye water cut vs. reference water cut (2005 and 2006 multiphase flow tests) 16 2s 20 d V aci 15 d w d ~ 10 0 w y 5 3 0 0 N a ~- -5 `o d -10 v `m -15 ~v ~ -20 -25 6ch South East Asia Hydrocarbon Flow Measurement Workshop 7ch -Stn March 2007 - - - +/- 5 % absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal x x X •x » x xX x • -------------------------------------~ ~ ~--~ ~ --~~ X~ x ~• ->~--- x o •~•j ~ 7ic• wo ~.•~:.~ ~ • X X X X ~X ' O • • ~ ~ ~o~ °o• f • o •• -- - -------------------------------------oo--•••a b~s~o•i •~ •! ~ e• b • • •• •• • •• • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 20: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests) 25 20 d V aci 15 d w d ~ 10 O y 5 3 a 0 ~o "- _5 O d -10 3 y -15 -20 -25 - - - +/_ 5 % absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal • • ---- o ~• ~ r • ~ • •• • a • •- • N t y 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 21: Red Eye water cut error vs. reference water cut (2005 and 2006 multiphase flow tests) 17 6th South East Asia Hydrocarbon Flow Measurement Workshop 7tn _ Stn March 2007 2s 20 m V aci 15 d w d ~ 10 O y 5 3 O ~ 0 to °- -5 `o - - - +/- 5 % absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal --------------------- -- ---- ---------- - ~ --- --- x x x-'~--~--- x~X xxiEx • x • t • w • • x x x x x x • • ~ °~ ° °8 • •i ° • • b • ~~ ° ° o• -- ^ o ° ----------- ° 0 rv -10 U m -15 is -20 -25 I i i I i ~ a I I ! 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 22: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 5% water cut) 2s 20 d V aLi 15 d d £ 10 O w y 5 3 O ~ 0 m °- -5 O m -10 - - - +/_ 5 % absolute error ° Red Eye 2G, NEL, Aug 2005, Horizontal • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal ° o ° • • °p °•° •••~ of• •+ • • 3 V y -15 is -20 -25 I I I i ~ i i ~ 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 23: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 25% water cut) 18 zs 20 d V 15 w d ~ 10 0 w as 5 0 a 0 °- -5 O d -10 3 U 6`n South East Asia Hydrocarbon Flow Measurement Workshop 7`n - 9`n March 2007 - - - +/_ 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal • • • • • • • • _• •• • •• • • • • • d -15 l0 -20 -25 I I I I I I- i F I t 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 24: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 40% water cut) 2s 20 d V a~i 15 d d £ 10 0 w y 5 0 ~ 0 °- -5 O d -10 .. 3 d -15 m -20 25 - - - +/- 5 % absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal --------------- • • • • • • •~ • • • 0 00 • • o ~ 9 --~•---- ~-'- -~! --- ---- --------o-- - - - - - - - - - - - - - - - - - - - - - - - - 0 - • i • •~ • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 25: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 50% water cut) 19 6~n South East Asia Hydrocarbon Flow Measurement Workshop 7rn _ 9cn March 2007 2s 20 d v d 1s d w d ~ 10 0 w d 5 .. 3 0 a 0 -5 O at -10 d -15 m -20 -25 0 Figure 26: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 60% water cut) 2s 20 d U aCi 15 d d ~ 10 0 w y 5 a 0 R °•- -5 0 m -10 - - - +/- 5 % absolute enor x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal • • x •• ~• • •x• •• x~ • r- ~ - `y -15 ~o 3 -20 -2s i ~ I + I ~ I ~ i 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 27: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 75% water cut) 20 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) 6`h South East Asia Hydrocarbon Flow Measurement Workshop 7"' - 9"' March 2007 25 20 m V aci 15 m w d £ 10 0 w y 5 0 ~ 0 m °- -5 0 d -10 - - - +/_ 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal • + • • • • • • `y -15 m 3 -20 -2s I I I I I ~ I I I I I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 28: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 82.5% water cut) zs 20 d V d 15 m w d ~ 10 0 w d 5 0 ~ 0 R =- -5 O d -10 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal _---------1•----+~+-- ~ ~i~ ~-_--~ - __ • M 3 y -15 m -20 -25 I I -~ I I I I I I {~ 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (°/a) Figure 29: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 87.5% water cut) 21 6~h South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ 9cn March 2007 2s 20 d V y 15 d d ~ 10 0 w d 5 3 0 a 0 w =- -5 `o ~ -10 - - - +/_ 5 % absolute error x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal x x x x • xx x • --- -- --x --~c---~----X -----+--------- x • x • 1• • • • • • • • 3 V y -15 ~o 3 -20 -25 a I I ~ i ~ I I I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 30: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 90% water cut) 25 20 a~ V a~i 15 w m ~ 10 0 w y 5 0 w 0 tt7 °-- -5 O d -10 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal --------------------------------------------------------- •~•- --- •• •• • • 3 V `y -15 io -20 -25 ! I I F ~ I + + + I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 31: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 92.5% water cut) 22 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn _ Stn March 2007 25 20 d V a~i 15 w a~ ~ 10 0 w y 5 3 ~ 0 R -5 0 d -10 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal ~- 3 V d -15 R -20 -25 I I I F I I I I I I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 32: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 95% water cut) 2s 20 d V d 15 d w m £ 10 0 w d 5 .. 3 0 9 0 -5 0 d -10 - - - +/_ 5 % absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal • Red Eye 2G, NEL, Feb 2006, Horizontal 0 0 0 v d -15 .. ~a -20 -25 I I ~ I I I I I I I i 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 33: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 97.5% water cut) 23 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn - Stn March 2007 2s 20 m aci 15 d d £ 10 0 d 5 O ~ 0 m -5 O m -10 3 y -15 ~o -20 -25 - - - +/- 5 % absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical ~, • Red Eye 2G, NEL, Nov 2006, Horizontal m o0 o M o o: o o ~ • •• • i 0 10 20 30 40 50 60 70 80 Reference GVF (%) Figure 34: Red Eye water cut error vs. reference GVF (2005 multiphase flow tests at 100% water cut) 90 100 24 Flomeko 2005 6 - 9 June 2005 CLAMP-ON, SONAR-BASED VOLUMETRIC FLOW RATE AND GAS VOLUME FRACTION MEASUREMENT FOR INDUSTRIAL APPLICATIONS Daniel L. Gysling, CiDRA Corporation Douglas H. Loose, CiDRA Corporation Alex M. van der Spek, ZDoor BV ABSTRACT A clamp-on, sonar-based flow measurement technology for simultaneously measuring volumetric flow rate and process fluid sound speed is described. The technology utilizes sonar array processing techniques to perform two independent measurements to characterize the process fluid, each well-suited for single and multiphase flows. Firstly, the meter provides mixture volumetric flow by tracking the speed at which naturally occurring flow-generated pressure fields convect past an array of strain-based sensors clamped-on to existing process pipe. Secondly, the meter provides compositional information by measuring the speed at which naturally occurring sound waves propagate through the process fluid using the same clamp-on sensors. Measuring the speed of sound of a process fluid utilizing this sonar technique is analogous to measuring process fluid density and has many compositional based applications. A primary example of this is using process sound speed to accurately measure the amount of entrained gases in liquid-continuous mixtures. The ability to measure volumetric flow and process sound speed reliably and accurately in single and multiphase applications with a non-intrusive, clamp-on device significantly enhances the observability of the many industrial processes. Data is presented from sonar- based volumetric flow and sound speed-based compositional measurements for a wide range of industrial applications, encompassing single phase liquid applications to large diameter, abrasive multiphase applications, widely-recognized as difficult, long-standing flow measurement challenges. 2 INTRODUCTION Volumetric flow is a critical measurement in process control and optimization for most industrial processes. The current industrial flow meter market is often classified into two technology-based categories: old technology and new technology. Old technology flow meters include flow measurement technologies that have been in use for more than 70 years, It includes turbine meters, orifice plates and variable area flow meters. The new technology flow meters include technologies which have emerged over the last 3050 years. These new technologies typically offer advantages over the old technologies in performance, functionality, and reliability. The major types of new technology flow meters include ultrasonic meters, electromagnetic flow meters, vortex flow meters, and Coriolis flow meters. Each type has evolved to serve various aspects of the diverse range of applications within the industrial flow meter landscape. This paper describes sonar-based flow meter technology which utilizes sonar techniques' to listen to, and interpret, pressure fields generated by turbulent pipe flows. Sonar flow measurement technology represents a new class of industrial flow meters utilizing measurement principles distinct from existing technologies. Sonar flow meters were first introduced into the oil and gas industry in 1998 for use in downhole multiphase flow metering applications2 3. Sonar flow measurement technology is currently being used in other industries such as pulp and paper, mining and minerals, hydro transport, chemicals and power generation. Process aeration is often an unwanted but unavoidable phenomenon that negatively impacts product quality or the ability to accurately determine the rate of flow. For instance, entrained air in the thin stock flow to the headbox of a paper machine may lead to pin holes in the BI0197 RevB Flomeko 2005 6 - 9 June 2005 • produced paper or worse still to a web break resulting in production loss. Entrained air in the paper and pulp industry is such a pervasive problem4 that both mechanical and chemical means are used to remove air from the process. Likewise in production of crude oil, gas carry under in the liquid outlet of a twophase separator impairs the measurement of the rate of net oil flow as the watercut meter is affected by the presence of free gas. It is well known that the resulting errors in the net oil rate can easily be 100% or more solely because of a small error in the watercut. Just as often, however, process aeration is an integral part of the production process and the air or gas content must be kept within certain limits. By way of example, the injection of a small amount of air in the hydrotransport pipe lines in oil sand processing initiates the separation of oil from sand. Likewise in the separation of rock from minerals in flotation cells, gas is sparged in at the bottom of the cell and the gas holdup in the cells must be controlled to optimize the gravity separation of rock from mineral. The sonar techniques that enable the interpretation of the naturally occurring pressure fields inside a pipe are also well suited to determine the velocity of propagation of acoustic pressure fields. The velocity of sound thus determined is a very sensitive indicator of process aeration and it offers a superior alternative to today's mechanical, sample taking analyzers. The methodology involves characterizing the speed at which coherent pressure waves, either vortical structures or acoustic pressure fields, convect past an axial array of sensors using beam-forming techniques developed over several decades for underwater acoustic applications. Since coherent vortical structures are an inherent feature of turbulent boundary layers, no internal geometry is required to generate these structures. Likewise, in the majority of industrial processes the proximity of pumps, compressors, valves or sharp bends ensures that no source of sound is required. The sonar-based measurement is therefore entirely passive and it can be performed using an array of strain based sensors mounted on the outside of the pipe. With no process-wetted hardware, the sonar flow measurement technology is well suited for the corrosive and abrasive slurries commonly encountered in many practical applications. 3 FLOW RATE MEASUREMENT The overwhelming majority of industrial process flows involve turbulent flow. Turbulent fluctuations within the process flow govern many of the flow properties of practical interest including the pressure drop, heat transfer and mixing. For these reasons, turbulent pipe flows have been extensively studied over the years with roots back to Osbourne Reynolds and Lord Rayleigh in the late nineteenth century5. 3.1 Turbulent pipe flow For engineering applications, considering only the time averaged properties of turbulent flows is often sufficient for design purposes. For sonar flow metering technology, understanding the time averaged velocity profile in turbulent flow provides a means to interpret the relationship between speed at which coherent structures convect and the volumetrically averaged flow rate within a pipe. For turbulent - flows, the time-averaged axial velocity varies with radial position, '~g from zero the wall to a maximum at ' ~ ~ ~ the centerline of the pipe. The flow 1 v_* coK~~~wi nos~~cri a~awcsa~sES~ TM, near the wall is characterized by ~ :: - steep velocity gradients and _ ~~ ~.~ ~,, transitions to relatively uniform core `. ;` ~' ,x~ ~ ~ flow near the center of the pipe. '~ -~ ~~~ ~ ` ~ Figure 1 shows a representative ~ schematic of a velocity profile and i 3 ,F,...,H.~Ky~ coherent vortical flow structures Figure 1: Coherent structures in turbulent pipe flows. present in fully developed turbulent pipe flow. BI0197 RevB Flomeko 2005 6 - 9 June 2005 The vortical structures are superimposed over time averaged velocity profile within the pipe and contain temporally and spatially random fluctuations with magnitudes typically less than 10% percent of the mean flow velocity. The Reynolds number (Re), based on pipe diameter (D), characterizes many of the engineering properties of the flow. The Reynolds number is a non-dimensional ratio representing the relative importance of inertial forces to viscous forces within a flow: Pipe flows with Reynolds numbers exceeding a critical value, typically 2300, are turbulent. Those with Reynolds numbers below this value are laminar. The vast majority of flows in industrial processes is turbulent with Reynolds numbers far in excess of the critical value. In addition to demarcating a boundary between laminar and turbulent flow regimes, the Reynolds number is a similarity parameter for pipe flows, i.e. flows in geometrically similar pipes, scaled with radius, with the same Reynolds number are dynamically similars .Empirical studies have shown that velocity profiles in turbulent pipe flows are well represented by the 1 over nth power law: ~~ =~1-R~ (1), 0 90% 85% 0 80% 75% 70% with n ranging from 6 to 10 as a weak function of Reynolds number. From a measurement perspective, the volumetrically averaged flow velocity V (mean velocity) or the volume rate of flow divided by the pipe's internal cross- sectional area is of interest. The relation between the ratio V/Uo and the Reynolds number is shown in Figure 2, which is based upon the power law (1). Apparently the ratio of the mean flow velocity to the maximum velocity slightly increases from a little below 80% just above the critical Reynolds number for turbulent flow to greater than 85% at Reynolds numbers over one million. It must be stressed that, given the velocity profile (1), very little fluid is actually flowing at the mean flow velocity. 1. E+03 1. E+04 1. E+05 1. E+06 1. E+07 Reynolds number Figure 2: Mean velocity normalized by Maximum velocity vs. Reynolds number. 3.2 Coherent turbulent structures Turbulent pipes flows are highly complex flows. Predicting the details of any turbulent flow is one of nature's great-unsolved problems. However, much is known regarding the statistical properties of the flow. For instance, turbulent pipe flows contain self-generating, coherent vortical structures often termed "turbulent eddies". The maximum length scale of these eddies is scales with the diameter of the pipe. These structures remain coherent for several pipe diameters downstream, eventually breaking down into progressively smaller eddies until the energy is dissipated by viscous effects. Experimental investigations have established that eddies generated within turbulent boundary layers convect at roughly 80% of maximum flow velocity. For pipe flows, this implies that turbulent eddies will convect at approximately the volumetrically averaged flow velocity within the pipe. The precise relationship between the convective velocity of turbulent eddies and the flow rate for each class of meters can be calibrated empirically as described below. 3.3 Characterizing the unsteady pressure field The sonar flow metering methodology uses the convection velocity of coherent structure with turbulent pipe flows to determine the volumetric flow rate. The convection velocity of these eddies is determined by applying sonar arraying processing techniques to determine the speed at which eddies convect past an axial array of dynamic strain measurements BI0197 RevB 3 Flomeko 2005 • 6 - 9 June 2005 distributed along the pipe outer circumference. The sonar-based algorithms determine the speed of eddies by characterizing both the temporal and spatial frequency characteristics of the flow field. For a train of coherent eddies convecting past a fixed array of sensors, the temporal and spatial frequency content of pressure fluctuations are related through the following relationship: w = kv (2). Here is the wave number, defined as k=2n/I~ (1/m), w is the temporal frequency (rad/s) and v is the convective velocity of the unsteady pressure fluctuations. Thus, the shorter the wavelength is the larger k and the higher the temporal frequency. ~ In sonar array processing, the spatial - temporal frequency content of time stationary sound fields are often .~ displayed using "k-w plots". k-w plots _ are essentially two dimensional ~ power spectra in which the power of ~ a pressure field is decomposed into ,. bins corresponding to specific spatial wave numbers and temporal ~ frequencies. On a k-w plot, the power associated with a pressure field _~ convecting with the flow is distributed w.~e.~nm~ in regions which satisfy the dispersion relationship developed Figure 3: k-w plot showing convective ridge above. This region is termed the "convective" ridge and the slope of this ridge on a k-w plot indicates the convective velocity of the pressure field. This suggests that the convective velocity of turbulent eddies, and hence flow rate within a pipe, can be determined by constructing a k-w plot from the output of a phased array of sensors and identifying the slope of the convective ridge. Figure 3 shows an example of a k-w plot generated from a phased array of transducers listening to a 16 inch pipe flowing water at approximately 350 I/s. The power contours show a well-defined convective ridge. A parametric optimization method was used to determine the "best" line representing the slope of the ridge. For this case, a slope of 3.2 m/s was determined. The intermediate result of the optimization procedure is displayed in the insert, showing that optimized value is unique and constitutes of one well-defined maximum. 3.4 Sonar flow meter calibration The k-w plot shown in Figure 3 illustrates the fundamental principle behind sonar based flow measurements, namely that axial arrays of transducers can be used in conjunction with sonar processing techniques to determine the speed at which naturally occurring turbulent eddies convect within a pipe. The next issue is to quantify the relationship between speed of the turbulent eddies and the volumetrically averaged flow rate within the pipe. To quantitatively evaluate this relationship, a number of geometrically similar sonar flow meters with diameters between 4 and 16 inch were tested with water at a flow meter calibration facility for flows ranging from 1.5 to 1500 I/s. The convection velocity determined using the sonar-based techniques, normalized by the volumetrically averaged flow rate supplied by the calibration facility as a function of Reynolds number ranged between 99% and 102% of the volumetrically averaged flow rate over the entire range of the test. Alow-order Reynolds number based calibration, was developed from this data for this class of meters. The calibration equation is developed in terms of the relative offset of the sonar based meter from the reference meter. The relative offset O is, in terms of the Reynolds number Re and a set of three coefficients C~, CZ and C3, unique to each sonar meter size given by (3). O=C,+ Cc Re 3 (3). BI0197 RevB Flomeko 2005 • 6 - 9 June 2005 . Figure 4 shows the relative difference of the volumetric flow rate measured by the calibrated sonar meters and the reference flow plotted versus reference flow. Calibration data was recorded for the sonar flow meters with volumetrically averaged flow velocities ranging from 1-10 m/s. Using a single Reynolds number calibration (4) spanning the operating range of the three flow meters of different physical sizes, the sonar meter measured the volumetric flow rate to within 0 5°/ - ~,-O.Sk Pr o~ctio nSONAR bac FlowMe[erDafa --- -~%c~rue~~ve~=oazs~ ^ SND60830085-109 Sch tO T tOD 62 ^ ^ SND60830088-111 Sch 10 T5D B2 SND60830085-175 Sch 10 T 10D B2 ^ SND60830088-116 Sch 10 T 5D B2 ^ SND60830085-117 Sch 10 T 10D B2 ^ SND60830085-118 Sch 10 T 5D B2 ® SNO60B30085-109 Sch 10 T 10D Bt ^ SNO60B30088-111 Sch 10T5D 81 o • ^^ o ~ ® • ' ' ~ • ^ ~ 0 0 . ° accuracy. It is important to note that this flow metering approach has no fundamental size limitations and should be applicable to turbulent pipe flows of all diameters and Reynolds numbers. Furthermore, similarity laws suggest, and data from Figure 4 support, that the relationship between convection velocity and flow rate from geometrically similar meters of any size is be governed by same Figure 4: Calibration data. Reynolds number based calibration. It can be concluded from the data presented that the 95% confidence level of the sonar based flow measurement equals 0.42%. 3.5 Industrial applications Numerous industrial applications for the sonar based flow measurement have been developed in close co-operation with end users over a period of more than 2 years. The industrial applications are to be found were the clamp on, non intrusive, large bore capability of the sonar based principle results in undisputed advantages in terms of life cycle cost, reliability or the sheer impossibility to make any other measurement device work. Examples of such are: • Hydro transport of oil sand8. • Thick stock flow in paper and pulps. • Air conveyed transport of particulate material. • Two phase flow of water and oi110 " • Sewer water processing. • Flow of coating pastes. • Magnetite flow in minerals processing. All of the above examples of industrial flows are characterized by their abrasive and/or corrosive nature. In many cases this necessitates the use of special pipe materials or the use of lined (Teflon, rubber, concrete) pipe. The phenomenon of pressure fluctuation induced circumferential pipe strain is universal and independent of the precise nature of the pipe material or lining. As a result a sonar based measurement can, in most cases, be applied without a process shut-down, without cutting the pipe and without elaborate operational procedures or safety measures. In selected cases the operating principle of the sonar based meter removes a calibration difficulty inherent in the traditional measurement principle. For instance, in the flow rate measurement of magnetite suspensions by electromagnetic flow meters the ferro magnetic nature of the suspended particulates affects the meter's calibration. As a result the meter may drift with magnetite concentration. Figure 5 shows two frequency distributions of the relative difference between a sonar based and electromagnetic flow rate measurement for both high (1.70 kg/dm3) and low (1.65 kg/dm3) density magnetite suspensions in the feed flow to a BI0197 RevB 5 Flomeko 2005 • 30000 24000 18000 ~ 3 O V 12000 sooo 6 - 9 June 2005 • 100°/ 10000 80% 8000 60% ~.. 8000 C 7 O 40% V 4000 zo°io zooo 0% n Figure 5: Frequency distribution of the relative offset of sonar versus mag meter. 100% 80% d 80% w R 7 40% ~ U zo°io 0% series of reverse flotation cells. As in this specific example neither meter was "nulled" relative to the other, either the high density histogram or the low density histogram may be used as a reference for the other. It follows that the difference between the two meters, sonar and an electromagnetic, has shifted by about 5% with the change in the magnetite concentration. This is believed to be due to the fact that the calibration of the electromagnetic flowmeter is dependent on the actual concentration of magnetite in the flow. A flow meter that is not affected by the detailed make up of the fluids flowing and any particulates therein is a very clear advantage. It is to be noted that in other comparable cases, where non magnetic particulate material is suspended in the flow, the difference between sonar and an electromagnetic flow meter is not affected by the density. 4 MEASUREMENT OF GAS CONTENT Using a similar, and in many cases the same, hardware platform it is also possible to measure the velocity of sound of acoustic waves propagating in the process piping. The propagation of acoustic waves occurs at frequencies much above the frequency domain of vortical pressure fluctuations, therefore the same sonar processing can be applied to determine both the acoustical velocity and the voritical velocity at the same time. The relation between speed of sound in twophase mixture and the volumetric phase fraction is well known in case the wavelength of sound is larger than the pipe diameter and hence also significantly larger than any process in homogeneities such as bubbles. 4.1 Velocity of sound in liquid/gas mixtures The mixing rule12, known as Wood's equationl3, expresses the fact that in a mixture the compressibility of the mixture equals the volumetrically averaged compressibility of the pure components. For the mixture density a similar rule holds: the mixture density equals the volumetric average of the pure component densities. Because the velocity of sound in a fluid equals the square root of the compressibility over the density, the two mixing rules can be written as: 1 _ tp 1-~p P~~ Pg~g Pr~i (4). Here, N is the volume fraction of gas at line conditions, c is the speed of sound, p the density and the subscripts g and I refer to the gas and liquid phase respectively. Figure 6 illustrates the relation between mixture sound speed and gas content for an air water mixture. In most industrial processes, at moderate temperature and pressure line conditions, the compressibility of the gas phase is orders of magnitude larger than the compressibility of the liquid phase. Inversely, the density is dominated by the liquid density. As such, it will be necessary to measure the process pressure (when varying) as both the gas density and the BI0197 RevB 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% Flomeko 2005 • 6 - 9 June 2005 • liquid density are significant when determining the gas volume fraction from the mixture sound speed. Conversely, neither the velocity of sound in the liquid nor the velocity of sound of the gas is a significant factor for mixtures where one phase is gaseous. In fact, the denominator of the first term in the Wood's equation equals the product of process pressure and polytropic exponent of the gas demonstrating that the gas content at line conditions can be determined using the velocity of sound independent of the gas molecular weight or the gas temperature. Hence, the determination of the gas content using mixture speed of sound is independent of the gas type 1000 and will be accurate E a~i ~ 100 0 x 10 \; \ -----.~ vai ~ • 4 bar _..__ _~ .~_ _ -.__ '--_-__ _ 5bar 0% 5% 10% 15% 20% Gas volume fraction Figure 6: Mixture sound speed vs. gas volume fraction. (4). The distensibility for thin walled, untethered pipe is given by: D _ 2R Et irrespective of the type of gas, which can be either air, carbon- dioxide, hydrogen or any mixture thereof. For mixtures confined to a pipe, a correction to above formulae (4) is necessary in order to account for the relative change of pipe cross sectional area upon internal pressure variation. This so called distensibility'a D, is an additive term to the first equation of (5), where R is the pipe's internal radius, t is the wall thickness and E the pipe materials' Young modulus. In steel pipe, the distensibility is quite small because of the large value of the Young modulus of steel. In aluminum, glass or even plastic pipe, however, the distensibility must be accounted for. The effect of the pipe distensibility is lower the apparent, measured speed of sound. For instance in a water filled 4" plastic pipe with a wall thickness of 5.5 mm and a modulus of 3.5 GPa, the measured speed of sound will be 420 m/s at zero aeration. This is a striking difference with the free space velocity of sound in water of 1480 m/s. 4.2 Measurement of the velocity of sound As described above, the relationship between mixture sound speed and entrained air in bubbly liquids is well established. However, as will be developed below, in bubbly flows, these relations are only applicable for the propagation of relatively low frequency, long wavelength sound. While this restriction does not present any significant obstacles for the sonar meter, it does present significant challenges to ultrasonic sound speed measurement devices. Ultrasonic meters typically operate in 100 kHz to several MHz frequency range. For these meters, entrained air bubbles have length scales on the same order as the acoustic waves generated by the ultrasonic meters. This poses several problems for ultrasonic measuring devices. Firstly, the bubbles scatter the ultrasonic waves, impairing the ability of the ultrasonic meter to perform a sound speed measurement. Secondly, ultrasonic meters rely on information derived from only a small fraction of the cross sectional area of the pipe to be representative of the entire cross section, an assumption that breaks down for flows with non- uniform distributions of in homogeneities, such as stratification of entrained air towards the top of process lines. BI0197 RevB 7 Flomeko 2005 • 6 - 9 June 2005 • Sonar flow meters use an approach developed and commercialized specifically for multiphase flow measurement in the oil and gas industry in which multiphase challenges described above are routinely encountered. Sonar meters measure the propagation velocity of operationally generated sound in the 100 to 1000 Hz frequency range. In this frequency range, sound propagates as aone-dimensional wave, using the process pipe as awave-guide. The wavelength of sound in this frequency range (>1 m) is typically several orders of magnitude larger than the length scale of the any bubbles or flow non-uniformities. The long wavelength acoustics propagate through multiphase mixtures unimpeded, providing a robust and representative measure of the volumetrically averaged properties of the flow. For the sound speed measurement, the sonar flow meter utilizes similar processing algorithms as those employed for the volumetric flow measurement. As with convective disturbances, the temporal and spatial frequency content of sound propagating within the process piping is related through a dispersion relationship. w=kc (6). As before, k is the wave number, defined as k=2n/~, (1/m), w is the temporal frequency (rad/s), and c is the speed at which sound propagates within the process piping. Unlike disturbances which convect with the flow, however, sound generally propagates in both directions, with and against the mean flow. For these cases, the acoustic power is located along two acoustic ridges, one for the sound traveling with the flow at a speed of c + V and one for the sound traveling against the flow at a speed of c - V. N Figure 7: k-w plot for 3% entrained air in water. ~ Figure 7 shows a k- w plot generated for acoustic sound field recorded from still water containing -3% entrained air by volume in an -~ 8 in, schedule 80, vertically oriented Plexiglas pipe. The k-w plot was constructed using data ~ from an array of strain based sensors clamped to the outside of the pipe. Two acoustic ridges are clearly evident. Based on the ~ slopes of the acoustic ridges, the measured sound speed for this for this mixture was 70 m/s, consistent ~ with that predicted by the Wood equation. Note that adding 3% air by volume reduces the sound speed of the bubbly mixture to less than 10% of the sound speed of liquid only water. 4.3 Industrial applications As was mentioned in the introduction, there are two applications of the full bore measurement of entrained gas of distinctly different character. First there are those where process aeration must be controlled or where process aeration must be avoided altogether. Examples of such are: • Natural froth lubricity flows. • Gas sparging in flotation cells. • Dissolving carbon dioxide in beverages. • Entrained air in the thin stock flow to a paper machine's headbox15. • Entrained air in filling stations for domestic household products. Second there are applications where entrained gases negatively affect the process indirectly by affecting other types of meters. Examples of this second kind are: BI0197 RevB wav«wm6« (1 ~) Flomeko 2005 6 - 9 June 2005 • Errors in consistency measurement of paper stock.16 • Errors in the determination of net oil using watercut meters". • Errors in Coriolis determined volume flow as a result of product aeration's. • Errors in custody transfer metering resulting from product flashing or aeration. The sonar based measurement of process aeration using the velocity of sound covers almost 5 orders of magnitude, from 0.01 % to above 20%, and is therefore universally applicable to a wide variation of process conditions. By way of example Figure 8 gives the amount of ~ entrained air in a volume of paper 0 6 ~~.. ~ 5 0 L 4 LL d E 3 0 > 2 y ~ 1 0 stock just before and just after the dosing of a commercially available defoamer chemical. Given the continuous character of the measurement and given the fact that this full bore measurement is, unlike a sampling system, representative of the true air content the ability to control defoamer dosing presents itself. Such dosing control will not only help reduce defoamer volume it -~20 -so o so ~2o will also help reduce process Time [s] variability. Thus product quality is positively impacted whilst at the Figure 8: Defoamer dosing application same time cost is reduced. Conversely, in applications where the amount of air or gas in a process must be kept at a stable level in presence of gas consumption by chemical reaction, this sonar based measurement can provide hitherto unavailable compositional information even on large diameter reactor vessels.. Just reversing the time scale in Figure 8 is sufficient proof of this claim. 5 CONCLUSIONS Sonar based flow monitoring enables the direct measurement of the convective transport velocity of turbulent eddies in pipe flow and it enables the direct measurement of the velocity of sound propagating through the pipe. Both measurements can be made using an array of strain based sensors clamped to the outside of the process piping. Evidence is presented to prove that the convective transport velocity of turbulent eddies is proportional the volumetrically averaged mean velocity. A Reynolds number based, empirical calibration is given which yields 0.5% accuracy for Newtonian fluids. Thus, a novel technique based upon naturally occurring phenomena in pipe flow allows the realization of a calibrated flow meter. Industrial applications of the sonar based flow meter in abrasive and corrosive fluids are discussed. An example in magnetite flows is given where the passive nature of the sonar based instrument proved to be a distinct advantage. It is shown how the velocity of sound in a twophase medium can be used to derive compositional information such as gas volume fraction. The necessary correction for the effect of the enclosing pipe is developed. The effect of fluid and gas properties on the calculated gas content is discussed. Neither the temperature nor the gas' molecular weight has any influence, only the liquid density and the process pressure must be known. An industrial application of the gas volume fraction measurement is presented. This defoamer dosing example is one of many which have been found. BI0197 RevB Flomeko 2005 • 6 - 9 June 2005 • 6 ACKNOWLEDGEMENTS The results presented in this work have benefits from several years of collaborative efforts to develop sonar-based flow measurement. The authors gratefully appreciate the efforts of the many colleagues and co-workers that have contributed to results presented herein. 7 REFERENCES 1 NIELSEN, R.O., Sonar signal processing, Artech House Inc, Norwood, MA, 2001, ISBN 0-89006- 453-9 2 KRAGAS, T. K., et al., " Downhole, Fiber Optic Multiphase Flow Meter: Field Installation" Presented at the Society of Petroleum Engineers Annual Conference, SPE Paper #77654, September, 2002. 3 KRAGAS, T. K., et al., "Downhole Fiber-Optic Multiphase Flowmeter: Design, Operating Principle, and Testing," Presented at Society of Petroleum Engineers Annual Conference, SPE Paper #77655, September, 2002. 4 MATULA, J. P. and KUKKAMAKI, E, "New findings of entrained air and dissolved gases in pm wet end: mill case study," TAPPI JOURNAL, Apri12000, Vol. 83 5 LANDAU M.T., MOLLO-CHRISTENSEN, E., Turbulence and Random Processes in Fluid Mechanics, 2nd Edition, Cambridge University Press, Cambridge, UK, ISBN 0-521-42213-2, 1992. 6 SCHLICHTING, H., Boundary Layer Theory, McGraw-Hill, New York, ISBN 0-07-055334-3, 1979 7 BERANEK, L.L., VER, LS.," Noise and Vibration Control Engineering," Section 14.6, John Wiley and Sons, New York, ISBN 0-471-61751-2, 1992 8 GYSLING, D.L., MUELLER, E., Application of sonar based, clamp on flow meter in oil sand processing, ISA 2004 Exhibit and Conference, Edmonton section, Apri12004. 9 GYSLING, D.L., LOOSE, D.H., Sonar based volumetric flow meter for pulp and paper applications, CiDRA Corporation, Wallingford, CT, 2003, unpublished work. 10 GYSLING, D.L., VAN DER SPEK, A.M., Fiber optic downhole multiphase flow meter: flow loop evaluation for oil/water mixtures, Downhole Instrumentation seminar, North Sea Flow Metering Workshop, Glasgow, Scotland, 23 October 2000. 11 GYSLING, D.L., VANDEWEIJER, T., VAN DER SPEK, A.M., Development of a permanent downhole twophase flow meter, SRI multiphase metering and pumping conference, Houston TX, February 2000 12 MC WILLIAM, D. DUGGINS, R.K., Speed of sound in bubbly liquids, Proc Instn Mech Engrs, Vol 184, Part 3C, 1969-1970. 13 WOOD, A., A textbook of sound, New York, NY, 1st edition, 1930 14 LIGHTHILL, J., Waves in Fluids, Cambridge University Press, Cambridge, 1980, ISBN 0-521- 29233-6 15 GYSLING, D.L., LOOSE, D.H., Sonar based volumetric flow and entrained air measurement for pulp and paper applications, TAPPI Spring Technical Conference, paper 58-1, Chicago, IL, May 2003. 16 STOOR, T., AMMALA, A. NIINIMAKI, J., Measurement of air content of pulp suspension -sonar method, APPITA 2005 pulp and paper conference, Auckland 16 - 19 May 2005. 17 GYSLING, D.L, LOOSE, D.H., Using sonar bsed gas volume fraction meter for improved net oil rate measurement, Canadian School of Hydrocarbon Management, Toronto, 2005. 18 GYSLING, D.L., BANACH, T. Accurate liquid phase density measurement of aerated liquids using speed of sound augmented Coriolis meters, ISA, Houston, October 2004. BI0197 RevB l0 SPE 100893 New Class of Meter Solves Old Problem Impacting Well Test Accuracy E.R. Ward, SPE, BP Exploration (Alaska) Inc. Copyright 2006, Soaety of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE Western Regional/AAPG Pacific Section/GSA Cordilleran Section Joint Meeting held in Anchorage, Alaska, U.S.A., 8-10 May 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may no! be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax Ot-972-952-9435. Abstract For the first time in a BP-operated asset, the impact of entrained free gas (not solution gas) in the liquid outlet line of a well test separator is quantified for the purpose of correcting gross fluid volumes and density measurement. This paper describes the results of deploying a sonar based, clamp-on gas void fraction (GVF) meter at a test facility in the Prudhoe Bay Unit (PBU) on Alaska's North Slope. Introduction The PBU has been in production since 1977. Over the life of the field several different Test Separator configurations have been utilized. Approximately 16 years ago, PBU started to use the density water cut method on 2-Phase Mini Test Separators to overcome problems that were encountered on the conventional 3-Phase Units. In general these units operated successfully; success was measured by repeatable water cut results that enabled the petroleum engineers to improve management of the wells and have more confidence in production changes as a result of well workovers. Cold viscous crude oil has now been introduced into the PBU production facilities increasing the range of the oil API gravity from 22 to 32 API now down to 17 API. This brought a whole new set of problems. As part of this project two new mini 2- Phase Test Separators were installed. A review of the liquid leg densities of the units handling viscous oil indicated the possibility of free gas with a resultant gas void fraction (GVF). This particular test facility employs a Coriolis meter to measure density and gross flow rate of the oil/water mixture. It was confirmed that discrepancies in allocation factors and individual net oil measurements, especially for cold high viscous crude oil, was due in part to unrecognized gas carry- under in the liquid outlet. Measured GVF associated with wells flowing `non-viscous' oil, the less viscous crude (22 to 32 API) ranged from 0 - 2.0 %, whereas the GVF of wells flowing viscous crude (17 to 22 API) was between 0 - 8% at normal vessel liquid levels increasing to >20% at reduced separator levels. The additional secondary phase measurement enables PBU to now report real time corrected densities and volumes using an in-house method to calculate water cut. In addition to viscous crude, we believe that application of this technology to smaller, somewhat under-sized separators with less stable operations will provide value across the industry. Well testing importance is increasing on the maturing fields of the North Slope of Alaska as it is not only used for the critical function of field management that ensures optimum production from a field; it also is a regulatory requirement set by the State of Alaska and may be used for Production Volume Accounting on fields with co-mingled production facilities. This paper is a brief report of the findings of a preliminary test and a more extensive pilot project of a strap-on sonar based GVF meter on both `non-viscous' crude oil and satellite field viscous oil. The preliminary test was a quick check to determine if the GVF meter could measure a meaningful GVF on the two crudes. With a favorable result to the preliminary test the pilot project was instigated and the unit was installed and fully integrated into the well testing system. Since being installed in October 2005, the unit has been used for on-line well testing. The objective was not only accurate GVF measurement to improve water cut and gross fluid volume accuracy but also to check for long term stability. A stable Zero GVF measurement is a critical issue especially when the unit is used for all types of crude oil and on many wells having little to no GVF. To quantify the impact of GVF on the Test Separator operations in PBU, a 1 %GVF equates to an understatement of water cut (WC) by 5% and a direct 1 % over statement of gross fluid flow. As the title of this paper indicates this meter provides a solution to a long standing problem. This is the final piece of a puzzle that has taken many years to solve. In order to have a better understanding of how our approach has developed the first few sections of this paper will provide a brief overview of ~ • SPE 100893 the PBU and a history of Well Testing, Oil Allocation and Test Separator improvements in the PBU. Overview of Greater Prudhoe Bay (GPB) GPB is a Production Unit of several oil fields (formations). The Initial Participating Area (IPA) within PBU is by far the largest and has been the main driving force in the development of the Test Separator Systems described in this paper. The most recent business need has been the introduction of small satellite fields to the IPA facilities and the problems of cold viscous oil. The PBU was from concept split into two operating areas by the owners with the agreement of the State of Alaska; the Western Operating Area (WOA) operated by BP and the Eastern Operating Area (EOA) operated by Atlantic Richfield Company (ARCO). In addition there was a different ownership split between the Gas Cap and the Oil Rim Participating Areas. After the BP/ARCO merger, BP is now the sole Operator of PBU and the field has been unitized with aligned working interest ownerships in Gas Cap and Oil Rim Participating Areas. The Test Separator operations described in this paper are from the WOA. Impacts of Well Testing As with all oil and gas fields, PBU well testing is used for field management. A very critical function used to optimize production rates and total hydrocarbon recovery from the field. With the early ownership differences between the Gas Cap and the Oil Rim, well testing was critical in the determination of the Gas Oil Ratio (GOR), one of the parameters used to select a well for inclusion in the Gas Cap or Oil Rim. As gas production increased beyond the agreed associated gas volume (determined at a 1000 GOR) the importance of well testing in this area reduced and the gas condensate allocation was then by an agreed liquid volume factor in the gas and simply determined by measuring the overall gas volume. The introduction of satellite field production into the IPA Processing Facilities created the problem of production allocation to the correct field. There was a different tax / royalty regime for IPA and the PBU satellite fields. By prior agreement with the State of Alaska well allocation was the selected method for individual field production. The overall volume of crude oil was measured to custody transfer standards; allocation and well testing determines the production split between the IPA and the individual satellite fields. This obviously increased the importance of well testing and PBU in collaboration with the State of Alaska undertook a major program to upgrade and improve oil allocation and well testing operations. With the merger of ARCO and BP the PBU Gas Cap -Oil Rim ownership difference has been eliminated. Also the State of Alaska has recently equalized the taxation rate for all oil produced through the PBU facilities. Well testing is again mainly for field management but more importantly for regulatory purposes to prove the field is being operated and managed in a prudent manner and to maximize overall fluid recovery. Oil Allocation Methodology As the PBU evolved over time, so has the Oil Allocation Process changed to meet the new challenges. WOA has three production facilities known as Gathering Centers (GC) where oil, gas and water are separated, the gas is dehydrated before shipment to the Gas Plants and re-injection into the field. The EOA also has three production facilities known as Flow Stations (FS). Oil is shipped to Pump Station 1 (PS 1) of the Trans Alaska Pipeline System (TAPS) for metering to custody transfer standards. Alyeska Pipeline Service Company (ALPS), the company operating TAPS, operated two metering systems, one each for EOA and WOA. As production has declined ALPS reduced metering to one combined meter set for EOA and WOA. Also GC 3 passes partially processed oil to FS 3 so only five production facilities are now producing directly to TAPS. All of these changes have had an impact on the allocation process. The following simplistic statistical model demonstrates the impact of metering accuracy on the allocation process. Taking the WOA as a model there are three levels at which oil metering is made; Fiscally at PS 1, Production Metering at the outlet of the GC and individual well production (Well Testing). In order to measure a total volume of 300 MBPD to an accuracy of 1% the choice is to either measure with one 300 MBPD meter with an accuracy of 1%, or three 100 MBPD meters with an accuracy of 1.75% or three hundred 1 MBPD meters with an accuracy of 17%. The WOA has gone from initial allocating process of allocating from PS 1 to the GCs and then to the associated wells to allocating directly from PS 1 to the all wells and back to the intermediate GC step process. The reason for the reversal was that the number of wells had grown significantly and inaccurate testing was being hidden. The wells needed to split up in to smaller groups so as to determine the problem areas. Brief History of Test Separators The following describes the fixed in place Test Separators. If at any time these units were having operational problems Portable Separators were utilized to ensure the required well testing was performed and the overall allocation process was accurately maintained. The initial test separators were Test Banks (3 Stages of Separation) in the GCs. This ensured the oil volume measurement was of sales quality crude corrected to Stock Tank Barrels (STB). As the field developed Test Separators were installed at the Well Pads operating at elevated pressures. This introduced the problem of "Oil Shrinkage", the change in volume of live crude at test separator conditions to STB. SPE 100893 ~ ~ 3 To overcome this problem PBU carried out a large project of correlating test results from the Well Pad Separators to the same well tested in the Test Bank. From this large data base an algorithm were developed that provided two factors, Oil Shrinkage and Solution Gas (SCF per unit volume) to be applied to the Test Separator results. Recently PBU updated this data base utilizing a customized equation of state to improve the accuracy of these factors. The initial Well Pad Test Separators were large 150 Barrel 3-Phase units. Turbine meters were used for oil, water and gas. Master Water and Oil Meters were installed to check the accuracy of the on-line meters. A capacitance probe was installed in the oil leg to detect the water cut up to 20%. In general these systems worked well but problems started to appear when the water cut and GOR started to increase. This was especially true when PBU came off the production plateau. Several improvements were made including replacing the liquid turbine meters with vortex units and modifying internals of the separators. The significant problem with the capacitance probe system was that it could only be customized on a per well pad basis and individual wells on the same well pad were exhibiting significant different physical properties which impacted the water cut accuracy. PBU had installed three mini (40 Barrel) 3-Phase Test Separators that were experiencing significant problems. The results made any field management of the wells in that area very difficult. In 1989 PBU decided to install a direct mass flow meter using the density water cut method on the liquid leg of the separator which was converted to a 2-Phase unit. This method proved so successful that it was installed on eight of the 3-Phase Units. In addition the three GC Test Bank Separators have been reduced to a single stage unit using the density water cut method. The two new satellite field Mini (30 Barrel) 2-Phase Separators are all based on this method. These units did have a microwave water cut meter installed in the liquid leg, but they have never been used on-line. Water Cut Calibration Methods for Density Based Water Cut Measurement All water cut analyzers need to be customized to specific well fluids. This may even be on a per well basis. The proprietary system installed required a `pseudo' oil density that would be temperature compensated using API Volume Correction Tables to give the oil density at line conditions. The first calibration method implemented simply fixed the water density and adjusted the oil density until the water cut matched spinout tests of the crude oil for each well. This was later improved by taking live samples to the laboratory where an analyzer measured the oil and water densities at line conditions and the' pseudo' density was calculated. Both methods were satisfactory but required careful co-ordination of the well in the Test Separator during sampling and were very man-hour intensive. With the updating of the eight 3-Phase Test Separators to 2-Phase Units, the addition of the two new 2-Phase Units for the viscous oil and the associated significant increase in well count the existing methods of calibration became virtually impossible to maintain. In addition the laboratory analyzer proved not to be satisfactory and was taken out of service. All of these problems lead to a fundamental reevaluation of the calibration methods and even the density method itself. New Approach to the Water Cut Density Method The following is only a brief outline of the in-house developed method that will assist with understanding the main topic of this paper; GVF measurement and the application to test separators. The basic intent of the method was to reduce sampling requirements while not impacting metering accuracy. The method is based on mass which does not change for pressure and temperature variations or for mixing two fluids together even if they are in different phases. Live crude is just stock tank barrel crude oil with gas in solution. Therefore the density of live crude can be predicted by simply adding the mass of the oil and the mass of the solution gas together. The key to understanding this system is oil shrinkage and solution gas. These parameters are fundamental to well testing at elevated pressures and temperatures. Typically a well test determines the volume of live oil at separator conditions; the oil volume is then shrunk to provide the daily production volume in STB terms. The density of stabilized crude and dry gas can be determined at both base and line conditions (Pressure and Temperature compensated) using API and AGA Standards. The density of water can be determined by well established and internationally accepted algorithms at both line and base conditions. The hydrocarbon (Oil plus Gas) density at line conditions is the sum of the oil line density with oil shrinkage applied plus the mass of solution gas on a per unit basis. The water cut is determined using the standard equation for the mixture of two fluids of known densities from the measurement of the line fluid density of the combined fluids. The unique part of the method is that the actual oil, gas and water volumes at line conditions can be determined. Therefore it is possible to mass balance the liquid leg by comparing this calculated mass to the measured mass flow from the direct mass flow meter. The method adjusts the solution gas in the density model until 100% mass balance is achieved. This has been demonstrated to improve the water cut accuracy. Benefits of the New Approach The oil shrinkage and solution gas factors are based on pressure, temperature and GOR. Therefore the metering on the Test Separator is now fully integrated as the off gas flow impacts the liquid leg measurement for oil and water. More specifically the hydrocarbon fluid density in the liquid leg is fully compensated to all pressure, temperature and GOR conditions. The only parameters to be input to the method are the base specific gravities of dry oil and water. This significantly reduces the sampling complexity as only the well fluids at STB conditions are required and not at the line conditions. • ~ SPE 100893 As the method provides on a real time basis the STB water cut, it can be compared directly to the laboratory determined water cut which is made at 0 PSIG. There is a significant difference between the on-line water cut and the STB water cut especially with oil shrinkages of up to 30%. Problems on the Viscous Oil Test Separators Most of the early problems were associated with the fact the units were open to the Artic environment and meters were not installed in the most advantageous way. These difficulties were slowly overcome and the new density method was installed on the separators. A review of the measured density in the liquid leg of the separators indicated a significant quantity of gas in the liquid leg which had a detrimental impact on both the total fluid volume and the water cut determination. The addition of GVF in the liquid leg means there are three unknowns but the calculation method only provides two equations. The third unknown, GVF had to be quantified for the density method to work. Selection of the GVF Meter BP was performing wet gas meter tests and during a presentation of this test a sonar based strap-on unit was presented that was claimed to measure GVF in the 0-20 range. The unit is passive; it listens to audio frequency noise signals in the fluid and using sonar techniques determines the speed of sound (SOS) of the fluid in the pipe. In this frequency range the wavelengths are several feet, therefore the transducer is measuring the physical properties e.g. free gas that is present a significant volume of the fluid and not just a slice across the pipe. The relationship between the SOS and gas in a liquid (GVF) is very well established and documented. Preliminary Tests It was decided to perform a preliminary test on the liquid leg of a Test Separator that tested both PBU and satellite crude wells. The objective of these very simple tests was to determine if the unit would measure a GVF and whether it would track expected GVF values when the level in the vessel was raised or lowered. Two units were installed; one upstream of the mass meter (horizontal) and a second downstream of the mass meter (vertical down). The intent of the preliminary tests was not only to confirm satisfactory operation of the GVF meter but also to try and select the best position for a more extensive test. The results of two days of trials were very favorable. A GVF was measured in both crudes in the range of 0 - 30%. The GVF measurement performed as expected; it increased in value for a lowering vessel liquid level and decreased in value for an increasing vessel liquid level. Typically both units tracked; however on high GVF values (> 15%) the downstream meter indicated up to twice the upstream unit. This was believed to be a piping issue with gas trapped in an inverted U section of pipe and the flow of fluid was not great enough to sweep the buildup of free gas. See Figures 1 and 2 for the GVF plots of these tests e 0 '~ 0.4 e 0.3 ~' o.z o.~ SI20I20051I:1500 5/20120051722:12 5/20/200517:29:26 5Y10Y10051]:38:38 SI20/200517b3:48 5/20Y200517:5100 Figure 1 -Downstream GVF Meter on a Typical PBU Well (28°API and 98°F) 35 30 ---- ~ ~ ~ Upstream y5 Downstream -O zo LL •°- ° ~ s A ~o 0 5127/2005 6:30 5/27/2005 7:42 5/22/2005 8:54 5/22/2005 70:06 5/22/2005 71:18 5/22/2005 72:30 Figure 2 -Comparison of Upstream and Downstream GVF Meters on a Cold Viscous Well (18°API and 54°F) Extended Pilot Test As a result of the favorable preliminary test it was decided to install a unit into the well testing system and to monitor its performance. The new in-house density approach is programmed into a stand alone flow computer that has fully flexible customer programming capability. The program was updated to include the GVF function in both the density calculation and the gross volume calculation. In addition the free gas was added to the off gas and the free gas was included in the mass balance of the liquid leg. To enable the operation to be monitored closely an extensive data gathering system was also configured into the flow computer and the Supervisory Control and Data Acquisition (SCADA) System. The SCADA System performs the well test function and the following parameters were retrieved in addition to the standard data for well testing. • Gas Void Fraction • On-line Measured Density • GVF Corrected Density • Calculated On-line Hydrocarbon Density • Calculated On-Line Water Density o.~ 0.6 o.s SPE 100893 ~ ~ 5 • Mass Flow • STB Oil Flow • STB Water Flow • On-line GOR • STB GOR • Mass Balance • Solution Gas Correction Factor Data was gathered approximately every 20 seconds. This real time data has enabled PBU for the first time to monitor very closely how the density method operates on a 2- Phase Separator. Review of Preliminary Results of the Pilot Test The water cut methodology is based on fluid densities so tracking how the hydrocarbon and water densities vary on-line and how the measured liquid leg fluid density compares to these densities is critical. For example the GVF values we have witnessed on these tests can take the measured density from less than the hydrocarbon density to higher than the water density. That is from 0% water to 100% water. The test separator is at an unmanned site and the only monitoring is restricted to measured /calculated variables; it was not feasible to bring back the status of the sonar unit. The dilemma is to know when an accurate GVF is being measured. The GVF transmitter was setup to freeze at the last known good answer. The GVF is not expected to be constant; therefore no "plateaus" should be expected on a plot of GVF. Reviewing the GVF transmitter status when this happens reveals two basic reasons; either poor signal quality or invalid speed of sound data. testing cold heavy viscous crude the results presented and discussed in this paper are for a viscous well. The initial tests on one particular well showed little to no GVF but as time progressed tests started to have large GVF swings and plateaus on the GVF data plot. The status of the unit was low signal quality and invalid SOS data. The first reaction was to question whether there was enough noise to enable the meter to function. After all the unit in use had the greatest distance to the liquid control valve, the expected source of the noise. A data "snap shot" was submitted to the manufacturer who stated the signal strength was good but the unit was not able to successfully analyze the SOS data. It was noted that when the wells are tested with the portable separator unit chemicals are injected into the crude, in particular anti-foam. Anti-foam was injected into the well flow-line. Figure 3 shows the response of the GVF Meter and the density water cut methodology to this anti-foam. The plot is for 8 hours with the anti-foam injected at approximately 5 hours into the plot. The well test was for 4 hours and this plot shows the first 3 hours of this test. There was an immediate improvement to the whole system. Parameters no longer had wild variations and the GVF corrected density was now solidly in between the hydrocarbon and water densities and steady. For the well in question the measured on-line density was significantly below the calculated on-line hydrocarbon density. Line Density GV F Cor Density - - - - - FID Cad Density --•----Water Calc Density GVF The downstream unit was selected as the primary meter for the test. Initial results looked promising; however we witnessed excessive swings in the indicated GVF (0 to 20 %+) with the associated large variations in water cut. This was a repeat of the high GVF measured during the preliminary test caused by a buildup of free gas in the inverted U section. The upstream unit was now selected and all tests were made using this unit. The first criterion for success was to determine if the GVF corrected line density lies between the hydrocarbon and the water densities. If this is satisfied the metering methodology will be able mass balance the liquid leg of the separator. The method will not be able to mass balance the liquid leg if this criteria is not met. A Portable Test Separator is used to check well tests especially if the results are questionable. This portable separator is manned on a 24/7 basis and it is customized for each well test. This is considered the best well test we can achieve. Therefore the second criterion was to compare the well test result from the on-line separator to the last test using the portable separator. In general the unit operated satisfactorily on PBU crude. However as the main reason for using the GVF meter was ~ so a_ 58 ~~ 56 c sa sz 50 ae 60 120 180 240 300 360 420 Minutes 20 18 1s 1a 1z 10 8 ~ s Figure 3 -the impact of Anti-Foam on the performance of the GVF Meter on Viscous Crude Oil The following well test result using the fixed separator and the new methodology including the GVF Meter and the standard SCADA well testing system was obtained and compared to the last Portable Test Separator test Portable Se arator Fixed Se arator Oil BPD 366 498 Water BPD 29 42 GOR 1142 1272 Water Cut % 7.3 7.8 Table 1 - Well Test Comparison of Portable to Fixed Test Separator • • SPE 100893 Conclusions The preliminary results of the pilot test to date look very promising; the objectives of the test are being met, i.e. to check the long term stability and performance of the GVF Meter under differing conditions. The presence of free gas in the liquid leg of the mini Test Separator when testing cold viscous wells was postulated; the GVF Meter has provided a quantitative measurement of this free gas. The secondary objective was to try and determine limitations of GVF Meter which we have achieved. When testing viscous wells with water present it is important to inject anti-foam to make the system operate correctly. Please note these wells have gas artificial lift. Only the results of one well are provided here because formal review all the data from all wells needs to be collected before it can be disseminated. Preliminary reviews indicate that a GVF is present in all well testing even on the PBU wells. However three of these GVF Meters will be installed on three mini 2-Phase Test Separators working on viscous and PBU crude oil. Several years of work has gone into perfecting the approach to the density method water cut. The addition of the GVF capability is the last piece of the puzzle to ensure accurate well testing. Acknowledgements I thank the management of BP Exploration (Alaska) Inc., Conoco Phillips Alaska Inc. and Exxon Mobil Corp. for their support and for granting permission to publish this paper. I thank Fred Bakun for all the work he provided in developing the oil shrinkage and solution gas factors that enabled the new approach to density water cut to be developed. Also for all the patient hours we spent in detailed discussion to fine tune the overall density method. I would also like to thank: Richard Volz of E&P Technology Group, BP America Inc for his support of this pilot program which enable BP Corporate to provide funds towards the pilot program and for his encouragement to perform these tests and publish this paper. Michael Bolkovatz, Hal Tucker, Rob Kruger and Bruce Weiler for their support and encouragement as well as their technical insight that was invaluable to assist with solving this problem. Douglas Loose for his valuable support during installation and commissioning of the GVF Meter. His technical assistance with solving the GVF performance problems during the pilot tests proved to be valuable for solving the operational problems. Nomenclature GVF =Gas Void Fraction API =American Petroleum Institute AGA =American Gas Association PBU =Prudhoe Bay Unit (Oil Field on the North Slope) IPA =Initial Participating Areas GPB = Greater Prudhoe Bay (PBU plus Greater Point Macintyre and other satellite fields) WOA =Western Operating Area of the PBU EOA =Eastern Operating Area of the PBU GOR =Gas Oil Ration SCF /Barrel GC =Gathering Center (Production Facilities in the WOA) FS =Flow Station (Production Facilities in the EOA) TAPS = Trans Alaska Pipeline System ALPS = Alyeska Pipeline Service Company. PS 1 =Pump Station 1 of TAPS MBPD =Thousand Barrels per Day STB =Stock Tank Barrels (Base Conditions 0 PSIG & 60°F) SCF =Standard Cubic Feet (Base Conditions 14.65 PSIA & 60°F) PSIG =Pounds per Square Inch Gauge PSIA =Pounds per Square Inch Absolute SOS =Speed of Sound WC =Water Cut X21 Page 1 of 3 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Thursday, July 17, 2008 1:12 PM To: Brady, Jerry L Cc: Roby, David S (DOA); Maunder, Thomas E (DOA); Birnbaum, Alan J (LAW); Taylor, Cammy O (DNR); Colombie, Jody J (DOA) Subject: RE: 070808 BP Cover Letter Jerry, Yes, I can see that BPs prior request for Unit 5 also requested under 20 AAC 25.228 and 11 AAC 83.371. Take a look at the public notice AOGCC put out in 2007 for the Unit 5 proposal. If you can't find the earlier notice in your files, David may be able to find it for you. The whole question here is what are you wanting to apply for at this time. The Commission has authority for the state to approve/require standards for well test equipment and allocation methodology per 20 AAC 25.230. It's a new ball game if the MPMs are being proposed instead of LACT meters between units, such as the Pioneer/KRU and Liberty/Endicott plans. If seeking "fiscal allocation" methods to replace LACT unit requirements, you would need approval from the Commission to waive requirements of 20 AAC 25.228, plus DNR and likely DOR will be very involved in this (and MMS for Northstar, and Liberty.) Alan Birnbaum is our attorney for the Commission and perhaps he can help you further. Cammy Taylor, Unit Manager at DNR has experience on this from Commission and DNR standpoint, and I think she would be of great help to you. I am cc'g both on this. If it can all wait till I get back, that might be best. Monday is ok with me. I'm outs here till July 30. Later Jane From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Thu 7/17/2008 8:19 AM To: Williamson, Mary J (DOA) Subject: RE: 070808 BP Cover Letter Thanks Jane! I will check on this. I am somewhat confused though. These are the same numbers we used last time. Were they also incorrect? Another topic, Andrew is not available on Friday. I will see if Monday can work. Jerry From: Williamson, Mary J (DOA) [mailto:jane.williamson@alaska.gov] Sent: Wednesday, July 16, 2008 8:50 PM To: Brady, Jerry L Cc: Pospisil, Gordon; Seamount, Dan T (DOA); Colombie, Jody J (DOA); Birnbaum, Alan J (LAW); Foerster, 7/18/2008 Page 2 of 3 Catherine P (DOA); Norman, John K (DOA); Roby, David S (DOA); Maunder, Thomas E (DOA); Kline, Carol; Colombie, Jody J (DOA) Subject: RE: 070808 BP Cover Letter Jerry, Thank you for the exciting overview of the Gent today. Excellent technical work. I reviewed the cover letter of the application again and I noticed a few things that you need to review with Gordon to make sure it is correct. It was my understanding that you are solely requesting use of this Gen 2 MPFM device for well testing and for use in production allocation within existing BP operated properties. . Your letter states you are requesting approval under 11 AAC 83.371 which is not under AOGCC authority. This is within DNR -Kevin Banks group. I would see if Cammy Taylor cammy.taylor@alaska.gov at 269- 8817can help you concerning this. I don't believe this regulation applies. . You also mention 20 AAC 25.228 -This doesn't apply unless you are requesting use in custody transfer applications. We would not be able to approve this without opportunity for hearing, and I'm fairly certain a hearing would be held if you do have this in mind. • If you are only requesting approval to use the GEN2 to enhance current test separation for existing pools, the Commission has the authority to approve under 20 AAC 25.230(a) and the Conservation Orders noted in your letter. . You should change the title of CO 547 to include all oil pools within the Prudhoe Bay Field, with the exception of Put River Oil Pool, Raven Oil Pool. • Your slides suggested you have a few specific projects in mind, but you stated you want to move toward full scale use of this technology. My preference would be a more measured, pilot approach, and I suggest you think about this, and specifically indicate where these will be used, say in the next 2 years or so. If you could limit the scope to what you will be getting to in the next 2 years, then I expect administrative approval wouldn't be a big deal. Of course we can notice for hearing in the larger scale and just see if there are comments/objections. I know you are in a hurry, but after considering this further, I need to take more time to collect comments from everyone and get our attorney to weigh in on the handling of your request. And, unfortunately, everyone is swamped with more pressing items at the moment. Therefor, I'll work on this when I get back. I will be on vacation from July 17 to July 29. It is really important to get this right from a legal standpoint. In the meantime, I suggest you work to set up a technical meeting with MMS (who will have their own requirements), DNR, and DOR. I believe your technical contact at MMS is James.Lusher cni.MMS.gov. At DNR, Cammy will ensure it is coordinated. I'm afraid I have no idea who at DOR would be involved or if they need to be involved. I'm not sure if Dudley is the technical guy any more. I suggest you contact Jon Iversen, 269- 6620, Jonathon.lversen@alaska.gov for a SPOC. I really think your technical work is very exciting and I do think this should be shared with them. If you have further questions, Dave Roby may be able to help at 793-1232. Jane 1NiCCiar~n on, PZ AOGCC Senior Reservoir Engineer (907} 793-1226 From: Williamson, Mary J (DOA) Sent: Tuesday, July 15, 2008 12:41 PM To: 'Kline, Carol'; 'Brady, Jerry L' Cc: Pospisil, Gordon; Seamount, Dan T (DOA); Colombie, Jody J (DOA); Birnbaum, Alan J (LAW); Foerster, 7/18/2008 Page 3 of 3 Catherine P (DOA); Norman, John K (DOA); Roby, David S (DOA); Maunder, Thomas E (DOA) Subject: FW: 070808 BP Cover Letter Carol and Jerry, It appears that this is your official application for approval to use the Gen 2 Multiphase Meter System, which will require amendment to 7 Conservation Orders. If so, we request 10 hard copies of the signed cover letter and application, one for each conservation order file, and 3 for Commissioners and Staff. You've requested amendment of CO 551 for Northstar. MMS is a royalty owner there and you therefor need to add to your cc list Jeff Walker, Regional Supervisor of Field Operations, Mineral Management Service Alaska Field Office - 3801 Centerpoint Drive, Suite 500, Anchorage AK 99503. After we receive the hard copy of the application, the Commission will determine whether they wish to act upon these requests administratively or notice the applications for public hearing. ,jc~ne ~I~ViCCiamson, ~F AOGCC Senior Reservoir Engineer (907) 793-1226 From: Kline, Carol [mailto:Carol.Kline@BP.com] Sent: Monday, July 14, 2008 5:31 PM To: Williamson, Mary J (DOA); Seamount, Dan T (DOA) Subject: 070808 BP Cover Letter Dan Jane It appears that the zipped file of the complete Application Report for Weatherford Generation 2.0 Multiphase Metering System was too large and bounced back to me. The only difference between the one sent last week and today is the signature on the cover letter. Attached is the cover letter for your file. Do you require a hard copy? Please let me know. I'm happy to bring one to you, if necessary. carol kline Office: (907) 564.4744 Cell: (907) 223.9494 email: carol.klinenbp.com 7/18/2008 ~zo by Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. July 8, 2008 Dan Seamount, Jr. -Chairman Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska)Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907) 564-5769 Fax: (907) 564-5706 Email: gotdon.pospisil~bp.com ~1~~ ~T~z~ x, r ,,, Is-3~~s~ ~,.,, ~.J~il' ' fc~53on r` . , Re: Application Report for Weatherford Generation 2.0 Multiphase Metering System Amendment to CO 547 -Prudhoe Bay Oil Pool Amendment to CO 548 -Endicott Oil Pool Amendment to CO 550 -Milne Point Oil Pool Amendment to CO 551 -Northstar Oil Pool Amendment to CO 559 -Put River Oil Pool Amendment to CO 570 -Raven Oil Pool Amendment to CO 402A -Badami Oil Pool Dear Mr. Seamount: BP Exploration (Alaska) Inc. (BPXA}, Operator of the fields shown in Appendix 1 of the attached Application Report, hereby requests authorization to use amulti-phase measurement device, as described in the Application Report, for the purpose of well testing and production allocation within BPXA operations conducted in the Prudhoe Bay Oil Pool, Endicott Oil Pool, Milne Point Oil Pool, Northstar Oil Pool, Put River Oil Pool, Raven Oil Pool, and Badami Oil Pool pursuant to 11 AAC 83.371, 20 AAC 25.228, and 20 AAC 25.230. The report describes the design, the expected performance and the anticipated applications of the Weatherford Generation Z.0 Multi-Phase Flow Meter. BPXA also requests an amendment to each of the aforementioned AOGCC Conservation Orders (CO) governing each pool in order to allow for the use of multi-phase meter technology as described in the Attached Report. The in-line multiphase metering system described in the attached report is based on the infrared water cut detector and sonar flow meter technologies, both developed by Weatherford. The system has been successfully tested at GPB V-pad and provides a metering solution for use in the full range of well conditions in the North Slope fields. The trial tests on V-pad concentrated on high gas fraction, gas lifted wells, but with conditions in the liquid-dominated multiphase regime. These meters were tested in a series and were statistically evaluated for accuracy, precision, and repeatability against a BPXA Request for Clarification Meeting and Request for Hearing Page 2 known standard two-phase separator. Based on the result of this test and other experience gained throughout the world, BPXA has gained an improved understanding of the applicability and limitations of multi-phase metering to North Slope production wells. The AOGCC Application Report submitted herein compiles the data and literature that were used to qualify the design and establish performance levels for the Weatherford Gen 2.0 Multi-phase Flow Meter as a self contained unit. This document was prepared following the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued November 30, 2004 by the AOGCC. Approval of this request will advance the use of multi-phase metering technology for North Slope production measurements. It will allow BPXA to gain operational experience with this meter while demonstrating multi-phase metering technology can provide allocation well tests comparable to a conventional test separator. Additional benefits include improved testing frequency (no stabilization period required), production fingerprinting (no vessel dampening), reduced HSE risk (smaller footprint, fewer personnel, no vessel), and opportunity for lift optimization. Should you have any questions regarding this request, please don`t hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Thank you for your assistance. Sincerely, ~^ ~ l Gordon Pospisil Technology & Resource Manager Attachment Cc: Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA John McMullen, BPXA Sherri Gould, BPXA John Cyr, BPXA Jerry Brady, BPXA Alan Mitchell, BPXA Sonny Rix, ExxonMobil Dan Kruse, CPAI Glenn C. Fredrick, Chevron USA Scott Millington, Anadarko Daniel "Toby" Osborn, Doyon Ltd Mathew Fagnani, Nana Glenn Fredrick, Chevron Ignacid Herrere, Murphy Exploration Jane Williamson, Alaska Oil & Gas Conservation Commission Kevin Banks (Acting Director) Division of Oil and Gas -Department of Natural Resources Cammy Taylor -Unit Manager Department of Natural Resources Jon Iversen, Director Department of Revenue -Tax bivision Jeff Walker, Mineral Management Service Alaska Field Office BP Alaska AOGCC "Application Report" for the Weatherford Gen 2 Multiphase Metering System 7/15/2008 070808 .40GCC (;e~2 App Kptd~c Table of Contents AOGCC "Application Report "for Gen 2 Multiphase Measurement System ............................ 3 1. Introduction ........................................................................................................................ 3 2. Proposed Applications ....................................................................................................... 3 3. System Components and Measurement Strategy ................................................................ 3 4. Field Test Program and Test Results ................................................................................. 6 Table 1-Summary of wells tested, time, and duration ......................................................... 7 Table 2 -Well Fluid Properties for Gen 2 Tests ................................................................... 7 Table 3 -Summary of Gen 2 Measurement Uncertainties (RMS average values) ................. 7 S. Factory Acceptance Tests (FAT) ...................................................................................... 10 6. Field Maintenance and Periodic Calibration ..................................................................10 7. List of References .............................................................................................................11 8. List of Appendices ............................................................................................................ I1 2of11 070808 AOGCC Gent flpp Rptc~oc AOGCC'Application Report"for Gen Z Multiphase Measurement System 1. Introduction This document describes the design and anticipated performance of Weatherford Gent - hereafter referred to as Gen 2 multiphase metering skids -designed for well testing of wells in operating areas shown in Appendix 1. This report compiles the data and literature that was used to qualify the design and establish performance levels for the Gen 2 skid. This document is to be submitted to Alaska Oil and Gas Conservation Commission (AOGCC) as an "Application Report" to obtain their approval for using the Gen 2 multiphase metering system as an alternative to conventional gravity based test separators for well testing. The "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued by AOGCC, requires operators to submit this "Application Report" before new metering systems are used for production well testing and allocations. Section 3 of the AOGCC document outlines the type of information that the application has to provide. This BPX "Application Report" provides the information that is requested in the Section 3 of the AOGCC document. The Gen 2 in-line multiphase metering system described in this report is based on the infrared water cut detector and sonar flow meter technologies, both developed by Weatherford. The system has been successfully tested at GPB V-pad and provides a metering solution for use in the full range of well conditions on the North Slope. The trial on V-pad concentrated on high gas fraction, gas lifted wells, but with conditions in the liquid-dominated multiphase regime. The ASRC Unit 1 was adopted as the reference device for the test. Confidence in Unit 1 was established through spot sampling of water cut and by comparison to the well pad separator. 2. Proposed Applications The proposed multiphase metering systems are designed to be used either as permanent wellhead installation or mobile systems deployed in a field. Table 1 in Appendix 1 A shows the wells and production horizons in which BP is the operator or has working interest that may use the proposed multiphase metering unit. This Table also shows the working interest owners. All parties with working interest, royalty ownership, as well as the Alaska Department of Revenue will be notified about the use of the metering system when the application of the metering system affects such interests. The proposed application will use the multiphase metering skids for production allocation. In the event that the proposed multiphase metering scheme does not produce the expected accuracy, we will revert to use the conventional well testing techniques. The allocation methodology currently practiced will continue and would not be affected by the multiphase metering system. 3. System Components and Measurement Strategy The Weatherford Gen 2.0 multiphase meter concept consists of four principal components: 1. A Red Eye 2G near-infrared water cut monitor 2. A Cs 137 gamma densitometer 3. A passive sonar volumetric flow meter 3of11 07U80& AO(:CC Gent App Rpt.d~~e 4. A Venturi nozzle differential pressure flow meter The proposed well head field configuration is shown in Figure 1. Figure 2 shows the Gen 2 installation in V-Pad trial tests conducted in January of 2008. Each of the metering components has been previously tested in wet gas and multiphase flow conditions as noted by the list of references. The innovation of the Gen 2.0 meter is to combine the four sensors to enable the optimum measurement of oil, water and gas flow rates across the full spectrum of composition, i.e. from 0% to 100% water cut, and from 0% to 100% gas volume fraction. The field tests reported in this document were performed to confirm loop test results for the Gen 2 meter and qualify this meter for field application. The sonar and nozzle are integrated into a single spool piece, with the densitometer and Red Eye meters located on downstream spools of restricted diameter (matching the diameter of the restriction at the sonar section); it is the intention that the four measurements will be integrated into a single spool, along with a static pressure and temperature measurement. The Red Eye 2G near-infrared water cut monitor has been extensively tested by a technology program led by the BP Gulf of Mexico (GOM). This has demonstrated the capability of the Red Eye to detect the water cut in multiphase flow streams containing up to 95% GVF with an uncertainty of ~5% absolute in the water cut measurement, almost independent of the GVF. A Red Eye has been installed at the UK National Engineering Laboratory (NEL) for nearly two years, undergoing a range of multiphase flow tests.2 One final comment on the Red Eye is that its measurement of water cut is expected to be unaffected by the composition of the water phase, i.e. independent of water salinity. This is because the dissolved salts in the water phase have no effect on the absorption of infra red radiation at the wavelengths used2. The gamma densitometer based on the 137 Cs Isotope uses the high energy 661 keV gamma ray. This device can be clamped to the outside of a steel pipe, and at 661keV there is little composition sensitivity of the absorption of the gamma ray, and so this instrument can be used to measure the density of the fluid mixture across a single path through the pipe, in this case a vertical path. This measured density can be directly related to the void fraction in the pipe. If the slip between the gas and liquid is known, then the void fraction can be converted to gas volume fraction. Note that `high energy' refers to the energy of the particular gamma ray, not the intensity. A high energy gamma ray is required to penetrate the steel pipe walls, but the intensity, or activity of the radioactive source material can be relatively modest, with a source activity of 100mCi more than adequate. The passive sonar instrument consists of an array of strain detectors mounted around the pipe circumference. This instrument interprets the propagation along the array of pressure pulses generated by the turbulence in the flow. This has been demonstrated to work well in a single phase (either gas or liquid) environment, and in a wet gas environment, with the measurement of total velocity (gas + liquid) in a wet gas stream almost independent of the liquid contents, a The tests at V-pad, presented in this report, were conducted in a liquid dominated multiphase stream to compliment the previous work. In this implementation the array of strain gauges is mounted on a section of restricted diameter. The reduction in the pipe cross section and consequent increase in gas velocity gives an improvement in the ability of the device to measure a velocity in a multiphase flow stream; this velocity is very strongly correlated with the gas velocity. 4of11 tV-fktilPS ~lff,Q ( F~c~t_' \~r~i Il~~~.duc Finally, the Venturi nozzle is based on a modification of the ISO 5167 standard ISA 1932 nozzle differential pressure flow meter and is included in this configuration order to make a measurement of the total flow momentum and hence mass flow rate. The choice of the nozzle type device over the more conventional Venturi was an attempt to condition the flow profile better for entry into the sonar measurement section, and a slight modification was made to the standard nozzle design in order to optimise the entrance effect of the flow meter area change on the sonar array in the meter throat. This device has been tested at Colorado Engineering Experiment Station and at NEL in wet gas flow conditions. The meter that was tested at V-pad in January of 2008 was 3-inch full bore ANSI 1500, with the diameter ratio (beta) of the nozzle being 0.541. The exact internal diameter at the inlet was 2.62 inch (66.64 mm) with the nozzle throat diameter 1.42 inch (36.05 mm) and the ID of the sonar section 1.58 inch (40.06 mm). Figure 1-Schematic of the Gen 2 Well Head configuration The measurement strategy for the Gen 2 system utilizes the "over reading" by Venturi and Sonar devices, caused by liquid content of the multiphase stream, to calculate the total and liquid flow rates in the multiphase stream. This is accomplished through a model developed for the Gen 2, which then calculates the GVF in the multiphase stream. The liquid density derived from the RE water cut meter and the multiphase fluid density provided by the densitometer, is used to partition the total flow rate into oil, water and gas flow rates at line conditions. The line condition flow rates are transformed to standard conditions through PVT calculations and reported as the output for the meter. Sofll 0711808 ..-~000C Gent ,app Rpt.dui~ Figure 2- Gen 2 Installations at V-Pad 4. Field Test Program and Test Results The testing was performed at Prudhoe Bay V-Pad between January 26`", 2008 and February 6`", 2008, with 16 well tests completed in this period. Each well was stabilized through the test system for 4 to 6 hours, followed by an 8 hour well test. Table 1 show the wells tested, test time and duration. The fluid properties for these tests are shown in Table 2. The test results are summarized in Table 3. Figures 4 to 9 show graphs of well test results for gas rate, liquid rate, and water cut. In each graph the data from Gen 2 is plotted against the data from ASRC Unit 1 that was used as the reference. The graphs in Figures 4-9 are presented in support of the gas, liquid and WC uncertainty levels for Gen 2 shown in Table 2. These graphs include the error from the reference test separator. 6 of 1 1 070808 AOGCC Gent App Rpt.doc Table 1- Summary of wells tested, time, and duration Wdl Tat dit* Tat time Tat sfion Pnea*we Bey Vied pariehekl V-41 Wet not av~l~e V-03 Qt -31-204$ 03:00 - f t :40 $ hogs Y-~3 Q2-{r3-244$ / 4:4D -22:04 ~ hours. V-tk4 Oi-2$-2448 t5:44-23:40 4haurs Pnedlaoe Bey V~ad V-tbt 43-05-2448 21:00 -45:00 $ haws V-t 02 Ot-2~-244$ t t:bb - t$:bb $ hoes V-t 03 41-2~-244$ 4D:bd-U3~3 Teat~~dwied l~ttt 5 erat~ 41-3t -2448 18:04 - 44 {14 $ haws v-t 4S bt-~-aab$ bo:bo - 4$~4 un~ t ~,d t 5 wed 4t-3D-244$ 13:44 - 2t A4 $ hoes V-t 47 We®nat tasted V-t 48 43-44-24tB 4:44 - t3:44 $ hags V-t d9 We1 net tasted V-1 t t 43-04-24th t $:O4 -03:04 $ hasps v-t t3 Oi -28-244$ t x:04 - tS:t 5 H3S trap -test ahar,danad 4t-37-2448 t2:00-2404 $haars ~+-t t7 We®not e V-t 22 43-45-2448 4$:40 - 1804 $ hasps Pradaoe 8etr V~Ped RSelredaar Blaatry v-s43 43~t-aab$ a~:oo - t~:bo $ ham ~ Zar 4t-2$-2448 42:40 - t404 $ Woos - 43-03-2048 t 2:44 - 24 04 $ haws V-244 43-4t-2443 20:44 -04:44 $ hasps w-2tb 43-03-244$ 4 t:44 -49:44 $ heaps Table 2 -Well Fluid Properties for Gen 2 Tests Gas Oil Water Formation/Well Density Density API Viscosity Density SG at 60 F cP at 60 F .886 14.1 @ Ivishak/V-04 0.882 g/cm3 28.2 68 F 1.013 g/cm3 .939 117 @ 66 Kuparuk/V-111 0.8 g/cm3 19.2 F n/a .938 273 @ 68 Schrader Bluff/V-204 0.75 g/cm3 19.4 F 1.014 g/cm3 Table 3 - Summary of Gen 2 Measurement Uncertainties (RMS average values) Meter Measurement Uncertain Relative to ASRC Unit 1- Gas Rate Li uid Rate Water Cut Gen 2 ~7 ~8 ~5 V-Pad Se arator ~9 f14 ~9 Estimated Reference Uncertaint ASRC Unit 1 ~3 ~5 ~2 7of11 117118118 :~OG(Y Gcn2 .app Rpt.duc 5a0o .... ~® ?C~ 2~D ~ 200D ~~ C ~~ 0 • NFf C•n.O af;IrYnYI ^ Nc'r Un:LPf{KUyrJI • f1R CSn:D~flBt lrfO•~BUt9 _~i.5i __- ~~.171.. • ^ .. • ~~ •• 11 ~109i ~_ ~ b tow • 109 O ~ C a -1096 O Q lV -209(, C -3791 -.C9~ -6091 Un~i 1 gas tiowraf8 (111scUd) Figure 4 -Gas flow rates from Gen 2 ^ 419rY1F7 Cim ~0 ~;K~ONJ; • 91HrriF7 C+m:n pr{&rnQi-BUI; _ M. - ~ ^ • _ . _ _ _ - _ - _ - _ - _ _ _ _ _ .. _ _ _ L _ _~ - ~•_ - 60 $ EO B5 70 75 60 ffi 90 96 100 Una 1 GVF (fli) Figure 5 -Gas flow rate accuracy as a function of GVF 370J ~ 2~ao kY 2000 3 O C 7~ 16~ • NFTG•n:9prYe{nMrl • riF'f (9Yn i0 prMlKU{•NI • riFT (3•n 20 puel&nnur-bun ~ _ - .. fo9a 7 ~ • • A. « • • i Q C ~~ '~ 0 ~ D 6CD 1~ 760D 2007 26x0 3700 unit, liquid tlowrate (st61d) Figure 6 -liquid flow rates from Gen 2 8of11 U70808 AOGCC Gent .-app Rpt.doc X0171 ~# ~ '071 t 20i9~ 4V a ~~ n3 i ~ ~_ ~ -~~ _Q O -~~ -~ •~~ _~~ • 51BhNFT Cfri:a 4udln'rnYl • &Hhlii'fWn:a4J~lKuprull • 91HM1FTWn:Dpuf~B[nro•~BUt; - -"' ylt -- w. 1'J~ - ~ - ~ - • • UnR 1 GVF (9~) Figure 7 -Liquid flow rate accuracy as a function of GVF. The Schrader-Bluff "out of bound" data is believed to be due to the over-reading of reference (ASRC Unit 1) under the flow conditions. ,w • 907, • WFT Wn:'aw••[u;~nro[1 ^ • fIFT Wn';Ow••[ul ~Ifugtil EOK • /1FT G.n:awr [V ~BCmsr-Blun) ~ ev9: • v a Q ,~9. N • {C1 • ?GRL O • 2071 1071 ^ 09~ • 091 1D71 209: 30# 109. 5091 ~9: 7071 /Y'19i 9096 7f>011 Unl~ ~ W/~8f CUl ~) Figure 8 - WC measurements from Gen 2 9of11 Ii70R118 :~OG(Y Gcn2 :app Rpt.da ~x _ ao9: a ~°°` a ,~ 3 -JOVc 4 N C -^•CI9i 0Y _~94 o+. • ^w - --------------------------- -t--- -~O'# • NFT dn: UvA1M [ut;1. V•1J • MFT dn20 MIM [N{KiprulJ • WFTdn:D+NM[utJ&nrasFeanJ - -•. 5R -sovc ~ ~ $ eo ~ ro is ao as 9o sa Unt 1 GVF ('1~) Figure 9 -Gen 2 water cut accuracy as a function of GVF 5. Factory Acceptance Tests (FAT) Jm The following factory acceptance tests will be conducted prior to field installation: • Hydrostatic pressure testing is performed according to the meter's pressure rating. • Liquid and gas flow rate tests will be conducted to check the performance of the meters. The test conditions will be guided by both the operating constraints of the test meter and of the flow facility. • A single-phase (water) calibration of the sonar array and a verification of the nozzle discharge coefficient are conducted. Due to well behaved Reynolds characteristics of the Sonar meter and documented properties of the Venturi nozzle, the single-phase water calibration has been found sufficient. • The Red Eye probe is calibrated on air as well as pure dry oil and produced water samples. Air calibrations are unique for each Red Eye unit. 6. Field Maintenance and Periodic Calibration The following items will be checked periodically: • The PVT tables would be updated monthly or as necessitated by operations to match a revised fluid characterization derived from representative field samples. • Correct operation of the primary devices will be tracked yearly to detect any offset (e.g. due to fouling). Establishing single-phase flow through the meter for a basic cross check between the nozzle and the sonar array provides the necessary primary device diagnostics. • Empty pipe calibration required as necessary for the densitometer. • Radioactive source site requirements -wipe test every 6 months. • Periodic calibration of DP/P/T transmitter. • Expected replacement of Red Eye monitor after 5 - 7 years. 10 of 11 7. List of References 070808 AOGCC` (Sent App Rpt.doc 1. "A PROTOTYPE WET-GAS AND MULTIPHASE FLOWMETER" E. S. Johansen (Weatherford Intl.), A. R. W. Hall (BP Exploration & Production),O. H. Unalmis, D. J. Rodriguez, A. Vera, V. Ramakrishnan (Weatherford Intl.) ,25th International North Sea Flow Measurement Workshop 16th 19th, October 2007. 2. "Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions", Andrew Hall, BP Exploration & Production John Lievois, eProduction Solutions, Babajide Adejuyigbe, eProduction Solutions. 6th South East Asia Hydrocarbon Flow Measurement Workshop7th- 9thMarch 2007. 3. "Wet gas metering using sonar-based flow meters and piping pressure loss gradients," Gysling, D.L., Loose, D.H., Morlino, N. and van der Spek, A., 25th International North Sea Flow Measurement Workshop, Oslo, Norway, October 2007. 4. "New class of meter solves old problem impacting well test accuracy," Ward, E., SPE paper 100893, 2006 SPE Western RegionaUAAPG Pacific Section/GSA Cordilleran Section Joint Meeting held in Anchorage, Alaska, May 2006. 8. List of Appendices Appendix 1 -Fields, Pools, and Wells Appendix 2 - "A PROTOTYPE WET-GAS AND MULTIPHASE FLOWMETER" 25th International North Sea Flow Measurement Workshop 16th - 19th, October 2007. Appendix 3 - "Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions" Appendix 4 -CLAMP-ON, SONAR-BASED VOLUMETRIC FLOW RATE AND GAS VOLUME FRACTION MEASUREMENT FOR INDUSTRIAL APPLICATIONS Appendix 5 - "New class of meter solves old problem impacting well test accuracy," 11 of 11 Appendix 1A Table 1-List fields, pools and wells affected by this proposal Working interest, royality interest, and tax treatment for leases Alaska Property Ownerships AOGCC BP Processing Facility Participating Area Pool Code AOGCC Pool Description Royalty Rate % ELF Exploration Chevron Conoco Phillips Exxon Mobil Doyon Ltd Nana Unocal Anadarko Murphy Total Badami Badami 060100 Badami 12.5%to 16.67% Separate 100 100 Endicott Eider 220165 Ivishak Undefined (Eider) 12.50% Separate 100 100 Endicott Endicott 220100 Endicott 12.5%to20% Separate 67.9221 0.0234 21.0206 0.1291 0.3874 10.5174 100 Endicott Sag Delta North 220150 Sag Delta Norlh 12.5%to 20% Separate 98.1327 0.4668 1.4005 100 LPC Niakuk 640148 Niakuk 12.5% Consolidated Niakuk 26.360567 1.16 36.076746 36.402687 100 LPC Tracl Operations 640147 GPMA Ivishak-Sag River 12.5% Consolidated Niakuk 0 LPC West Niakuk 640149 Niakuk, Undefined 12.5% Consolidated Niakuk 26.360567 1.16 36.076746 36.402687 100 LPC North Prudhoe Bay State 640152 North Prudhoe Bay State 12.5% Separate 26.360567 1.16 36.076746 36.402687 100 LPC West Beach 640186 West Beach 12.5% Separate 26.360567 1.16 36.076746 36.402687 100 LPC & Prudhoe GC-1 Lisburne 640144 Lisburne 12.5% Separate 26.360567 1.16 36.076746 36.402687 100 Milne Poini MPU Kuparuk 525100 Milne Point Kuparuk 12.5% to 20°~ Separate 99.425769 0.574231 100 Milne Paint MPU Sag River 525150 Milne Point Sag River 12.5%to 20% Separate 98.741072 1.258926 100 Milne Point MPU Schrader Bluff 525140 Milne Point Schrader Bluff 12.5%to 20% Separate 99.269596 0.7304D4 100 Milne Paint Traci Operations 525160 Milne Point Ugnu, undefined 12.5°k Separate 100 100 Northstar Northstar 590100 Northstar 20%plussupplemental Separate 98.5772 1.4228 100 LPC & Prudhoe GC-1 Point McIntyre 640180 Point McIntyre 12.5%io 16.67% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe All GC & FS Prudhoe IPAs (OWGC) 640150 Sadlerochit 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GC-1 Midnight Sun 640158 Midnight Sun, undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GC-2 Aurora 640120 PBU Aurora, Undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GC-2 Borealis 640130 PBU Borealis, Undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 10D Prudhoe GC-2 Orion 640135 PBU Orion, Undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe GC-2 Polaris 640160 Schrader Bluff (Satellite), undefined 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 G. 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I Dsla Ds1s 1 ~°~ D517 1 ~ ~1 LISBURNE PA' ~ ~ 1 1 ~ I ~ DFADHDRSE ~ ~0a DS 2N , .J _ '-~ ~. ~ ` ~ KUPARUK RIPER • 1~ ~ 1 ~ . ~ e ~ ~ ~ ~ KUPARUKPA"' ~ ~ _ JACOBS LADDER UNIT WEST SAK PA "' I Anadarko 50.0 % ~~ ~... __ ROCK FLOUR UNIT a BG Alaska 40.0% BADAMI UNIT GREATER MOOSES TOOTH UNR ' ~.~' ~:` ~ -~ , d ASRC 10.0% gpppMl SANDS PA ENIPetro 100.0% s S' d . ~' Approx. 7 Miles East Approx. 20 Miles West 1 , ~ CPAI 78.D0% Anadarko 22.00% IARCTICFGRTITDDEUNIT J A White 100.0% l .p° ~ BPExploratlont00.0% . . TAPS ~ ~~7 1 BP Pipelines Inc. 48.8785% ~ ; ` 1 ~ ~..- I CPAI 28.2323% 4325% E M bil 20 . r 1... ~ 1 xxon o . ( d, I ~KUPARUKRIVERUNIT ltw r PA'"' ` M t Williams 3.0845°10 / Unocal 1.3742% ~ r e a e DszP / 1 1 a` I / ' BPXA Cartography does not warrant that the data Is accurate or fit for any ~^' ~ ,~ . J particular use. User hereby Indemnifies and holds harmless BPXA Cartography / - - - • ~ - for any claims andlor Ilablllties which may arise from users use the data - I~ ;~ ornn 25th International North Sea Flow Measurement Workshop 16th -19th October 2007 A PROTOTYPE WET-GAS AND MULTIPHASE FLOWMETER E. S. Johansen (Weatherford Intl.), A. R. W. Hall (BP Exploration & Production) O. H. Unalmis, D. J. Rodriguez, A. Vera, V. Ramakrishnan (Weatherford Intl.) ABSTRACT A wet-gas flowmeter based on the field-proven downhole fiber-optic multiphase flowmeter has been developed. The flowmeter is based on an extended throat Venturi-nozzle and a Sonar flowmeter. This combination exploits the characteristics of these two devices in wet-gas flows. For the Venturi, there is awell-defined and large over-reading with increasing liquid-loading, whereas this has a significantly lower impact on the total flow rate measured by Sonar. The Sonar-Venturi wet-gas flowmeter has been in development over the past several years and has been tested extensively in industry flow loops. Particular emphasis has been placed on developing a flowmeter with a broad operating envelope that includes a large span of fluid properties, a high turndown ratio, and well characterized response both within and outside its intended operating envelope. The wet-gas performance has been demonstrated at the recently commissioned CEESI 3 phase wet-gas flow loop, yielding total and gas flow rates better than ~5%,* liquid flow rate better than X0.5 m3/hr in Type I wet gas,l and better than X20% in Type II wet gas. A Red Eye 2G near- infrared (NIR) water cut meter is used to differentiate the oil/condensate and water: The Red Eye 2G has field proven performance in low gas volume fraction (GVF) flows for full range of water cut. A prototype version has demonstrated f5% water cut uncertainty in high GVF multiphase2 flows and initial testing of the Red Eye in wet-gas flows is showing great promise. The wet-gas flowmeter was also tested at the NEL multiphase flow facility to evaluate whether the measurement capability could be extended beyond the wet-gas envelope. Although the performance in low-pressure multiphase flows did not match the performance seen in high-pressure wet-gas flow, measurement capability was maintained and reasonable performance was demonstrated for the entire range of GVF. INTRODUCTION Test separators and portable well testing services are the most common technologies used to generate a measurement snapshot, typically every 30 days, but often less frequent. It is, however, widely accepted that real-time individual wellhead production monitoring is an effective tool to monitor the health and maximize the performance and ultimate recovery of producing oil and gas wells. Measurement technologies have been developed to monitor individual wells in real-time; however, the high cost has generally limited the install base to prolific wells or multiple wells multiplexed with multi-port selector valves. Furthermore, many are being used as mobile well- testing devices. Other factors complicating wide implementation include limited operating envelope, fragile mechanical and sensing characteristics, and sensitivity to changes in fluid chemistry or composition. To date, only a few meter types claim to operate both in wet-gas and All performance numbers quoted herein are relative measurements with 95% confidence interval, unless otherwise noted. multiphase regimes. Most other wet-gas or multiphase meters may report highly erroneous results outside their intended operating range. Therefore, as wells mature with increasing gas fractions and water cut, the flow measurement conditions at the wellhead necessitate flowmeters with a wider operating envelope and a lower sensitivity to compositional changes than is available today. The Sonar flowmeter technology platform offers the potential for acost-effective and robust flowmeter with a broad operating envelope that may bridge the gap between traditional multiphase flowmeters and high gas-fraction metering. Sonar flow measurement is derived from the field- proven downhole fiber optic multiphase flowmeter.3-5 It is non-intrusive, has no wetted sensors and offers excellent resilience to erosion and corrosion. Sonar flowmeters offer accurate and repeatable flow measurement with a small and well-behaved Reynolds number dependence and a large turndown ratio. Sonar can measure liquid and gas flows with no changes in hardware or software. The conventional types of differential pressure meters (e.g. Venturi, cone or orifice plate meters) still remain the flowmeters of choice in the vast majority of gas wells. The over-reading of such devices when there is liquid in the flow stream is well understood and documented in literature.6'~ However, the liquid content can be very difficult to estimate and hence correct for in the field. Consequently, the erroneous readings must be corrected by back allocation. Sonar tends to have a very well-behaved and low over-reading with liquid loading in wet-gas flows. The combination of a differential pressure meter with a Sonar flowmeter therefore offers an over-reading contrast that is exploited to yield the total and gas flow rates and the liquid content. FLOWMETER DESCRIPTION The Sonar-Venturi flowmeter is a combination of a Sonar sensor array located in the extended throat section of aVenturi-Nozzle, shown in Fig 1. The higher mixture velocity in the throat is favorable to the passive Sonar array as it improves signal to noise ratio and enhances mixing. The Sonar flowmeter consists of an array of electronic strain gauges (non-fiber optic) combined with fully integrated data acquisition and processing electronics housed in aspool-mounted enclosure. The prototype flowmeter also employs a multivariable pressure, temperature, and differential pressure transmitter for the Venturi. The flowmeter also includes Modbus and diagnostic communications over RS 485 and Ethernet. The entire assembly is powered by 12-36 VDC, consumes less than 10 W, and is Class I, Division 1 compliant. 2 multivariable transmitter Sonar data acquisition and erecessine electronics flo~~ Figure 1 -Sonar-Venturi flowmeter schematic. Sonar Flowmeter Turbulent pipe flow contains self-generating vortical structures that convect with the fluid. These vortices remain coherent for several pipe diameters, and they decay as they convect through the pipe. Meanwhile new vortices are continuously generated by frictional forces acting between the fluid and pipe wall and within the fluid itself. An array of circumferentially mounted and axially distributed pressure sensors measures dynamic pressure fluctuations associated with the convecting turbulent eddies. The convection velocity is calculated from the unsteady pressures by array processing algorithms. The volumetric flow rate is directly proportional to the convective velocity measured by Sonar and a single Reynolds number calibration yields a flow rate for liquid or gas. with an uncertainty typically better than ±1 %. The calibrated performance of the Sonar meter in single-phase (oil, water and gas) is presented in Fig. 2. A Reynolds number "turndown" of nearly three orders of magnitude is demonstrated for six different fluids at three different test facilities with no change in the three calibration constants. The calibration values are also consistent with what is typically seen in a fiber-optic flowmeter. In wet- gas conditions, the calibrated Sonar velocity yields a volumetric flow rate that is slightly higher than the actual mixture velocity. The over-reading of Sonar is well behaved with respect to liquid loading and is readily correlated with the Lockhart-Martinelli parameter. 3 Venturi nozzle Sonar array 5% 0 `_' 2% O w 1% ~ o°i° _o u. -1 a~ -2% d' 3% Venturi 4% 3% • NEL-Brine • NEL-Oseberg ^ NEL-Nitrogen O Weatherford-Water ^ Weatherford-Air ~ CEESI-Natural Gas ----- t 1% - ---------------o----...-......--,.;..........o- g • ° °• • o v ----------------------------------s...........------------------------------•-----••------------ -4% -5% ~- 1. E+04 1.E+05 1.E+06 1.E+07 1.E+08 Reynolds Number, [-] Figure Z -Baseline Sonar performance over broad Reynolds number range. The extended throat Venturi-nozzle performance was verified with the same dataset and was found to measure single-phase flow rates within X1.4%. The Venturi behavior is well described in literature. Tests conducted with the Sonar-Venturi combination throughout single-phase, multiphase, and wet-gas flow were consistent with published values of discharge coefficients. The turndown ratio of the differential pressure sensor is 84:1 from the multivariable transmitter specification sheet. In practice, the wet gas differential pressure on a horizontal Venturi-nozzle was observed to depart from the deLeeuw correlation at pressure turndown ratio of 30:1. Since 0P is proportional to VZ the velocity turndown ratio for the Venturi-nozzle is at best 9:1 and, in practice, it can be as low as 5:1. Thus, in terms of flow velocity turndown, the performance of the Sonar meter far exceeds that of the Venturi-nozzle. Water Cut Meter The Red Eye 2G water cut meter is based on the principles of spectroscopy and relies on the large difference in the absorption of near infrared (NIR) radiation between oil and water. Differentiation is achieved by operating over a very narrow band of radiation with maximum intensity occurring at wavelengths where crude oil and water exhibit large differences in opacities. The Red Eye measures transmissions at multiple infrared wavelengths simultaneously and calculates the water fraction from the ratio of attenuation at different wavelengths. The technique operates consistently across the full range of 0% to 100% water cut, and is effectively insensitive to free gas. 4 ° 0 R o: .~ a J °~; N t0 d 100 90 80 70 60 50 40 30 20 10 0 - - - ± 5% absolute error , ~ ° .Red Eye 2G, NEL, Aug 2005, Horizontal o Red Eye 2G, NEL, Aug 2005, Vertical o~ ° ~0 _, 0 10 20 30 40 50 60 70 80 90 100 Reference Water Liquid Ratio, [%] Figure 3 -Performance of water cut measurement Z 15 ° - - - ± 5% absolute error ° Red Eye 2G, NEL, Aug 2005, Horizontal i 10 n Red Eye 2G, NEL, Aug 2005, Vertical ~ w 5 ------------------------------- - n e° n--eP---B---- -- e° ° e n o -----°-'~----- ~ o n n n°n n 0 ° ~ U ° ° ° ° uJ n n ° o ~e ~ ~ $ ° ° ~°° ° ° ~° ~ ° ° e ° ° ~ ~~ o ° ° ~°n° 5 'o - --- ° ° ° ° •~ ~ ° ° -10 m ca -15 0 10 20 30 40 50 60 70 80 90 100 Reference Gas Volume Fraction, [%] Figure 4 -Performance of water cut measurement for wide GVF range? Data shown in Figs. 3 and 4 range from 10 to 95% GVF at low pressures.2 Even those points at the highest GVF do not constitute wet-gas flows with Lockhart-Martinelli parameter significantly higher than 0.3 (due to the low pressure and high liquid/gas density contrast)1. However, recent tests conducted at CEESI show very good sensitivity, correlation, and measurement capability in wet-gas flows at GVF up to 99.9%. The water cut measurement has been verified in separate studies and the remainder of the discussion in this paper will focus on the ability to measure liquid and gas flow rates by the Sonar-Venturi combination. 5 TEST ENVELOPE The flowmeter was tested at NEL (multiphase) and CEESI (3-phase wet gas) in August and September of 2007 respectively. The CEESI tests were conducted in the recently commissioned 3- phase wet-gas flow loop. 100 10 E ~ 1 0 d 0.1 J m ;t 0.01 m a N 0.001 0 0001 ^ NEL ^ ^ ~^ a CEESI S ~ 9 ® ^o° ^°~~° ^ ^ o ^ ~ ~ aan GVF 9.1% ^~ ^ p^ ~^~~~ ^ ®®oso ^^^~ GVF 50% ~ A • 0 e ,, e GVF 90.9% a -0"~ O A e _ • e g GVF 99.0% ~ e e o ~ _ e GVF 99.9% 0 GVF 99.99% 0.1 1 10 100 Superficial Gas Velocity, [m/s] Figure 5 -Phase superficial velocity and GVF variations for NEL and CEESI test matrices. Figure 5 shows the entire test matrix for both facilities in terms of superficial liquid and gas velocities with no-slip GVF as isolines. From this view, it appears as though the two tests overlap, however, the test pressure at NEL ranged from 2 to 7.5 bar, whereas the test pressures at CEESI ranged from 14 to 55 bar yielding very different liquid/gas density contrasts (see table below). Consequently the high GVF points in the NEL test matrix are not representative of wet-gas conditions because the relatively low gas density results in a relatively low gas Froude number, Frg and a relatively high Lockhart-Martinelli parameter, XL,u. The CEESI test envelope, on the other hand, covered Frg and XLM within the regions defined by API as Type I and Type II wet-gas flow.l CEESI NEL Pressure 14, 28, 55 bara 2 - 7.5 bara Tem erature 28-35 °C 22-42 °C WLR 0 - 100% 1, 40, 75, 100% GVF (no sli) 97.5-100% 0 - 100% Total Volume Flow Rate 85-655 m /hr 14 - 460 m /hr Liquid/Gas Density Ratio 16 at 55 bara 40 at 28 bara 98 at 14 bara 106 at 7.5 bara 485 at 2 bara Fr Sonar 1.5 - 20 0.07-2.6 Fr Nozzle 0.5 -5.5 0.02.-0.7 Xr,~r 0 - 0.26 0.3-167 LM 0 - 0.72 0-1 6 WET-GAS TESTS CEESI Test Facility The CEESI (Colorado Engineering Experiment Station, Inc.) wet-gas facility, originally built in 1998, was designed for two-phase flow studies consisting of natural gas and hydrocarbon liquids. The loop has been recently redesigned for three-phase operation. Figure 6 shows the block diagram of the three-phase wet-gas loop used for the current tests. CIRCULATION HEAT C^ALESCING TURBINE ULTRAS^NIC C^MPRESSDRS EXCHANGER FILTER METER METER GAS CHROMAT~GRAPH TRIPLEX 2~~ 0.5" PUMPS E^R C^RI^LIS C^RI^LIS METER METER HYDR^CARB^N GAS-LIQUID LIQUID SEPARATUR LIQUID-LIQUID SEPARATGR TRIPLEX 2" 0,5" PUMPS CURI^LIS CGRIGLIS EDR METER METER WATER TEST TEST TEST TEST TEST L^CATI^N 5 L^CATI^N 4 L^CATI^N 3 LOCATION 2 LOCATI^N 1 Figure 6 -Block diagram of wet-gas research loop, 4-inch test line Both a turbine meter and an ultrasonic meter measure the flow rate of the natural gas. The difference in mass flow rate between these two meters is monitored; if the difference exceeds a specified amount, the data is scrutinized for detrimental effects such as pulsation. If the difference is within tolerance, then all other meters installed in the research loop can be compared to the natural gas mass flow rate as measured by the turbine meter. Pressure and temperature measurements at various locations on the loop (including the test locations) are used to calculate local gas density. The hydrocarbon liquid and the water, which reside in the liquid-liquid separator, can be injected into the gas stream by positive displacement pumps (Triplex pumps). Coriolis meters measure the mass flow rate and the density of the liquids to be injected. The gas stream carries the liquid mixture through the meter test locations and on to the horizontal gas-liquid separator where it is then returned to the liquid-liquid separator. Stability of liquid density, gas composition, pressure, temperature and flow rate is monitored to determine steady state conditions. During each test point, a gas chromatograph obtains a sample of the natural gas on a 6-minute time interval. Using the average natural gas composition during the test point and the measured pressure and temperature at any given location in the test loop, the gas density at that location is determined using AGA-8. The composition of the gas has some seasonal variation with the methane composition ranging from approximately 83% to 95% during the year. The hydrocarbon liquid (ExxsolTM D80) is very similar to kerosene with less than 2 ppm sulfur. 7 Figure 7 -Sonar-Venturi flowmeter installed vertically in flow loop. Figure 7 shows the vertical installation of the Sonar-Venturi flowmeter in the 4-inch wet-gas flow loop. The flowmeter was mounted immediately downstream of a blind T. Measurement Contrast The flowmeter has two independent measurements -the Sonar velocity and the Venturi OP. It has been established (as evidenced in literature and through tests at multiple flow facilities by the authors) that both instruments measure dry-gas flow-rates very well. In wet-gas flow, it is desirable for each instrument to have an over-reading that is dependent primarily on liquid loading and minimally on other flow parameters such as gas Froude number and line pressure. A modified version of the de Leeuw correlation (developed for horizontal flows) was found to work very well and has been adopted for the Venturi. The basis for the Venturi over-reading (ORV) and subsequent correlation is OR V = ` S,aPnaren, (I ) ~g,ref with ORV = f,(X,Frg), (2) where the Lockhart-Martinelli parameter is defined herein, as: X = m` Pg . (3) m~ p, The over-reading correlation for the Sonar meter (ORS) was established based on the measured flow velocity and the liquid mass quality (LMQ): ORS = Qr,apparena . (4) ~t,ref ~t,apparent Vm`4 ~ (~) ORS = fl (LMQ, Frg) ; (6) LMQ = m` ~ (~) mt where V„z is the Sonar mixture velocity after applying the Reynolds calibration. A necessary condition for solving for both unknowns (i.e., total flow rate and liquid loading), is to have two independent equations that characterize ORV and ORS. A convenient way to quantify the independence of the over-reading characteristics is to depict the contrast (i.e., difference in slope) of both over-reading trends. The apparent nozzle gas flow rate and the apparent Sonar bulk flow rate were divided by the reference total flow rate and plotted against XLM in Fig. 8. The contrast between the two trends is what allows for a successful iterative solution for the unknowns. 1.35 1.2 R .. 0 ~ 1.15 ^ 9.r o 1.3 1.25 c 1.1 a a ~ 1.05 0 Q ~ e~' '° ------------- °o 1 0.95 0.9 ~- 0.00 0.02 0.04 0.06 0.08 Lockhart-Martinelli, [-] ^ Nozzle o Sonar 0.10 0.12 0.14 Figure 8 -Difference in slope between the over-reading trends of Sonar and Venturi reveals the contrast between the two devices in wet-gas flow. 9 10% m ~ 5% 3 0 ~v w c 0% 0 L W d W -5% -10% ^ 14 bars 0 27 bara + 55 bara .•••.±5% o + ++ •~ + ^ + + ++ + 0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2 Lockhart-Martinelli, [-] Figure 9 -Total flow rate relative error for wet gas. Figure 9 shows the total flow rate relative error predicted over all test pressures for the Sonar- Venturi flowmeter. Total flow rate is predicted well within ~5% for the test points across the full range of Lockhart-Martinelli parameter tested. The gas flow rate relative error is shown in Fig. 10. As expected, the gas rate performance follows the total flow rate since the liquid content by volume is negligible for a majority of the test matrix. 10% m ... ~ 5% 3 0 y !6 ~ 0% •L W d Y d -5% 0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 Lockhart-Martinelli, [-] -10% ^ 14 bara 0 28 bara + 55 bara ----~±5% ~ + + ~~ ~ ^ + ++ + Figure 10 -Gas flow rate relative error for wet gas. 0.2 10 40% 30% a~ 3 20% O -LLp 10% 3 O' ~ 0% .` O W -10% d R -20% ^ 14 bara 0 28 bara + 55 bara ....-. o + # 20 % + ~ ^ dF # g ~ $ + + + {' $+ * + + + -30% -40% ~ 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2 Lockhart-Martinelli, [-] Figure 11-Liquid flow rate relative error for API Type II wet gas. Figure 11 shows the relative error in liquid flow rate for API Type II wet gas, defined by having XLM > 0.02. The dashed lines show that most of the points are contained within a f20% relative error band. Figure 12 shows the error in liquid flow rate for API Type Iwet-gas flows, where XLM < 0.02. In this case the data has been presented in absolute terms and is shown to be within X0.5 m3/hr. 1.0 s E 0.5 o: 3 0 a ~ 0.0 J C O W :; -0.5 0 N Q -1.0 ^ 14 bara 0 28 bara + + 55 bara + + + + ~~ + + + + ~ + + .......................................................................................ft...----- 0 0.005 0.01 0.015 Lockhart-Martinelli, [-] Figure 12 -Liquid flow rate absolute delta for Type I wet gas. 0.02 11 1.5 ~ 1.0 E m 0 3 0.5 0 ~ 0.0 J C .` O w` -0.5 d .. 3 0 y Q -1.0 -1.5 ^ 97%<GVF<99% D 99%<GVF<99.6% ^ ^ + 99.6%<GVF<100% ^ p+ ^D --------------- o ,p + + + ++ + + Q I~ ~ ^ 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Water cut, [-] Figure 13 -Error in liquid flow rate prediction vs. water cut. Figure 13 shows the effect of water cut on the measured liquid flow rate demonstrating that there is no discernable effect of liquid viscosity and to a certain degree density. MULTIPHASE TESTS The Sonar-Venturi is primarily designed for wet-gas flow; however, it was also tested at NEL to evaluate the performance in off-design conditions. An extension of the wet-gas iterative solution described above was devised for resolving the liquid and gas flow rates under multiphase flow conditions. While analogous ORS and ORV concepts are used in characterizing the multiphase response of the single phase devices, the defmitions of these quantities as well as their correlating parameters are different from the ones used for wet gas. The ORV in multiphase flows follows published methods and is analogous to variations in discharge coefficient in multiphase flow conditions.g'9 The Sonar over-reading was characterized in a form similar to the wet-gas methodology. No refinement was attempted for this first evaluation of multiphase performance and no effort was made to asymptotically match the multiphase and wet-gas models. 12 Figure 13 -Sonar-Venturi flowmeter at NEL multiphase test facility. The gamma densitometer in picture is for R&D only and has not been used in the Sonar-Venturi flowmeter calculations. The results were categorized using three gas volume fraction (GVF) ranges namely 0<GVF<60%, 60<GVF<80%, and 80<GVF<97.5%. It is worth emphasizing that even the highest GVF in this facility does not constitute wet-gas flows and that intermittent flow conditions occurs at all GVF above 30%. 400 350 300 r E 250 ~ 200 3 0 150 0 100 ,+ + + p ~+ ~o+~" +~ 'o * *. -+~ ,~-, Reference --- ±20% 50 0 0 50 100 150 200 250 300 350 400 Reference Total Flow Rate, [m'/h] Figure 14 -Total flow rate in multiphase Figure 14 shows the total flow rate for all GVFs ranging from 0 to 100% and all water cuts ranging from 5 to 75%. It can be seen that the total flow rate is predicted to within X20% for GVF<80%, however, at higher GVF the measurement is erratic. The velocity reported by Sonar at these 13 conditions is not deemed representative as a time-averaged total flow rate. Further refinement of Sonar processing is required to resolve these flow conditions accurately. 120 100 t 80 ai R ~ 60 3 0 v a 40 J 20 0 '~ T ' 0 20 40 60 80 100 120 Reference Liquid Flow Rate, [m'/h] Figure 15 -Liquid flow rate in multiphase. Similar to the total flow rate, Fig. 15 shows that liquid flow rate is measured to within 20% for GVF<80%. The effect of the inaccurate Sonar velocity between 80 and 97.5% GVF exacerbates the liquid error. 400 300 L ~ 250 ~ 200 350 3 0 y 150 R C7 100 50 O O 0 v' o~ ' ~, o.' ~~ Q' v 0%<GVF<60% n 60%<GVF<80% + 80%<GVF<100% Reference --- t 10% -' + +, -' + + + -++ ++ ~+ + 0 n°# ~, nE ± ~~n $ ,~ ° '+ ~+ 0 0%<GVF<60% 0 60%<GVF<80% + 80%<GVF<100% Reference --- t20% 0~ 0 50 100 150 200 250 300 350 400 Reference Gas Flow Rate, [m'/h] Figure 16 -Gas flow rate in multiphase. 14 Figure 16 shows the gas flow rate. The gas rate is predicted to within 20% between 60 and 80% GVF, but larger errors are prevalent at lower GVF. Again, the measurement performance between 80 and 97.5% GVF is reduced due to low accuracy of the Sonar in this regime to the widely time- varying properties of the flow. Currently Sonar algorithms do not attempt to capture transient properties, but is rather reporting volumetric and time-averaged flow properties. It is worth noting that the Sonar processing algorithms can readily identify the slugs and offer potential to calculate both slug and bubble velocity and volume. CONCLUSIONS The Sonar-Venturi-(Red Eye) flowmeter constitutes ahigh-accuracy top-side evolution of the downhole fiber-optic flowmeter technology. The flowmeter combines Sonar sensors with an extended throat Venturi that enables measurement of liquid and gas rates in wet-gas and multiphase flows. Addition of a Red Eye 2G water cut meter enables distinction of oil/condensate and water. This flowmeter has been tested in a range of wet-gas and multiphase flow conditions at CEESI and NEL where it was found that for wet-gas flows the total and gas flow rates are measured to within ~5% and liquid rate is determined to be within X20% in API Type II wet gas and X0.5 m3/hr in API Type I wet gas. In multiphase flows, liquid and total rates are predicted to better than X20% at GVF below 80%. In low pressure highly unsteady slugging flows, there is a reduction in Sonar measurement capability and hence the measurement performance is reduced. This was evident between 80 and 97.5% GVF in the multiphase facility. Additional work is required to improve the multiphase and especially Sonar performance in unsteady flow conditions. The Red Eye water cut meter has been demonstrated in other work to be within ~5% (absolute) over the full range of GVF and WLR and is not significantly affected by slugging flow conditions. ACKNOWLEDGEMENTS The authors gratefully acknowledge BP Exploration Operating Company Intl. for permission to present this work. We would also like to thank directly or indirectly contributed to this work. NOMENCLATURE Acronyms and Symbols A = Area, [m2] API = American Petroleum Institute CEESI = Colorado Engineering Experiment Station, Inc f = Function Fr = Densimetric Froude Number, [-] GVF = Gas Volume Fraction, [-] LMQ = Liquid Mass Quality m = Mass flow rate, [kg/s] NEL = National Engineering Laboratory NIR = Near-Infrared ORS = Over-Reading Sonar, [-] ORV = Over-Reading Venturi, [-] Q = Volumetric Flow Rate, [m3/s], [m3/hr] V = Velocity, [m/s] WLR = Water Liquid Ratio, [-] Limited and Weatherford our co-workers who have 15 XLM = Lockhart-Martinelli parameter, [-] OP = Differential Pressure, [bar] Subscripts g = Gas 1 = Liquid m = Mixture s = Superficial t = Total REFERENCES [ 1 ] "State of the Art Multiphase Flow Metering" API Publication 2566, First Edition, May 2004. [2] Hall, A., Lievois, J., and Adejuyigbe, B., "Testing of the Red Eye Near-Infrared Water Cut Monitor for Application as a Water Cut Sensor in Multiphase Flow Conditions," Multiphase Pumping and Technologies, International Conference & Exhibition, Abu Dhabi, 10-14 February 2007. [3] Kragas, T.K., Johansen, E.S., Hassanali, H., and Da Costa, S. L.: "Installation and Data Analysis of a Downhole, Fiber Optic Flowmeter at BP's Mahogany Field, Offshore Trinidad," SPE 81018, SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of- Spain, 27-30 Apri12003. [4] Johansen, E. S., Kragas, T. K. and Beaumont, P., "Downhole Fiber Optic 3-Phase Flowmeter Field Test at BP Mungo," 21st North Sea Flow Measurement Workshop, T,ansberg, 28-30 October 2003. [5] Sandoy B., et al. "Improved Reservoir Management with Intelligent Multi-Zone WAG Injectors and Downhole Optical Flow Monitoring," SPE 95843, SPE Annual Technical Conference and Exhibition Dallas, 9-12 October 2005. [6] De Leeuw R., "Liquid Correction of Venturi Meter Readings in Wet-gas Flow", North Sea Workshop 1997. [7] Stewart, D., et al. "Wet-gas Venturi Metering" North Sea Flow Measurement Workshop, Tonsberg, Norway, 2003. [8] Hall, A.R.W., Reader-Harris, M.J. and Millington, B.C., "A Study of the Performance of Venturi Meters in Multiphase Flow," 2nd International Conference on Multiphase Technology, Banff, 22 June 2000. [9] Vilagines, R. and Hall, A.R.W., "Comparative Behaviour of Multiphase Flowmeter Test Facilities," Oil and Gas Science Technology, Vol. 58, No. 6, pp. 647-657, 2003. 16 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn -Stn March 2007 Testing of the Red Eye Near-Infrared Water Cut Monitor in High GVF Multiphase Flow Conditions Andrew Hall, BP Exploration 8~ Production John Lievois, eProduction Solutions Babajide Adejuyigbe, eProduction Solutions INTRODUCTION Near infra-red spectroscopy is a well-known technique for chemical analysis and has been successfully applied to measurement of small quantities of water in a variety of media, such as paper, methanol, tobacco, etc. The Red Eye® 2G water cut monitor was developed to exploit the very characteristic attenuation of infra-red light by water as a means to measure the water cut in mixtures of oil and water. The water cut monitor uses four specific NIR wavelengths to provide a capability for water cut measurement across the full range from 0% to 100%. The monitor was known to operate reliably in the presence of a small quantity of free gas (up to 20%) from previous tests, and the purpose of this new test programme was to evaluate the capability of the instrument to operate in much higher gas volume fraction environments. This paper presents new data obtained in three test campaigns at the TUV NEL multiphase flow facility. The tests spanned the full range of water cuts from 0% to 100%, at a range of fluid mixture velocities, and with gas volume fractions in the 60% to 95% range. Most tests were for meters in a horizontal orientation, but some additional tests were included in vertical flow. The results exceeded expectations of water cut measurement uncertainty at these high gas fraction conditions, with very little dependence of the uncertainty on GVF. 2 RED EYE WATER CUT MONITOR 2.1 Description of the meter The Red Eye water cut measurement is based on near-infrared absorption spectroscopy. As shown in Figure 1, the dependence of absorption of near-infrared light on wavelength varies with the composition. At several key wavelengths, infrared light absorption is dependent on the behaviour of carbon-hydrogen and oxygen-hydrogen bonds in the molecules. Water, contains O-H bonds and hydrocarbons do not, therefore allowing infrared absorption to distinguish water from organic molecules. Furthermore, the characteristic wavelength associated with bending of the H-O-H bond in water is different from the wavelength associated with O-H bond stretch, so there exists the potential for water to be distinguished from other molecules, such as methanol, containing O-H bonds. The Red Eye 2G water cut meter extends the performance of the earlier 1 G meter, which used a single wavelength, to allow more accurate measurements of water cut at lower water- cut, by simultaneously measuring multiple wavelengths that include both the water and oil absorbent peaks. Scattering effects caused by emulsions, sand, or gas bubbles, are expected to have the same effect at all wavelengths and as such can be eliminated. Furthermore, changing salinity should have no effect on the measurement, since the water absorption is based on the water molecule itself, not what is dissolved in the water. The internal design of the meter is shown in Figure 2. The meter consists of a probe which is inserted into the flow either through a 1-inch NPT tapping or using a 1%2-inch flanged connection and an electronics module mounted directly onto the probe. The only external connections required are for power (10 to 30 V DC @ 8 W) and output signal (4-20 mA analogue or RS-485 MODBUS outputs). 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn -Stn March 2007 The main measurement section within the insertion probe has a small gap, with an infrared source on one side and detector consisting of a fibre optic bundle on the other. Between the optical source and detector and the process fluids are sapphire windows for their optical and mechanical properties including abrasion resistance. 2.2 High gas fraction test philosophy The meter had previously been tested at gas volume fractions up to about 20% GVF, demonstrating that gas at this level had only a minimal effect on the water cut measurement. However, the meter had never been tested at higher gas fractions prior to the BP test in August 2005. Initially this test, simultaneous with testing of other equipment, was just intended to explore the impact of high gas fractions on the meter, with no preconceived expectations of its performance under these conditions. 2.3 Installation of meters and test matrices The Red Eye meter was tested in horizontal and vertical flow without a mixer in August 2005; in a horizontal orientation with a static mixer immediately upstream of the Red Eye meter in February 2006; and in horizontal flow, without a mixer but in a pipe spool of restricted diameter (2.4 inch in a test line of 4 inch diameter) in November 2006. The meters were located approximately 80 feet downstream of the inlet to the multiphase test section. The test section adjacent to the meter was instrumented with a pressure transmitter and a platinum resistance thermocouple. These instruments provided the reference pressure and temperature measurements for correction of the reference gas volumetric flowrate to actual meter conditions at the Red Eye meter. The August 2005 horizontal flow test was conducted in series with another meter undergoing a performance test, and so the test matrix was determined by the requirements for the FAT, which required high flowrates. Tests were conducted at 5%, 25%, 40% and 100% water cut. The reason for testing at 100% water cut was to allow testing at high liquid flowrates. The schedule was also very tight, because of the need to deliver the meter to its field installation, and this did not allow additional time in this configuration for conducting further tests. Several other meters were also included in this test including a Weatherford sonar flow meter (also shown in Figure 3). The August 2005 vertical flow test was conducted immediately following the horizontal test, but with the commercial multiphase meter removed from the test line. Tests were conducted at 5%, 75% and 90% water cut. Following encouraging results obtained in the August 2005 campaign, it was decided to conduct a more systematic test, concentrating on the Red Eye meter alone. This was installed in February 2006, once again in a horizontal orientation, shown in Figure 5, and a test matrix was designed which spanned the previous tests, but now included more intermediate water cuts. The water cuts tested were 5%, 25%, 40%, 50%, 60%, 75%, 82.5%, 87.5%, 90%, 92.5%, 95% and 97.5%. It would also have been desirable to include some tests between 5% and 25%, but these conditions are difficult to set up and control in this flow facility. An additional test was conducted in November 2006 of other equipment, with a Red Eye meter included as part of the test, to maximise utilisation of the test facility. The water cuts tested were 5%, 25%, 40%, 50%, 60%, 75%, 90% and 100%, covering roughly the same ranges of conditions as the previous test. Figure 7 shows the planned and actual test matrices for both the 2005 and 2006 test programmes. 2.4 Reference system (TUV NEL multiphase flow test facility) The TUV NEL multiphase flow facility is located in the James Young Building in East Kilbride, near Glasgow, Scotland. This site is also the location of the UK National Standards for flow measurement (oil, water and gas standards). The TUV NEL multiphase flow facility consists of a 250 barrel separator which is filled with the water and oil phases. Nitrogen gas is generated on demand by evaporation of liquid nitrogen 2 6t" South East Asia Hydrocarbon Flow Measurement Workshop 7t" -Stn March 2007 which is stored in a 40m3 tank. The nitrogen is used on a one-pass basis and is exhausted to atmosphere at the outlet of the separator. The oil is metered though Faure-Herman helicoidal turbine meters, either 1'/z-inch or 3-inch depending on the flowrate required. These meters are calibrated in the UK National Standard gravimetric oil calibration facility at TUV NEL, using oil of an appropriate viscosity. The water is metered through standard flat-bladed turbine meters, either 1'/~-inch or 3-inch depending on the flowrate required. These meters are calibrated in the UK National Standard gravimetric water calibration facility at TUV NEL, using fresh water. The gas is metered through standard flat-bladed turbine meters, either'/2-inch, 1-inch or 3- inch depending on the flowrate required. The '/-inch meter was not used for these tests. These meters are calibrated in the UK National Standard gravimetric gas calibration facility at TUV NEL, using air. Both the oil and the water phases can be cross-contaminated with a small proportion of the other phase, due to limitations of the separator capacity. Generally the cross-contamination becomes most noticeable at higher liquid flowrates when the water cut is in the range 25% to 50%. The water content of the oil stream is detected using acapacitance-based water-in-oil monitor. This is specifically calibrated on the fluids in the test facility, and gives an uncertainty in the water cut of the oil stream of less than ±1 % absolute. The oil content of the water stream is detected using aCoriolis-based densitometer. This takes as an input the density of the oil and water as a function of temperature, and the temperature-corrected reading from the densitometer is used to calculate the oil content. This gives an uncertainty in water cut of the water stream of less than ±1 % absolute. Extensive testing at TUV NEL has demonstrated that the cross-contamination of the liquid streams has a negligible impact on the turbine meter accuracy over the ranges encountered. Tests have also shown that there is no dissolved gas in the separator outlets, and as the gas is generated from pure liquid nitrogen, it is completely dry at the reference gas flowmeters. Since the flows are metered on a volumetric basis, the temperature of the oil and water, and the temperature and pressure of the gas, is measured at the flowmeters. The volumetric flowrates are corrected to the measured temperature and pressure at the location of the test meter in the multiphase flow line to give the correct volumetric flowrates at the test meter at line conditions. 2.5 Fluid properties The fluids used were stabilised crude oil, salt water and nitrogen gas. The crude oil is topped to remove high volatility components, and mixed with kerosine in approximate proportions of 70% crude to 30% kerosine to restore the original viscosity. The crude oil is a mixture of crudes from different North Sea oil fields, including Forties, Beryl and Oseberg crudes. The density and viscosity of the crude oil mixture are periodically measured as a function of temperature The salt water phase consists of a solution of magnesium sulphate (MgSO4). This salt was selected by TUV NEL to avoid (or minimise) corrosion of pipework. It is important that the water phase has salinity similar to the application conditions, both for electrical type meters (capacitance /conductivity /microwave) and for dual-energy gamma densitometers. The concentration of the water phase is calculated from its density, which is periodically measured as a function of temperature. The water density is normally measured immediately before a test programme, as the density gradually changes due to evaporation of water. The gas phase is nitrogen. The density of nitrogen can be estimated with sufficient accuracy at the low operating pressure using the ideal gas equation, with a gas molecular weight of 28. TUV NEL uses a more exact equation of state for reference flowrate calculation. 3 6~n South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ Stn March 2007 2.6 Calibration of the Red Eye meters The Red Eye meters were calibrated by flowing single phase oil and single phase water through the meters prior to starting the multiphase flow tests. Manual intervention was required during the tests to select the optimum combination of wavelengths depending on the water cut, 2 out of the 4 wavelengths being used for any one measurement. This process is somewhat automated in the standard (water-oil) model, but had not been fully implemented for high GVF operation. However, since the exact reference data was not available to the meter operator at the time of the tests, the water cut algorithm selection was necessarily based on the readings from the Red Eye itself, as it would be in an operating situation. 2.7 Data recording and processing The test facility was run until the flow was sufficiently stable to perform a test. Since the test conditions were almost all in the slug flow regime the operator's experience was relied on to determine this stability time. Typically it took less than 5 minutes between test conditions. Each test condition was recorded for a period of 5 minutes, with the Red Eye set up to record data at 1 second intervals. The Red Eye data files included time, water cut and four infrared absorption figures. Only the water cut was used for further data analysis by BP. An average was taken of the water cut over the test, along with standard deviation and confidence to check for data quality. TUV NEL provided data for oil flowrate (litres/sec), water flowrate (litres/sec), gas flowrate (litres/sec), temperature (°C) and pressure (barg). Again the measurement was provided for the 5 minute period of the test, calculated from 100 three-second samples of the reference readings. All data was reported from the meter at line conditions, i.e. at the temperature and pressure at the multiphase meter. No reference data from TUV NEL was provided to Weatherford during the tests. 3 TEST RESULTS 3.1 Meter results: 2005 test campaign Figure 10 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal and vertical flow tests conducted in August 2005. Figure 11 shows the error in these measurements plotted against the reference gas volume fraction and Figure 12 shows the error in water cut measurements plotted against the reference water cut. Overall the water cut measurements were within about ±5% of the reference values, with a tendency to under-read water cut. It was not clear at this stage whether this was due to the particular water cuts selected for testing, or a slight non-uniform distribution of the oil and water in the horizontal pipe, and therefore further testing was required. 3.2 Meter results: February 2006 test campaign Figure 13 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal tests conducted in February 2006. Figure 14 shows the error in these measurements plotted against the reference gas volume fraction and Figure 15 shows the error in water cut measurements plotted against the reference water cut. With the exception of the tests at around 60% water cut, all the water cut measurements were within about ±5% of the reference values. There is a quite clear variation of the errors in water cut measurement with water cut, with the abrupt switches in errors at different water cuts across the range related to the selection of pairs of wavelengths used to determine water cut; it is likely this could be optimised to improve the measurements. There is a much smaller variation with GVF, and although this is not clear from Figure 14, it is best demonstrated by plotting results for individual water cuts against GVF, as shown in the next section. 4 6t" South East Asia Hydrocarbon Flow Measurement Workshop 7m - 9~n March 2007 3.2 Meter results: November 2006 test campaign Figure 16 shows the water cut measurement from the Red Eye meters against the reference water cut for the horizontal tests conducted in November 2006. Figure 17 shows the error in these measurements plotted against the reference gas volume fraction and Figure 18 shows the error in water cut measurements plotted against the reference water cut. The key difference between these tests and the tests conducted earlier in the year is an improvement in the mid-range water cut measurement (50% and 60% water cut). This improvement is a result of algorithm development, with no change to the meter hardware. Using the improved interpretation algorithm, all the water cut measurements were within about ±5% of the reference values. 3.3 Meter results: comparison of 2005 and 2006 test campaigns Figure 19 shows the water cut measurements from the Red Eye meters against the reference water cut for the test campaigns in August 2005 and February and November 2006. Figure 20 shows the error in these measurements plotted against the reference gas volume fraction and Figure 21 shows the error in water cut measurements plotted against the reference water cut. Apart from the measurements at the lowest water cuts, and at 50% and 60% water cut, these figures show the good consistency between the results from both test campaigns, suggesting that there is limited impact of a static mixer in multiphase flow conditions. The differences at 50% and 60% water cut are a result of the improved interpretation algorithm. Figure 22 to Figure 34 show the water cut measurement errors plotted against GVF for each individual water cut range. These plots quite clearly show the limited scatter in the water cut errors as a function of GVF, and also the good consistency between the results from the two test campaigns. At each specific water cut there is a scatter of only t1 or 2% in the water cut errors, up to GVF values over 90%. 4 CONCLUSIONS The test results show that the principal influence on the water cut measurement accuracy under these multiphase flow conditions is the water cut itself, with a relatively small influence of the gas fraction. Typically at any particular water cut there is a scatter of about ±2% in the water cut errors across a range of gas fractions from 70% to 95%. No other in-line multiphase flowmeter (without full or partial separation) is able to measure water cut within a scatter of ±2%, particularly at high water cuts, under these conditions of high gas volume fraction. The tests have also shown that there is a relatively limited impact of the presence of a static mixer on the test results, or of the orientation of the meter (horizontal or vertical). While these tests show that good measurements of water cut can be obtained in high gas fraction multiphase flow conditions, it should be noted that the gas phase used in the tests was nitrogen, which is completely transparent to infra-red light at these wavelengths. It is expected that hydrocarbon gas will have an impact on the measurement, and the meter should therefore be tested in a test facility using hydrocarbon gas. A secondary evaluation also needs to be conducted to determine the impact of alcohols (methanol, etc.) on the water cut measurement. These test programmes were conducted over short timescales in an ideal laboratory environment with well characterised and `clean' fluids. It is recommended that further data is obtained for the longer term performance of the meter in the laboratory and more importantly in real production fluids. 5 ACKNOWLEDGEMENTS The test work at TUV NEL and analysis of the test results was funded by a BP subsea metering technology project. The Red Eye meters and support personnel for the test programme were provided by eProduction Solutions. The support of both organisations and their permission to publish this work is gratefully acknowledged. 5 6~h South East Asia Hydrocarbon Flow Measurement Workshop 7`h - 9~h March 2007 Figure 1: Near-infrared absorption spectrum ~~\ Fiber Optic Bundle collector apties Probe assembly Sapphire window Sapphire Window NIR Emitter Figure 2: Red Eye water cut meter cross-section 6~n South East Asia Hydrocarbon Flow Measurement Workshop 7m _ 9cn March 2007 Figure 3: Red Eye meter installation (August 2005 horizontal test) Figure 4: Red Eye meter installation (August 2005 vertical test) 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ 9m March 2007 Figure 5: Red Eye meter installation (February 2006 test) Figure 6: Red Eye meter installation (November 2006 test) 6~n South East Asia Hydrocarbon Flow Measurement Workshop 7tn - 9~n March 2007 5% water cut z0 ao 60 BO t0 7 t20 1I 0 t60 +a o GHwizareai, quo 3005 O Veni®i. quo 2005 •non:oM.t Fee zao6 4 • • 1P• Nov zoos • eG • • G ar • •o •9 • eG Oe••[I •• ^ l ^ Do O O e o e e s ao 0 o +o zo m as so 6a )6 m eo +oo GVF (%) 40% water cut 9 ~ .~,~. Feb 8666 ~ 26 NOV 2008 . . . . . ...... ~ 60 ~ r • i io s ~zo +a o Leo - +6 0 0 10 20 b a0 50 60 )0 BO 90 +W GVF (%) 60% water cut ~ 66 ~ 26 ~ fio E 25% water cut GHmzaM•i, quo A06 2.0 •HenzoNai. Fen 2008 •NwvoNel, w.zoo6 • r ao 8.0 • 10.0 12.0 40 iB 0 10 ZO 30 00 50 60 10 BO 80 tOD GVF (%) 50% water cut ~ ~~ oNe,:om.i, quo zoos . w,roe~.i. Fee zoos . HwveMl. Nov 2006 .. . ~ •o •p +p a• _- - - - c • o • • o i c • o •o 0 0 ~ so ~s eo F roo s +2 0 +. a +e o +e o 0 10 20 3o a0 6a BO 10 60 0p 100 GVF 1%1 75% water cut S` 4 e Ve6a. Au0 2666 20 .NmzoMSi. Fen 2008 rb~. NOV 2006 e •e • w r •a ao -_ ___- - e - 6 • .~- ~-• eo +o 0 +z o uo mo 0 10 ZO 30 40 50 80 )0 BO BO tW 0 10 30 30 a0 60 60 )0 BO W 100 GVF (%) GVF (%) Figure 7: Test matrices for TUV NEL test (August 2005, February 2006, November 2006) 9 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn _ Stn March 2007 82.5% water cut P 1 87.5% water cut 0 10 10 30 a0 BO )0 80 90 100 0 10 20 b a0 50 60 )0 BO 90 100 OVF (X) GVF (X) 90% water cut 92.5% water cut ~ ~~ 3 6 5 fia F 10 4 u tB 0 e . rai. FU02W5 Monren.,. .61006 Ma. rw. mofi • s ~. ... • . ° 0 • b e ~ ~~ $ 10 6 fi0 E t00 ~S u0 1B0 1B0 t C 1 1 0 10 10 30 d0 80 10 BO 90 100 1 GVF (X) 95% water cut ~ ~~ 10 60 % 80 X 0 t0 20 30 d0 50 60 10 80 BO 100 GVF ~) 16 .1~,~6•. Fm 1666 6 -- . 00 do 60 - -- - 10 10 b d0 50 BO 70 80 BO 100 GVF(%) 97.5% water cut u •Fbnx6mN. Fe61006 34 .a 80 BO --__ -- - _- • i --i 13.0 1d 0 t60 t0 10 30 d0 50 60 10 80 90 100 GVF (%) 100% water cut "" O116nz6rl•i. /up 1005 10 ~~~ . 0 •I16nz6r0•i. Fe61006 •G s • d •G o ~ 6 ___ n- .o . o• •~ 0 0 eo C 100 0 0 uo 0 160 0 0 0 0 o G c 1 0 10 1o m do bo 10 6o w 100 GVF (%) 10 6`n South East Asia Hydrocarbon Flow Measurement Workshop 7`n - 9`n March 2007 '=''>'~ii~' _- l art ~~ .an-.c ~~^~ ~~~~ I l~ a l~~ ._ _ lsrwe`c ,` h~ -+._` . ...~«. Figure 8: Location of multiphase flow meter test facility Pressur a and Three phase separ~ or f I ow coat rol Liquid Test meter nitrogen R~ere-~ce metering Pump Pump Test meter Gas Figure 9: Schematic of TUV NEL multiphase flow test facility ;zr 11 6cn South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ Stn March 2007 100 90 80 70 - - - +/- 5 % absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical 0 ,o .ifc ~. °. +. 60 v :: 50 3 ;; 40 Cd G 30 20 10 0 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 10: Red Eye water cut vs. reference water cut (2005 multiphase flow tests) 25 20 d U a~i 15 d w m ~ 10 O w d 5 O ~ 0 ~a °-- -5 O - - - +/- 5 % absolute error n Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical x x x x x x ----------- - xx x ------------------- - X --~c--~X---a x ----x-XXx- ------ x x x o o xx x o xx xx o o ~ x x x x ~ o 0o_~j X oo~ox x~~ a o°x '$o a o n-----o ----- ~ D ~ m -10 v y -15 is 3 -20 -25 I I I r i I I I I I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 11: Red Eye water cut error vs. reference GVF (2005 multiphase flow tests) 12 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn - 9~n March 2007 zs 20 d V a~i 15 m w m ~ 10 w y 5 0 ~ 0 °•- -5 0 m -10 - - - +/- 5 % absolute ertor ^ Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical o x ~ ^ o~ ^ 3 V y -15 is -20 -25 I h i I F I I I I~ 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 12: Red Eye water cut error vs. reference water cut (2005 multiphase flow tests) 100 90 80 70 .. 60 3 d 50 m 3 d 40 d 30 20 10 0 - - - +/~ 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal i~ ti r~ ~ • .~ '• ~ • • 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 13: Red Eye water cut vs. reference water cut (February 2006 multiphase flow tests) 13 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn -Stn March 2007 2s 20 m V a~i 15 m w m E 10 0 y 5 3 0 a 0 m °- -5 O m -10 v m -15 is -20 -25 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal • • • --- --------------------------- --- •~•- • t • ~• ••• •••'!'•~ ~ • • • • • •• •• • • •• • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 14: Red Eye water cut error vs. reference GVF (February 2006 multiphase flow tests) 2s 20 d U d 15 w d ~ 10 0 w 5 .d. a 0 ~o °- -5 O m -10 3 v ~`y~ -15 -20 -25 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal --------------------------- ---------- ---- -- ------• ~ -- -- . • ~ t ~ M ~ • : • • •• ~ > • • i • • ------------ ------------- • • •r ~ t : y 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 15: Red Eye water cut error vs. reference water cut (February 2006 multiphase flow tests) 14 6`h South East Asia Hydrocarbon Flow Measurement Workshop 7tn _ gin March 2007 100 90 80 70 0 - - - +/- 5 % absolute ertor • Red Eye 2G, NEL, Nov 2006, Horizontal w N~ ~• •~j / .• ~ / •~ •~. -• ~~ •' 60 3 V ~ 50 t0 3 40 d 30 20 10 0 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 16: Red Eye water cut vs. reference water cut (November 2006 multiphase flow tests) 2s 20 m V a~i 15 d w ar ~ 10 O w d 5 a 0 e -5 0 m -10 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Nov 2006, Horizontal -------------------------------------- 1--- ~• • •~ •~ •• s• ~ t~ ••• •ri-• •'- ~ •i •~-~-j-•••v---- v `y -15 .. w -20 -25 I I I I I I I I I F 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 17: Red Eye water cut error vs. reference GVF (November 2006 multiphase flow tests) 15 6'h South East Asia Hydrocarbon Flow Measurement Workshop 7`h - 9"' March 2007 25 20 m V a~i 15 d w m ~ 10 O w d 5 a 0 ca 0 -5 0 m -10 - - - +/_ 5 % absolute error • Red Eye 2G, NEL, Nov 2006, Horizontal ` • • • • • •• • ~ • • _• r=- • • •Z•• ~~ •- •• • v `y -15 is -20 -25 ! I i I I I ! I ~ I 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 18: Red Eye water cut error vs. reference water cut (November 2006 multiphase flow tests) 100 90 80 70 °.. ~ 60 v :: 50 3 d 40 m 30 20 10 0 - - - +/- 5% absolute error ^ Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical ~i~ • Red Eye 2G, NEL, Feb 2006, Horizontal •. • Red Eye 2G, NEL, Nov 2006, Horizontal ~ ~ • .• ~ •` j , • -~ '• ~ • • .• .o .~ ~ . 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 19: Red Eye water cut vs. reference water cut (2005 and 2006 multiphase flow tests) 16 6th South East Asia Hydrocarbon Flow Measurement Workshop 7tn _ Stn March 2007 25 20 d V y 15 d d ~ 10 O w d 5 3 ~ ~ ~- -5 0 d -10 3 U y -15 IC -20 -25 - - - +/- 5% absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal x x x •x » x xx _ x • - -----------------------X --~ ~ ~--~Y---~•x~~ ,,• -~--- x o •Kot ~ ik• wo ~•••~~ • i• • • x x x x tlPx ~ • • -------------------------- ~ o ~ ~o ~ oo • ~ • o i • --- ~v-- •• o b ~0.3 • • • ~ ••b•• • •• •• • • • • 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 20: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests) 25 20 d V a~i 15 d w d E 10 0 y 5 3 a ~ ~a °- -s 0 d -10 v d -15 is =20 -25 - - - +/- 5 % absolute error ~ Red Eye 2G, NEL, Aug 2005, Horizontal X Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal --------------~-------- --o • • .s . •• -- ------ t y 0 10 20 30 40 50 60 70 80 90 100 Reference water cut (%) Figure 21: Red Eye water cut error vs. reference water cut (2005 and 2006 multiphase flow tests) 17 bin South East Asia Hydrocarbon Flow Measurement Workshop 7tn _ Stn March 2007 25 20 m V a~i 15 d w d ~ 10 O y 5 a 0 e -5 0 m -10 v - - - +/- 5 % absolute enor ^ Red Eye 2G, NEL, Aug 2005, Horizontal ~~ x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal x x x- --~--- xxx xx~c • x • j • ••• • x x x x x x ~ • ~ ^~ ° ^ 9 • • •• • •^ ^ ^ • ^ • ~~ o • ^ o ^ ------------------------ --------------v---- -o ------- ^ ------------ `m -15 m -20 -25 I I I I I r I- ~ i 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 22: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 5%water cut) 2s 20 d V aCi 15 d d ~ 10 0 w y 5 O a ~ w °-- -5 `O L at -10 - - - +l- 5 % absolute error ^ Red Eye 2G, NEL, Aug 2005, Horizontal • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal ^ ^ ^ • • o ^ • ^ N • t» •f • •• • • ^ • • 3 V y -15 -20 -25 1 I I t I t r I -I I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 23: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 25% water cut) 18 2s 20 d V 15 d w m ~ 10 0 w m 5 3 O ~ 0 to ~- -5 `o d -10 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn - Stn March 2007 - - - +/- 5% absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal • • • • • • t • • • • • • • • • • _• • •• • •• • • • • • 3 v d -15 io -20 -25 I I I I I ~ I I I I I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 24: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 40% water cut) 25 20 d V aci 15 d d £ 10 0 w d 5 3 0 a 0 ro \° °... -$ O d -10 - - - +/- 5 % absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal ------ • • • •- • • 0 p •• 00 • • o • ___________________________ ~ _o __f•____~_O_~~ 5~:~___ O • •~ • 3 v `m -15 .. -20 -25 A I I I I I I I I I I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 25: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 50% water cut) 19 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7`n -Stn March 2007 25 20 d V ati 15 m w m `~ 10 0 w y 5 _3 O a 0 w °- -5 0 d -10 3 V `y -15 -20 -25 - - +/- 5% absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal _. 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 26: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 60% water cut) 25 20 d V aCi 15 d d ~ 10 0 w m 5 a 0 m =- -5 - - - +/- 5% absolute error x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal ------- ------------------------ • • x X • ~t•z • X• • x --------------------- r- ~ - 0 d -10 v `y -15 io -20 -25 f I I I I I I I I ~ I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 27: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 75% water cut) 20 2s 20 d V a~i 15 d w m E 10 0 w y 5 0 Q 0 to - -5 O d -10 bin South East Asia Hydrocarbon Flow Measurement Workshop 7cn _ gin March 2007 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal .:~. 3 U d -15 is -20 -25 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 28: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 82.5% water cut) 25 20 m U a~i 15 w d ~ 10 O w as 5 0 a 0 co °- -s O d -10 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal - -------------------------------•-------I ----------------------- -------- 5.----~.+-- ~ i-~ =-~--~ - ____ • M 3 v y -15 is -20 -25 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 29: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 87.5% water cut) 21 6`n South East Asia Hydrocarbon Flow Measurement Workshop 7`n - 9`n March 2007 25 20 V a~i 15 d d ~ 10 0 w 5 Y _7 O N 0 a a °- -5 0 ~ -10 - - - +/- 5% absolute error x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal x x x x • xx x • • ----------------------- - - - - - - - - x --ic-- ---- X -----~--------- x • • X • 1• • • • • • • • -------------------------- v y -15 ... a -20 -25 I ~ I I ~ I ~ I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 30: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 90% water cut) 25 20 m V aCi 15 m w a> £ 10 0 w y 5 0 N Q A \° =- -5 - - - +/_ 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal O d -10 3 V d -15 .+ 3 -20 -25 ~ I i I i ! I I I I 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 31: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 92.5% water cut) 22 6th South East Asia Hydrocarbon Flow Measurement Workshop 7tn _ Stn March 2007 25 20 d V d 15 d w rv ~ 10 0 w y 5 ~. 3 O 0 y a °-- -5 O - - - +/- 5% absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal i . ~-i at -10 v d -15 is -20 -25 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 32: Red Eye water cut error vs. reference GVF (2006 multiphase flow tests at 95% water cut) 25 20 d V 15 d d ~ 10 0 y 5 3 O a 0 ~o -5 - - - +/- 5 % absolute error ^ Red Eye 2G, NEL, Aug 2005, Horizontal • Red Eye 2G, NEL, Feb 2006, Horizontal ^ ^ 0 `O m -10 3 v y -15 ea 3 -20 -2s 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 33: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 97.5% water cut) 23 6tn South East Asia Hydrocarbon Flow Measurement Workshop 7tn - 9~n March 2007 2s 20 d V aci 15 w d ~ 10 0 w y 5 Y 3 a ~ ~- -5 0 - - - +/- 5 % absolute error ~ Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical • Red Eye 2G, NEL, Nov 2006, Horizontal ~ o0 0 ~ o o ~ .. ° •• • • • • • ~ r - - - -- -------------------------~---~~---~--~ -~•--j- as -10 .. 3 V y -15 ., ~o -20 -25 + 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 34: Red Eye water cut error vs. reference GVF (2005 multiphase flow tests at 100% water cut) 24 Flomeko 2005 6 - 9 June 2005 CLAMP-ON, SONAR-BASED VOLUMETRIC FLOW RATE AND GAS VOLUME FRACTION MEASUREMENT FOR INDUSTRIAL APPLICATIONS Daniel L. Gysling, CiDRA Corporation Douglas H. Loose, CiDRA Corporation Alex M. van der Spek, ZDoor BV ABSTRACT A clamp-on, sonar-based flow measurement technology for simultaneously measuring volumetric flow rate and process fluid sound speed is described. The technology utilizes sonar array processing techniques to perform two independent measurements to characterize the process fluid, each well-suited for single and multiphase flows. Firstly, the meter provides mixture volumetric flow by tracking the speed at which naturally occurring flow-generated pressure fields convect past an array of strain-based sensors clamped-on to existing process pipe. Secondly, the meter provides compositional information by measuring the speed at which naturally occurring sound waves propagate through the process fluid using the same clamp-on sensors. Measuring the speed of sound of a process fluid utilizing this sonar technique is analogous to measuring process fluid density and has many compositional based applications. A primary example of this is using process sound speed to accurately measure the amount of entrained gases in liquid-continuous mixtures. The ability to measure volumetric flow and process sound speed reliably and accurately in single and multiphase applications with a non-intrusive, clamp-on device significantly enhances the observability of the many industrial processes. Data is presented from sonar- based volumetric flow and sound speed-based compositional measurements for a wide range of industrial applications, encompassing single phase liquid applications to large diameter, abrasive multiphase applications, widely-recognized as difficult, long-standing flow measurement challenges. 2 INTRODUCTION Volumetric flow is a critical measurement in process control and optimization for most industrial processes. The current industrial flow meter market is often classified into two technology-based categories: old technology and new technology. Old technology flow meters include flow measurement technologies that have been in use for more than 70 years, It includes turbine meters, orifice plates and variable area flow meters. The new technology flow meters include technologies which have emerged over the last 30-50 years. These new technologies typically offer advantages over the old technologies in performance, functionality, and reliability. The major types of new technology flow meters include ultrasonic meters, electromagnetic flow meters, vortex flow meters, and Coriolis flow meters. Each type has evolved to serve various aspects of the diverse range of applications within the industrial flow meter landscape. This paper describes sonar-based flow meter technology which utilizes sonar techniques' to listen to, and interpret, pressure fields generated by turbulent pipe flows. Sonar flow measurement technology represents a new class of industrial flow meters utilizing measurement principles distinct from existing technologies. Sonar flow meters were first introduced into the oil and gas industry in 1998 for use in downhole multiphase flow metering applicationsz 3. Sonar flow measurement technology is currently being used in other industries such as pulp and paper, mining and minerals, hydro transport, chemicals and power generation. Process aeration is often an unwanted but unavoidable phenomenon that negatively impacts product quality or the ability to accurately determine the rate of flow. For instance, entrained air in the thin stock flow to the headbox of a paper machine may lead to pin holes in the BI0197 RevB Flomeko 2005 6 - 9 June 2005 produced paper or worse still to a web break resulting in production loss. Entrained air in the paper and pulp industry is such a pervasive problem4 that both mechanical and chemical means are used to remove air from the process. Likewise in production of crude oil, gas carry under in the liquid outlet of a twophase separator impairs the measurement of the rate of net oil flow as the watercut meter is affected by the presence of free gas. It is well known that the resulting errors in the net oil rate can easily be 100% or more solely because of a small error in the watercut. Just as often, however, process aeration is an integral part of the production process and the air or gas content must be kept within certain limits. By way of example, the injection of a small amount of air in the hydrotransport pipe lines in oil sand processing initiates the separation of oil from sand. Likewise in the separation of rock from minerals in flotation cells, gas is sparged in at the bottom of the cell and the gas holdup in the cells must be controlled to optimize the gravity separation of rock from mineral. The sonar techniques that enable the interpretation of the naturally occurring pressure fields inside a pipe are also well suited to determine the velocity of propagation of acoustic pressure fields. The velocity of sound thus determined is a very sensitive indicator of process aeration and it offers a superior alternative to today's mechanical, sample taking analyzers. The methodology involves characterizing the speed at which coherent pressure waves, either vortical structures or acoustic pressure fields, convect past an axial array of sensors using beam-forming techniques developed over several decades for underwater acoustic applications. Since coherent vortical structures are an inherent feature of turbulent boundary layers, no internal geometry is required to generate these structures. Likewise, in the majority of industrial processes the proximity of pumps, compressors, valves or sharp bends ensures that no source of sound is required. The sonar-based measurement is therefore entirely passive and it can be performed using an array of strain based sensors mounted on the outside of the pipe. With no process-wetted hardware, the sonar flow measurement technology is well suited for the corrosive and abrasive slurries commonly encountered in many practical applications. FLOW RATE MEASUREMENT The overwhelming majority of industrial process flows involve turbulent flow. Turbulent fluctuations within the process flow govern many of the flow properties of practical interest including the pressure drop, heat transfer and mixing. For these reasons, turbulent pipe flows have been extensively studied over the years with roots back to Osbourne Reynolds and Lord Rayleigh in the late nineteenth century5. 3.1 Turbulent pipe flow For engineering applications, considering only the time averaged properties of turbulent flows is often sufficient for design purposes. For sonar flow metering technology, understanding the time averaged velocity profile in turbulent flow provides a means to interpret the relationship between speed at which coherent structures convect and the volumetrically averaged flow ~,,~ ~ r rate within a pipe. For turbulent _ ~°~ - ~: ~ .: ~ " ' ` ~ jt - _ flows, the time-averaged axial ~ ~;~ ~~ ~. ~ ~ ,,~, velocity varies with radial position, ' a." ,.: from zero the wall to a maximum at `~~ `~= ~ `""~ ~ ~ '~-' `°'~` the centerline of the pipe. The flow " ~ coH~~crtrtt n~a~s~~cri eiuncsa~ae~ near the wall is characterized by ~ ~ ~ ~, ~~ ~~ °~ ""~ ~ ~ steep velocity gradients and ~ '=~ ~. ~~; ~ x~~ transitions to relatively uniform core - ~ ~~ ~.~ ,, ~, flow near the center of the pipe. ""~ Figure 1 shows a representative ~ ~ schematic of a velocity profile and ~~~~~xw°~.,, ~ coherent vortical flow structures Figure 1: Coherent structures in turbulent pipe flows. present in fully developed turbulent pipe flow. BI0197 RevB 2 Flomeko 2005 6 - 9 June 2005 The vortical structures are superimposed over time averaged velocity profile within the pipe and contain temporally and spatially random fluctuations with magnitudes typically less than 10% percent of the mean flow velocity. The Reynolds number (Re), based on pipe diameter (D), characterizes many of the engineering properties of the flow. The Reynolds number is a non-dimensional ratio representing the relative importance of inertial forces to viscous forces within a flow: Pipe flows with Reynolds numbers exceeding a critical value, typically 2300, are turbulent. Those with Reynolds numbers below this value are laminar. The vast majority of flows in industrial processes is turbulent with Reynolds numbers far in excess of the critical value. In addition to demarcating a boundary between laminar and turbulent flow regimes, the Reynolds number is a similarity parameter for pipe flows, i.e. flows in geometrically similar pipes, scaled with radius, with the same Reynolds number are dynamically similars .Empirical studies have shown that velocity profiles in turbulent pipe flows are well represented by the 1 over nth power law: u(r) = 1- ~ to (1 ), U ( R) 0 90% 85% 0 80% 75% 70% with n ranging from 6 to 10 as a weak function of Reynolds number. From a measurement perspective, the volumetrically averaged flow velocity V (mean velocity) or the volume rate of flow divided by the pipe's internal cross- sectional area is of interest. The relation between the ratio V/Uo and the Reynolds number is shown in Figure 2, which is based upon the power law (1 ). Apparently the ratio of the mean flow velocity to the maximum velocity slightly increases from a little below 80% just above the critical Reynolds number for turbulent flow to greater than 85% at Reynolds numbers over one million. It must be stressed that, given the velocity profile (1 ), very little fluid is actually flowing at the mean flow velocity. 1. E+03 1. E+04 1. E+05 1. E+06 1. E+07 Reynolds number Figure 2: Mean velocity normalized by Maximum velocity vs. Reynolds number. 3.2 Coherent turbulent structures Turbulent pipes flows are highly complex flows. Predicting the details of any turbulent flow is one of nature's great-unsolved problems. However, much is known regarding the statistical properties of the flow. For instance, turbulent pipe flows contain self-generating, coherent vortical structures often termed "turbulent eddies". The maximum length scale of these eddies is scales with the diameter of the pipe. These structures remain coherent for several pipe diameters downstream, eventually breaking down into progressively smaller eddies until the energy is dissipated by viscous effects. Experimental investigations have established that eddies generated within turbulent boundary layers convect at roughly 80% of maximum flow velocity. For pipe flows, this implies that turbulent eddies will convect at approximately the volumetrically averaged flow velocity within the pipe. The precise relationship between the convective velocity of turbulent eddies and the flow rate for each class of meters can be calibrated empirically as described below. 3.3 Characterizing the unsteady pressure field The sonar flow metering methodology uses the convection velocity of coherent structure with turbulent pipe flows to determine the volumetric flow rate. The convection velocity of these eddies is determined by applying sonar arraying processing techniques to determine the speed at which eddies convect past an axial array of dynamic strain measurements BI0197 RevB 3 Flomeko 2005 6 - 9 June 2005 distributed along the pipe outer circumference. The sonar-based algorithms determine the speed of eddies by characterizing both the temporal and spatial frequency characteristics of the flow field. For a train of coherent eddies convecting past a fixed array of sensors, the temporal and spatial frequency content of pressure fluctuations are related through the following relationship: w = kv (2). Here is the wave number, defined as k=2n/I~ (1/m), co is the temporal frequency (rad/s) and v is the convective velocity of the unsteady pressure fluctuations. Thus, the shorter the wavelength is the larger k and the higher the temporal frequency. ~ In sonar array processing, the spatial - temporal frequency content of time stationary sound fields are often .~ displayed using "k-w plots". k-w plots are essentially two dimensional ~ power spectra in which the power of ~ a pressure field is decomposed into ~. bins corresponding to specific spatial wave numbers and temporal ~ frequencies. On a k-w plot, the power associated with a pressure field _,~ convecting with the flow is distributed w.«~,~~ in regions which satisfy the dispersion relationship developed Figure 3: k-w plot showing convective ridge above. This region is termed the "convective" ridge and the slope of this ridge on a k-w plot indicates the convective velocity of the pressure field. This suggests that the convective velocity of turbulent eddies, and hence flow rate within a pipe, can be determined by constructing a k-w plot from the output of a phased array of sensors and identifying the slope of the convective ridge. Figure 3 shows an example of a k-w plot generated from a phased array of transducers listening to a 16 inch pipe flowing water at approximately 350 I/s. The power contours show a well-defined convective ridge. A parametric optimization method was used to determine the "best" line representing the slope of the ridge. For this case, a slope of 3.2 m/s was determined. The intermediate result of the optimization procedure is displayed in the insert, showing that optimized value is unique and constitutes of one well-defined maximum. 3.4 Sonar flow meter calibration The k-w plot shown in Figure 3 illustrates the fundamental principle behind sonar based flow measurements, namely that axial arrays of transducers can be used in conjunction with sonar processing techniques to determine the speed at which naturally occurring turbulent eddies convect within a pipe. The next issue is to quantify the relationship between speed of the turbulent eddies and the volumetrically averaged flow rate within the pipe. To quantitatively evaluate this relationship, a number of geometrically similar sonar flow meters with diameters between 4 and 16 inch were tested with water at a flow meter calibration facility for flows ranging from 1.5 to 1500 I/s. The convection velocity determined using the sonar-based techniques, normalized by the volumetrically averaged flow rate supplied by the calibration facility as a function of Reynolds number ranged between 99% and 102% of the volumetrically averaged flow rate over the entire range of the test. Alow-order Reynolds number based calibration, was developed from this data for this class of meters. The calibration equation is developed in terms of the relative offset of the sonar based meter from the reference meter. The relative offset ~ is, in terms of the Reynolds number Re and a set of three coefficients C~, CZ and C3, unique to each sonar meter size given by (3). ~=C1+ Cc Re 3 (3). BI0197 RevB Flomeko 2005 6 - 9 June 2005 Figure 4 shows the relative difference of the volumetric flow rate measured by the calibrated sonar meters and the reference flow plotted versus reference flow. Calibration data was recorded for the sonar flow meters with volumetrically averaged flow velocities ranging from 1-10 m/s. Using a single Reynolds number calibration (4) spanning the operating range of the three flow meters of different physical sizes, the sonar meter measured the volumetric flow rate to within 0 5°/ - N-0.5% Pro °Iucfi onSONAR trac FbwMeterData - -- -95~ca,rae~~~e~~=o.az% ^ SND60830085-109 Sch 10 T 10D 62 o ^ SND60B300B5-1115th 10 TSD 62 SNO60B300B5-115 Sch 10 T 10D B2 O SNJ60830085-116 Sch 10 T SD B2 ^ SNO60B30085-117 Sch 10 T 10D B2 O SNO60B30085-118 Sch 10 T SD 62 ^ SND60830085-109 Sch 10 T 10D B1 d SND6083008S111 Sch 10 TSD B1 o ® ^^ o ~ ' ' ~ ~ ^ .. ~ ~~ ~ o ~ ,~~ ~ ~ 0 0 0 0 ------- ---- ----- . ° accuracy. It is important to note that this flow metering approach has no fundamental size limitations and should be applicable to turbulent pipe flows of all diameters and Reynolds numbers. Furthermore, similarity laws suggest, and data from Figure 4 support, that the relationship between convection velocity and flow rate from geometrically similar meters of any size is be governed by same Figure 4: Calibration data. Reynolds number based calibration. It can be concluded from the data presented that the 95% confidence level of the sonar based flow measurement equals 0.42%. 3.5 Industrial applications Numerous industrial applications for the sonar based flow measurement have been developed in close co-operation with end users over a period of more than 2 years. The industrial applications are to be found were the clamp on, non intrusive, large bore capability of the sonar based principle results in undisputed advantages in terms of life cycle cost, reliability or the sheer impossibility to make any other measurement device work. Examples of such are: • Hydro transport of oil sand8. • Thick stock flow in paper and pulp9. • Air conveyed transport of particulate material. • Two phase flow of water and oi110 " • Sewer water processing. • Flow of coating pastes. • Magnetite flow in minerals processing. All of the above examples of industrial flows are characterized by their abrasive and/or corrosive nature. In many cases this necessitates the use of special pipe materials or the use of lined (Teflon, rubber, concrete) pipe. The phenomenon of pressure fluctuation induced circumferential pipe strain is universal and independent of the precise nature of the pipe material or lining. As a result a sonar based measurement can, in most cases, be applied without a process shut-down, without cutting the pipe and without elaborate operational procedures or safety measures. In selected cases the operating principle of the sonar based meter removes a calibration difficulty inherent in the traditional measurement principle. For instance, in the flow rate measurement of magnetite suspensions by electromagnetic flow meters the ferro magnetic nature of the suspended particulates affects the meter's calibration. As a result the meter may drift with magnetite concentration. Figure 5 shows two frequency distributions of the relative difference between a sonar based and electromagnetic flow rate measurement for both high (1.70 kg/dm3) and low (1.65 kg/dm3) density magnetite suspensions in the feed flow to a BI0197 RevB 5 30000 2aooo ~ 18000 7 O U 12000 6000 100% 8o°i° d so°i° r f0 3 40% 3 U 20% 0% 0% 5% 10% 15% 20% Figure 5: Frequency distribution of the relative offset of sonar versus mag meter. series of reverse flotation cells. As in this specific example neither meter was "nulled" relative to the other, either the high density histogram or the low density histogram may be used as a reference for the other. It follows that the difference between the two meters, sonar and an electromagnetic, has shifted by about 5% with the change in the magnetite concentration. This is believed to be due to the fact that the calibration of the electromagnetic flowmeter is dependent on the actual concentration of magnetite in the flow. A flow meter that is not affected by the detailed make up of the fluids flowing and any particulates therein is a very clear advantage. It is to be noted that in other comparable cases, where non magnetic particulate material is suspended in the flow, the difference between sonar and an electromagnetic flow meter is not affected by the density. 4 MEASUREMENT OF GAS CONTENT Using a similar, and in many cases the same, hardware platform it is also possible to measure the velocity of sound of acoustic waves propagating in the process piping. The propagation of acoustic waves occurs at frequencies much above the frequency domain of vortical pressure fluctuations, therefore the same sonar processing can be applied to determine both the acoustical velocity and the voritical velocity at the same time. The relation between speed of sound in twophase mixture and the volumetric phase fraction is well known in case the wavelength of sound is larger than the pipe diameter and hence also significantly larger than any process in homogeneities such as bubbles. 4.1 Velocity of sound in liquid/gas mixtures The mixing rule12, known as Wood's equation13, expresses the fact that in a mixture the compressibility of the mixture equals the volumetrically averaged compressibility of the pure components. For the mixture density a similar rule holds: the mixture density equals the volumetric average of the pure component densities. Because the velocity of sound in a fluid equals the square root of the compressibility over the density, the two mixing rules can be written as: 1 _ ~P 1-tp P~2 Pg~g PICI (4). Here, cp is the volume fraction of gas at line conditions, c is the speed of sound, p the density and the subscripts g and I refer to the gas and liquid phase respectively. Figure 6 illustrates the relation between mixture sound speed and gas content for an air water mixture. In most industrial processes, at moderate temperature and pressure line conditions, the compressibility of the gas phase is orders of magnitude larger than the compressibility of the liquid phase. Inversely, the density is dominated by the liquid density. As such, it will be necessary to measure the process pressure (when varying) as both the gas density and the Flomeko 2005 6 - 9 June 2005 100°1 10000 LOW 8o°i° sooo 60% ~.. 6000 C 7 O 40% V 4000 20% 2000 0% n BI0197 RevB 0% 5% 10% 15% 20% Flomeko 2005 6 - 9 June 2005 liquid density are significant when determining the gas volume fraction from the mixture sound speed. Conversely, neither the velocity of sound in the liquid nor the velocity of sound of the gas is a significant factor for mixtures where one phase is gaseous. In fact, the denominator of the first term in the Wood's equation equals the product of process pressure and polytropic exponent of the gas demonstrating that the gas content at line conditions can be determined using the velocity of sound independent of the gas molecular weight or the gas temperature. Hence, the determination of the gas content using mixture speed of sound is independent of the gas type 1000 and will be accurate a~i ~ 100 0 m x 10 ~ _.. ----'.~ vas ~ • \ _ ~ - 4 bar ., -~ ._ -____ •• •- -'--- 5bar 0% 5% 10% 15% 20% Gas volume fraction Figure 6: Mixture sound speed vs. gas volume fraction. (4). The distensibility for thin walled, untethered pipe is given by: D _ 2R Et irrespective of the type of gas, which can be either air, carbon- dioxide, hydrogen or any mixture thereof. For mixtures confined to a pipe, a correction to above formulae (4) is necessary in order to account for the relative change of pipe cross sectional area upon internal pressure variation. This so called distensibility14, D, is an additive term to the first equation of (5), where R is the pipe's internal radius, t is the wall thickness and E the pipe materials' Young modulus. In steel pipe, the distensibility is quite small because of the large value of the Young modulus of steel. In aluminum, glass or even plastic pipe, however, the distensibility must be accounted for. The effect of the pipe distensibility is lower the apparent, measured speed of sound. For instance in a water filled 4" plastic pipe with a wall thickness of 5.5 mm and a modulus of 3.5 GPa, the measured speed of sound will be 420 m/s at zero aeration. This is a striking difference with the free space velocity of sound in water of 1480 m/s. 4.2 Measurement of the velocity of sound As described above, the relationship between mixture sound speed and entrained air in bubbly liquids is well established. However, as will be developed below, in bubbly flows, these relations are only applicable for the propagation of relatively low frequency, long wavelength sound. While this restriction does not present any significant obstacles for the sonar meter, it does present significant challenges to ultrasonic sound speed measurement devices. Ultrasonic meters typically operate in 100 kHz to several MHz frequency range. For these meters, entrained air bubbles have length scales on the same order as the acoustic waves generated by the ultrasonic meters. This poses several problems for ultrasonic measuring devices. Firstly, the bubbles scatter the ultrasonic waves, impairing the ability of the ultrasonic meter to perform a sound speed measurement. Secondly, ultrasonic meters rely on information derived from only a small fraction of the cross sectional area of the pipe to be representative of the entire cross section, an assumption that breaks down for flows with non- uniform distributions of in homogeneities, such as stratification of entrained air towards the top of process lines. BI0197 RevB Flomeko 2005 6 - 9 June 2005 Sonar flow meters use an approach developed and commercialized specifically for multiphase flow measurement in the oil and gas industry in which multiphase challenges described above are routinely encountered. Sonar meters measure the propagation velocity of operationally generated sound in the -100 to 1000 Hz frequency range. In this frequency range, sound propagates as aone-dimensional wave, using the process pipe as awave-guide. The wavelength of sound in this frequency range (>1 m) is typically several orders of magnitude larger than the length scale of the any bubbles or flow non-uniformities. The long wavelength acoustics propagate through multiphase mixtures unimpeded, providing a robust and representative measure of the volumetrically averaged properties of the flow. For the sound speed measurement, the sonar flow meter utilizes similar processing algorithms as those employed for the volumetric flow measurement. As with convective disturbances, the temporal and spatial frequency content of sound propagating within the process piping is related through a dispersion relationship. w = kc (6). As before, k is the wave number, defined as k=2~/~, (1/m), w is the temporal frequency (rad/s), and c is the speed at which sound propagates within the process piping. Unlike disturbances which convect with the flow, however, sound generally propagates in both directions, with and against the mean flow. For these cases, the acoustic power is located along two acoustic ridges, one for the sound traveling with the flow at a speed of c + V and one for the sound traveling against the flow at a speed of c - V. N Figure 7: k-w plot for 3% entrained air in water. 4.3 Industrial applications Figure 7 shows a k- w plot ~ generated for acoustic sound field recorded from still water containing -3% entrained air by volume in an -~ 8 in, schedule 80, vertically oriented Plexiglas pipe. The k-w plot was constructed using data ~ from an array of strain based sensors clamped to the outside of the pipe. Two acoustic ridges are clearly evident. Based on the ~ slopes of the acoustic ridges, the measured sound speed for this for this mixture was 70 m/s, consistent ~ with that predicted by the Wood equation. Note that adding 3% air by volume reduces the sound speed of the bubbly mixture to less than 10% of the sound speed of liquid only water. As was mentioned in the introduction, there are two applications of the full bore measurement of entrained gas of distinctly different character. First there are those where process aeration must be controlled or where process aeration must be avoided altogether. Examples of such are: • Natural froth lubricity flows. • Gas sparging in flotation cells. • Dissolving carbon dioxide in beverages. • Entrained air in the thin stock flow to a paper machine's headbox15. • Entrained air in filling stations for domestic household products. Second there are applications where entrained gases negatively affect the process indirectly by affecting other types of meters. Examples of this second kind are: BI0197 RevB w.~,«w.ne« n ~l Flomeko 2005 6 - 9 June 2005 • Errors in consistency measurement of paper stock.16 • Errors in the determination of net oil using watercut meters". • Errors in Coriolis determined volume flow as a result of product aeration18. • Errors in custody transfer metering resulting from product flashing or aeration. The sonar based measurement of process aeration using the velocity of sound covers almost 5 orders of magnitude, from 0.01 % to above 20%, and is therefore universally applicable to a wide variation of process conditions. By way of example Figure 8 gives the amount of ~ entrained air in a volume of paper 6 ~ 5 0 w 4 LL N 8 3 0 > 2 y ~ 1 0 stock just before and just after the dosing of a commercially available defoamer chemical. Given the continuous character of the measurement and given the fact that this full bore measurement is, unlike a sampling system, representative of the true air content the ability to control defoamer dosing presents itself. Such dosing control will not only help reduce defoamer volume it -120 -60 o so 12o will also help reduce process Time [s] variability. Thus product quality is positively impacted whilst at the Figure 8: Defoamer dosing application same time cost is reduced. Conversely, in applications where the amount of air or gas in a process must be kept at a stable level in presence of gas consumption by chemical reaction, this sonar based measurement can provide hitherto unavailable compositional information even on large diameter reactor vessels.. Just reversing the time scale in Figure 8 is sufficient proof of this claim. 5 CONCLUSIONS Sonar based flow monitoring enables the direct measurement of the convective transport velocity of turbulent eddies in pipe flow and it enables the direct measurement of the velocity of sound propagating through the pipe. Both measurements can be made using an array of strain based sensors clamped to the outside of the process piping. Evidence is presented to prove that the convective transport velocity of turbulent eddies is proportional the volumetrically averaged mean velocity. A Reynolds number based, empirical calibration is given which yields 0.5% accuracy for Newtonian fluids. Thus, a novel technique based upon naturally occurring phenomena in pipe flow allows the realization of a calibrated flow meter. Industrial applications of the sonar based flow meter in abrasive and corrosive fluids are discussed. An example in magnetite flows is given where the passive nature of the sonar based instrument proved to be a distinct advantage. It is shown how the .velocity of sound in a twophase medium can be used to derive compositional information such as gas volume fraction. The necessary correction for the effect of the enclosing pipe is developed. The effect of fluid and gas properties on the calculated gas content is discussed. Neither the temperature nor the gas' molecular weight has any influence, only the liquid density and the process pressure must be known. An industrial application of the gas volume fraction measurement is presented. This defoamer dosing example is one of many which have been found. BI0197 RevB Flomeko 2005 6 - 9 June 2005 6 ACKNOWLEDGEMENTS The results presented in this work have benefits from several years of collaborative efforts to develop sonar-based flow measurement. The authors gratefully appreciate the efforts of the many colleagues and co-workers that have contributed to results presented herein. 7 REFERENCES 1 NIELSEN, R.O., Sonar signal processing, Artech House Inc, Norwood, MA, 2001, ISBN 0-89006- 453-9 2 KRAGAS, T. K., et al., " Downhole, Fiber Optic Multiphase Flow Meter: Field Installation" Presented at the Society of Petroleum Engineers Annual Conference, SPE Paper #77654, September, 2002. 3 KRAGAS, T. K., et al., "Downhole Fiber-Optic Multiphase Flowmeter: Design, Operating Principle, and Testing," Presented at Society of Petroleum Engineers Annual Conference, SPE Paper #77655, September, 2002. 4 MATULA, J. P. and KUKKAMAKI, E, "New findings of entrained air and dissolved gases in pm wet end: mill case study," TAPPI JOURNAL, Apri12000, Vol. 83 5 LANDAU M.T., MOLLO-CHRISTENSEN, E., Turbulence and Random Processes in Fluid Mechanics, 2nd Edition, Cambridge University Press, Cambridge, UK, ISBN 0-521-42213-2, 1992. 6 SCHLICHTING, H., Boundary Layer Theory, McGraw-Hill, New York, ISBN 0-07-055334-3, 1979 7 BERANEK, L.L., VER, I.S.," Noise and Vibration Control Engineering," Section 14.6, John Wiley and Sons, New York, ISBN 0-471-61751-2, 1992 8 GYSLING, D.L., MUELLER, E., Application of sonar based, clamp on flow meter in oil sand processing, ISA 2004 Exhibit and Conference, Edmonton section, Apri12004. 9 GYSLING, D.L., LOOSE, D.H., Sonar based volumetric flow meter for pulp and paper applications, CiDRA Corporation, Wallingford, CT, 2003, unpublished work. 10 GYSLING, D.L., VAN DER SPEK, A.M., Fiber optic downhole multiphase flow meter: flow loop evaluation for oil/water mixtures, Downhole Instrumentation seminar, North Sea Flow Metering Workshop, Glasgow, Scotland, 23 October 2000. 11 GYSLING, D.L., VANDEWEIJER, T., VAN DER SPEK, A.M., Development of a permanent downhole twophase flow meter, SRI multiphase metering and pumping conference, Houston TX, February 2000 12 MC WILLIAM, D. DUGGINS, R.K., Speed of sound in bubbly liquids, Proc Instn Mech Engrs, Vol 184, Part 3C, 1969-1970. 13 WOOD, A., A textbook of sound, New York, NY, 1st edition, 1930 14 LIGHTHILL, J., Waves in Fluids, Cambridge University Press, Cambridge, 1980, ISBN 0-521- 29233-6 15 GYSLING, D.L., LOOSE, D.H., Sonar based volumetric flow and entrained air measurement for pulp and paper applications, TAPPI Spring Technical Conference, paper 58-1, Chicago, IL, May 2003. 16 STOOR, T., AMMALA, A. NIINIMAKI, J., Measurement of air content of pulp suspension -sonar method, APPITA 2005 pulp and paper conference, Auckland 16 - 19 May 2005. 17 GYSLING, D.L, LOOSE, D.H., Using sonar bsed gas volume fraction meter for improved net oil rate measurement, Canadian School of Hydrocarbon Management, Toronto, 2005. 18 GYSLING, D.L., BANACH, T. Accurate liquid phase density measurement of aerated liquids using speed of sound augmented Coriolis meters, ISA, Houston, October 2004. BI0197 RevB to SPE 100893 New Class of Meter Solves Old Problem Impacting Well Test Accuracy E.R. Ward, SPE, BP Exploration (Alaska) Inc. Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE Western Regional/AAPG Pacific Section/GSA Cordilleran Section Joint Meeting held in Anchorage, Alaska, U.S.A., 8-10 May 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restdcted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract For the first time in a BP-operated asset, the impact of entrained free gas (not solution gas) in the liquid outlet line of a well test separator is quantified for the purpose of correcting gross fluid volumes and density measurement. This paper describes the results of deploying a sonar based, clamp-on gas void fraction (GVF) meter at a test facility in the Prudhoe Bay Unit (PBU) on Alaska's North Slope. Introduction The PBU has been in production since 1977. Over the life of the field several different Test Separator configurations have been utilized. Approximately 16 years ago, PBU started to use the density water cut method on 2-Phase Mini Test Separators to overcome problems that were encountered on the conventional 3-Phase Units. In general these units operated successfully; success was measured by repeatable water cut results that enabled the petroleum engineers to improve management of the wells and have more confidence in production changes as a result of well workovers. Cold viscous crude oil has now been introduced into the PBU production facilities increasing the range of the oil API gravity from 22 to 32 API now down to 17 API. This brought a whole new set of problems. As part of this project two new mini 2- Phase Test Separators were installed. A review of the liquid leg densities of the units handling viscous oil indicated the possibility of free gas with a resultant gas void fraction (GVF). This particular test facility employs a Coriolis meter to measure density and gross flow rate of the oil/water mixture. It was confirmed that discrepancies in allocation factors and individual net oil measurements, especially for cold high viscous crude oil, was due in part to unrecognized gas carry- under in the liquid outlet. Measured GVF associated with wells flowing `non-viscous' oil, the less viscous crude (22 to 32 API) ranged from 0 - 2.0 %, whereas the GVF of wells flowing viscous crude (17 to 22 API) was between 0 - 8% at normal vessel liquid levels increasing to >20% at reduced separator levels. The additional secondary phase measurement enables PBU to now report real time corrected densities and volumes using an in-house method to calculate water cut. In addition to viscous crude, we believe that application of this technology to smaller, somewhat under-sized separators with less stable operations will provide value across the industry. Well testing importance is increasing on the maturing fields of the North Slope of Alaska as it is not only used for the critical function of field management that ensures optimum production from a field; it also is a regulatory requirement set by the State of Alaska and may be used for Production Volume Accounting on fields with co-mingled production facilities. This paper is a brief report of the findings of a preliminary test and a more extensive pilot project of a strap-on sonar based GVF meter on both `non-viscous' crude oil and satellite field viscous oil. The preliminary test was a quick check to determine if the GVF meter could measure a meaningful GVF on the two crudes. With a favorable result to the preliminary test the pilot project was instigated and the unit was installed and fully integrated into the well testing system. Since being installed in October 2005, the unit has been used for on-line well testing. The objective was not only accurate GVF measurement to improve water cut and gross fluid volume accuracy but also to check for long term stability. A stable Zero GVF measurement is a critical issue especially when the unit is used for all types of crude oil and on many wells having little to no GVF. To quantify the impact of GVF on the Test Separator operations in PBU, a 1 %GVF equates to an understatement of water cut (WC) by 5% and a direct 1% over statement of gross fluid flow. As the title of this paper indicates this meter provides a solution to a long standing problem. This is the final piece of a puzzle that has taken many years to solve. In order to have a better understanding of how our approach has developed the first few sections of this paper will provide a brief overview of SPE 100893 the PBU and a history of Well Testing, Oil Allocation and Test Separator improvements in the PBU. Overview of Greater Prudhoe Bay (GPB) GPB is a Production Unit of several oil fields (formations). The Initial Participating Area (IPA) within PBU is by far the largest and has been the main driving force in the development of the Test Separator Systems described in this paper. The most recent business need has been the introduction of small satellite fields to the IPA facilities and the problems of cold viscous oil. The PBU was from concept split into two operating areas by the owners with the agreement of the State of Alaska; the Western Operating Area (WOA) operated by BP and the Eastern Operating Area (EOA) operated by Atlantic Richfield Company (ARCO). In addition there was a different ownership split between the Gas Cap and the Oil Rim Participating Areas. After the BP/ARCO merger, BP is now the sole Operator of PBU and the field has been unitized with aligned working interest ownerships in Gas Cap and Oil Rim Participating Areas. The Test Separator operations described in this paper are from the WOA. Impacts of Well Testing As with all oil and gas fields, PBU well testing is used for field management. A very critical function used to optimize production rates and total hydrocarbon recovery from the field. With the early ownership differences between the Gas Cap and the Oil Rim, well testing was critical in the determination of the Gas Oil Ratio (GOR), one of the parameters used to select a well for inclusion in the Gas Cap or Oil Rim. As gas production increased beyond the agreed associated gas volume (determined at a 1000 GOR) the importance of well testing in this area reduced and the gas condensate allocation was then by an agreed liquid volume factor in the gas and simply determined by measuring the overall gas volume. The introduction of satellite field production into the IPA Processing Facilities created the problem of production allocation to the correct field. There was a different tax / royalty regime for IPA and the PBU satellite fields. By prior agreement with the State of Alaska well allocation was the selected method for individual field production. The overall volume of crude oil was measured to custody transfer standards; allocation and well testing determines the production split between the IPA and the individual satellite fields. This obviously increased the importance of well testing and PBU in collaboration with the State of Alaska undertook a major program to upgrade and improve oil allocation and well testing operations. With the merger of ARCO and BP the PBU Gas Cap -Oil Rim ownership difference has been eliminated. Also the State of Alaska has recently equalized the taxation rate for all oil produced through the PBU facilities. Well testing is again mainly for field management but more importantly for regulatory purposes to prove the field is being operated and managed in a prudent manner and to maximize overall fluid recovery. Oil Allocation Methodology As the PBU evolved over time, so has the Oil Allocation Process changed to meet the new challenges. WOA has three production facilities known as Gathering Centers (GC) where oil, gas and water are separated, the gas is dehydrated before shipment to the Gas Plants and re-injection into the field. The EOA also has three production facilities known as Flow Stations (FS). Oil is shipped to Pump Station 1 (PS 1) of the Trans Alaska Pipeline System (TAPS) for metering to custody transfer standards. Alyeska Pipeline Service Company (ALPS), the company operating TAPS, operated two metering systems, one each for EOA and WOA. As production has declined ALPS reduced metering to one combined meter set for EOA and WOA. Also GC 3 passes partially processed oil to FS 3 so only five production facilities are now producing directly to TAPS. All of these changes have had an impact on the allocation process. The following simplistic statistical model demonstrates the impact of metering accuracy on the allocation process. Taking the WOA as a model there are three levels at which oil metering is made; Fiscally at PS 1, Production Metering at the outlet of the GC and individual well production (Well Testing). In order to measure a total volume of 300 MBPD to an accuracy of 1% the choice is to either measure with one 300 MBPD meter with an accuracy of 1%, or three 100 MBPD meters with an accuracy of 1.75% or three hundred 1 MBPD meters with an accuracy of 17%. The WOA has gone from initial allocating process of allocating from PS 1 to the GCs and then to the associated wells to allocating directly from PS 1 to the all wells and back to the intermediate GC step process. The reason for the reversal was that the number of wells had grown significantly and inaccurate testing was being hidden. The wells needed to split up in to smaller groups so as to determine the problem areas. Brief History of Test Separators The following describes the fixed in place Test Separators. If at any time these units were having operational problems Portable Separators were utilized to ensure the required well testing was performed and the overall allocation process was accurately maintained. The initial test separators were Test Banks (3 Stages of Separation) in the GCs. This ensured the oil volume measurement was of sales quality crude corrected to Stock Tank Barrels (STB). As the field developed Test Separators were installed at the Well Pads operating at elevated pressures. This introduced the problem of "Oil Shrinkage", the change in volume of live crude at test separator conditions to STB. SPE 100893 To overcome this problem PBU carried out a large project of correlating test results from the Well Pad Separators to the same well tested in the Test Bank. From this large data base an algorithm were developed that provided two factors, Oil Shrinkage and Solution Gas (SCF per unit volume) to be applied to the Test Separator results. Recently PBU updated this data base utilizing a customized equation of state to improve the accuracy of these factors. The initial Well Pad Test Separators were large 150 Barrel 3-Phase units. Turbine meters were used for oil, water and gas. Master Water and Oil Meters were installed to check the accuracy of the on-line meters. A capacitance probe was installed in the oil leg to detect the water cut up to 20%. In general these systems worked well but problems started to appear when the water cut and GOR started to increase. This was especially true when PBU came off the production plateau. Several improvements were made including replacing the liquid turbine meters with vortex units and modifying internals of the separators. The significant problem with the capacitance probe system was that it could only be customized on a per well pad basis and individual wells on the same well pad were exhibiting significant different physical properties which impacted the water cut accuracy. PBU had installed three mini (40 Barrel) 3-Phase Test Separators that were experiencing significant problems. The results made any field management of the wells in that area very difficult. In 1989 PBU decided to install a direct mass flow meter using the density water cut method on the liquid leg of the separator which was converted to a 2-Phase unit. This method proved so successful that it was installed on eight of the 3-Phase Units. In addition the three GC Test Bank Separators have been reduced to a single stage unit using the density water cut method. The two new satellite field Mini (30 Barrel) 2-Phase Separators are all based on this method. These units did have a microwave water cut meter installed in the liquid leg, but they have never been used on-line. Water Cut Calibration Methods for Density Based Water Cut Measurement All water cut analyzers need to be customized to specific well fluids. This may even be on a per well basis. The proprietary system installed required a `pseudo' oil density that would be temperature compensated using API Volume Correction Tables to give the oil density at line conditions. The first calibration method implemented simply fixed the water density and adjusted the oil density until the water cut matched spinout tests of the crude oil for each well. This was later improved by taking live samples to the laboratory where an analyzer measured the oil and water densities at line conditions and the' pseudo' density was calculated. Both methods were satisfactory but required careful co-ordination of the well in the Test Separator during sampling and were very man-hour intensive. With the updating of the eight 3-Phase Test Separators to 2-Phase Units, the addition of the two new 2-Phase Units for the viscous oil and the associated significant increase in well count the existing methods of calibration became virtually impossible to maintain. In addition the laboratory analyzer proved not to be satisfactory and was taken out of service. All of these problems lead to a fundamental reevaluation of the calibration methods and even the density method itself. New Approach to the Water Cut Density Method The following is only a brief outline of the in-house developed method that will assist with understanding the main topic of this paper; GVF measurement and the application to test separators. The basic intent of the method was to reduce sampling requirements while not impacting metering accuracy. The method is based on mass which does not change for pressure and temperature variations or for mixing two fluids together even if they are in different phases. Live crude is just stock tank barrel crude oil with gas in solution. Therefore the density of live crude can be predicted by simply adding the mass of the oil and the mass of the solution gas together. The key to understanding this system is oil shrinkage and solution gas. These parameters are fundamental to well testing at elevated pressures and temperatures. Typically a well test determines the volume of live oil at separator conditions; the oil volume is then shrunk to provide the daily production volume in STB terms. The density of stabilized crude and dry gas can be determined at both base and line conditions (Pressure and Temperature compensated) using API and AGA Standards. The density of water can be determined by well established and internationally accepted algorithms at both line and base conditions. The hydrocarbon (Oil plus Gas) density at line conditions is the sum of the oil line density with oil shrinkage applied plus the mass of solution gas on a per unit basis. The water cut is determined using the standard equation for the mixture of two fluids of known densities from the measurement of the line fluid density of the combined fluids. The unique part of the method is that the actual oil, gas and water volumes at line conditions can be determined. Therefore it is possible to mass balance the liquid leg by comparing this calculated mass to the measured mass flow from the direct mass flow meter. The method adjusts the solution gas in the density model until 100% mass balance is achieved. This has been demonstrated to improve the water cut accuracy. Benefits of the New Approach The oil shrinkage and solution gas factors are based on pressure, temperature and GOR. Therefore the metering on the Test Separator is now fully integrated as the off gas flow impacts the liquid leg measurement for oil and water. More specifically the hydrocarbon fluid density in the liquid leg is fully compensated to all pressure, temperature and GOR conditions. The only parameters to be input to the method are the base specific gravities of dry oil and water. This significantly reduces the sampling complexity as only the well fluids at STB conditions are required and not at the line conditions. SPE 100893 As the method provides on a real time basis the STB water cut, it can be compared directly to the laboratory determined water cut which is made at 0 PSIG. There is a significant difference between the on-line water cut and the STB water cut especially with oil shrinkages of up to 30%. Problems on the Viscous Oil Test Separators Most of the early problems were associated with the fact the units were open to the Artic environment and meters were not installed in the most advantageous way. These difficulties were slowly overcome and the new density method was installed on the separators. A review of the measured density in the liquid leg of the separators indicated a significant quantity of gas in the liquid leg which had a detrimental impact on both the total fluid volume and the water cut determination. The addition of GVF in the liquid leg means there are three unknowns but the calculation method only provides two equations. The third unknown, GVF had to be quantified for the density method to work. Selection of the GVF Meter BP was performing wet gas meter tests and during a presentation of this test a sonar based strap-on unit was presented that was claimed to measure GVF in the 0-20 range. The unit is passive; it listens to audio frequency noise signals in the fluid and using sonar techniques determines the speed of sound (SOS) of the fluid in the pipe. In this frequency range the wavelengths are several feet, therefore the transducer is measuring the physical properties e.g. free gas that is present a significant volume of the fluid and not just a slice across the pipe. The relationship between the SOS and gas in a liquid (GVF) is very well established and documented. Preliminary Tests It was decided to perform a preliminary test on the liquid leg of a Test Separator that tested both PBU and satellite crude wells. The objective of these very simple tests was to determine if the unit would measure a GVF and whether it would track expected GVF values when the level in the vessel was raised or lowered. Two units were installed; one upstream of the mass meter (horizontal) and a second downstream of the mass meter (vertical down). The intent of the preliminary tests was not only to confirm satisfactory operation of the GVF meter but also to try and select the best position for a more extensive test. The results of two days of trials were very favorable. A GVF was measured in both crudes in the range of 0 - 30%. The GVF measurement performed as expected; it increased in value for a lowering vessel liquid level and decreased in value for an increasing vessel liquid level. Typically both units tracked; however on high GVF values (> 15%) the downstream meter indicated up to twice the upstream unit. This was believed to be a piping issue with gas trapped in an inverted U section of pipe and the flow of fluid was not great enough to sweep the buildup of free gas. See Figures 1 and 2 for the GVF plots of these tests o.~ 0.6 o.s e 0 ~~ o.a e e 0.3 ~ o.z o.t 5/20/200517:1500 51201200517:22:12 5/201200517:29:24 5120/200517:36:36 5120/200577A3:46 5/20Y10p517:51U0 Figure 1 -Downstream GVF Meter on a Typical PBU Well (26°API and 98°F) 35 30 -~-~--Upstream 25 Downstream 0 ' 20 ~ A 0 15 A ~o o f i ~ - i i i 5127/2005 6:30 5/21/2005 7:42 5/77/2005 8:54 5'2712005 70:06 5/22/2005 77:16 5/22/2005 72:30 Figure 2 -Comparison of Upstream and Downstream GVF Meters on a Cold Viscous Well (18°API and 54°F) Extended Pilot Test As a result of the favorable preliminary test it was decided to install a unit into the well testing system and to monitor its performance. The new in-house density approach is programmed into a stand alone flow computer that has fully flexible customer programming capability. The program was updated to include the GVF function in both the density calculation and the gross volume calculation. In addition the free gas was added to the off gas and the free gas was included in the mass balance of the liquid leg. To enable the operation to be monitored closely an extensive data gathering system was also configured into the flow computer and the Supervisory Control and Data Acquisition (SCADA) System. The SCADA System performs the well test function and the following parameters were retrieved in addition to the standard data for well testing. • Gas Void Fraction • On-line Measured Density • GVF Corrected Density • Calculated On-line Hydrocarbon Density • Calculated On-Line Water Density SPE 100893 • Mass Flow • STB Oil Flow • STB Water Flow • On-line GOR • STB GOR • Mass Balance • Solution Gas Correction Factor Data was gathered approximately every 20 seconds. This real time data has enabled PBU for the first time to monitor very closely how the density method operates on a 2- Phase Separator. Review of Preliminary Results of the Pilot Test The water cut methodology is based on fluid densities so tracking how the hydrocarbon and water densities vary on-line and how the measured liquid leg fluid density compares to these densities is critical. For example the GVF values we have witnessed on these tests can take the measured density from less than the hydrocarbon density to higher than the water density. That is from 0% water to 100% water. The test separator is at an unmanned site and the only monitoring is restricted to measured /calculated variables; it was not feasible to bring back the status of the sonar unit. The dilemma is to know when an accurate GVF is being measured. The GVF transmitter was setup to freeze at the last known good answer. The GVF is not expected to be constant; therefore no "plateaus" should be expected on a plot of GVF. Reviewing the GVF transmitter status when this happens reveals two basic reasons; either poor signal quality or invalid speed of sound data. The downstream unit was selected as the primary meter for the test. Initial results looked promising; however we witnessed excessive swings in the indicated GVF (0 to 20 %+) with the associated large variations in water cut. This was a repeat of the high GVF measured during the preliminary test caused by a buildup of free gas in the inverted U section. The upstream unit was now selected and all tests were made using this unit. The first criterion for success was to determine if the GVF corrected line density lies between the hydrocarbon and the water densities. If this is satisfied the metering methodology will be able mass balance the liquid leg of the separator. The method will not be able to mass balance the liquid leg if this criteria is not met. A Portable Test Separator is used to check well tests especially if the results are questionable. This portable separator is manned on a 24/7 basis and it is customized for each well test. This is considered the best well test we can achieve. Therefore the second criterion was to compare the well test result from the on-line separator to the last test using the portable separator. In general the unit operated satisfactorily on PBU crude. However as the main reason for using the GVF meter was testing cold heavy viscous crude the results presented and discussed in this paper are for a viscous well. The initial tests on one particular well showed little to no GVF but as time progressed tests started to have large GVF swings and plateaus on the GVF data plot. The status of the unit was low signal quality and invalid SOS data. The first reaction was to question whether there was enough noise to enable the meter to function. After all the unit in use had the greatest distance to the liquid control valve, the expected source of the noise. A data "snap shot" was submitted to the manufacturer who stated the signal strength was good but the unit was not able to successfully analyze the SOS data. It was noted that when the wells are tested with the portable separator unit chemicals are injected into the crude, in particular anti-foam. Anti-foam was injected into the well flow-line. Figure 3 shows the response of the GVF Meter and the density water cut methodology to this anti-foam. The plot is for 8 hours with the anti-foam injected at approximately 5 hours into the plot. The well test was for 4 hours and this plot shows the first 3 hours of this test. There was an immediate improvement to the whole system. Parameters no longer had wild variations and the GVF corrected density was now solidly in between the hydrocarbon and water densities and steady. For the well in question the measured on-line density was significantly below the calculated on-line hydrocarbon density. Line Density GV F Cor Density - - - - - FIC l'alc Density --~----Water Calc Density GVF so a 58 ass m o~ sz so as 60 120 180 240 300 360 420 Minutes tz e to ~ 8 ~ Figure 3 -the impact of Anti-Foam on the performance of the GVF Meter on Viscous Crude Oil The following well test result using the fixed separator and the new methodology including the GVF Meter and the standard SCADA well testing system was obtained and compared to the last Portable Test Separator test Portable Se arator Fixed Se arator Oil BPD 366 498 Water BPD 29 42 GOR 1142 1272 Water Cut % 7.3 7.8 Table 1 -Well Test Comparison of Portable to Fixed Test Separator SPE 100893 Conclusions The preliminary results of the pilot test to date look very promising; the objectives of the test are being met, i.e. to check the long term stability and performance of the GVF Meter under differing conditions. The presence of free gas in the liquid leg of the mini Test Separator when testing cold viscous wells was postulated; the GVF Meter has provided a quantitative measurement of this free gas. The secondary objective was to try and determine limitations of GVF Meter which we have achieved. When testing viscous wells with water present it is important to inject anti-foam to make the system operate correctly. Please note these wells have gas artificial lift. Only the results of one well are provided here because formal review all the data from all wells needs to be collected before it can be disseminated. Preliminary reviews indicate that a GVF is present in all well testing even on the PBU wells. However three of these GVF Meters will be installed on three mini 2-Phase Test Separators working on viscous and PBU crude oil. Several years of work has gone into perfecting the approach to the density method water cut. The addition of the GVF capability is the last piece of the puzzle to ensure accurate well testing. Acknowledgements I thank the management of BP Exploration (Alaska) Inc., Conoco Phillips Alaska Inc. and Exxon Mobil Corp. for their support and for granting permission to publish this paper. I thank Fred Bakun for all the work he provided in developing the oil shrinkage and solution gas factors that enabled the new approach to density water cut to be developed. Also for all the patient hours we spent in detailed discussion to fine tune the overall density method. I would also like to thank: Richard Volz of E&P Technology Group, BP America Inc for his support of this pilot program which enable BP Corporate to provide funds towards the pilot program and for his encouragement to perform these tests and publish this paper. Michael Bolkovatz, Hal Tucker, Rob Kruger and Bruce Weiler for their support and encouragement as well as their technical insight that was invaluable to assist with solving this problem. Douglas Loose for his valuable support during installation and commissioning of the GVF Meter. His technical assistance with solving the GVF performance problems during the pilot tests proved to be valuable for solving the operational problems. Nomenclature GVF =Gas Void Fraction API =American Petroleum Institute AGA =American Gas Association PBU =Prudhoe Bay Unit (Oil Field on the North Slope) IPA =Initial Participating Areas GPB = Greater Prudhoe Bay (PBU plus Greater Point Macintyre and other satellite fields) WOA =Western Operating Area of the PBU EOA =Eastern Operating Area of the PBU GOR =Gas Oil Ration SCF /Barrel GC =Gathering Center (Production Facilities in the WOA) FS =Flow Station (Production Facilities in the EOA) TAPS = Trans Alaska Pipeline System ALPS = Alyeska Pipeline Service Company. PS 1 =Pump Station 1 of TAPS MBPD =Thousand Barrels per Day STB =Stock Tank Barrels (Base Conditions 0 PSIG & 60°F) SCF =Standard Cubic Feet (Base Conditions 14.65 PSIA & 60°F) PSIG =Pounds per Square Inch Gauge PSIA =Pounds per Square Inch Absolute SOS =Speed of Sound WC =Water Cut X19 • by Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. May 13, 2008 John K. Norman Chairman Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907) 564-5769 Fax: (9071564-5706 Email: gotdon.pospisilQbp.com Re: Application Report for EMST"' Multiphase Metering System (ASRC Unit 5) Amendment to CO 550 -Milne Point Oil Pool Dear Mr. Norman: Attached is the BP Exploration (Alaska) Inc. (BPXA) report of results for field testing the' EMSTM meter system for portable well testing -currently designated as ASRC Unit 5. The attached report fulfills the requirements in the "Guidelines for Qualification of Multiphase meters for Well Testing" ("Guidelines") dated November 20, 2004 and the conditions outlined in the Commission's approval letter of November 14, 2006. Under the "Guidelines", this data qualifies use of ASRC Unit 5 at Milne Point Oil Pool, (CO 550) for production allocation well testing. Should you have any questions regarding this report, please contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Sincerely, Gordon ospisil BPXA Report of EMST"' Meter System Results Page 2 Technology & Resource Manager Cc: Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA John McMullen, BPXA Sherri Gould, BPXA John Cyr, BPXA Jerry Brady, BPXA Alan Mitchell, BPXA Sonny Rix, ExxonMobil Dan Kruse, CPAI • • Field Qualification of ASRC Unit 5 for Milne Point Well Testing Background The basis of design and principle of operation of the multiphase metering system that is incorporated in the ASRC Unit 5 well testing trailer were described fully in the document submitted to AOGCC titled "AOGCC -Application Report for EMST"' Multiphase Metering System"..The system utilizes a partial separator in conjunction with two TopFlowT"' (TF) multiphase meters to measure oil, water and gas rates. Testing conducted This report summarizes the results of qualification field tests conducted at Milne Point to verify the ASRC Unit 5 performance and uncertainty for well testing. The qualification process followed the AOGCC "Guidelines for Qualification of Multiphase Metering System for Well Testing". The objective of the testing campaign was to provide supporting data to qualify ASRC Unit 5 to be used for well testing within the Milne Point Field. These tests were conducted between July 2007 and April 2008. The testing protocol followed the steps provided in Section 3 of the AOGCC Guidelines. The qualification tests for Unit 5 required comparison to reference field measurements. Options used to determine the references were: Capturing fluids that flow through the system during the test and measuring them with secondary equipment. Samples obtained from online fluids were used to measure the water cut. This water cut was used as the reference to verify the water cut measurement uncertainty of Unit 5. Indexing the performance of the new system against an established multiphase measurement system such as a Type I gravity based test separator. This option was used in piggy back tests where Unit 5 performance was compared with the ASRC Unit 1. 3. A combination of the above options was used in a number of tests. With the understanding that there might be some uncertainty in the reference measurements, a number of steps were taken to calibrate and maintain the quality of the reference measurement systems. These steps included development of test procedures and installation of a new gas carry-under monitoring device on Unit 1. For piggy back tests, the well fluids from the header were directed to Unit 5, then to Unit 1, and when appropriate to a set of tanks for tank measurements. Well testing timelines and protocols The test program was conducted in three stages. The first stage took place in July and August 2007 at GPB L and E pads, and Milne Point S and H pads. These tests were essentially "burn-in" trials for Unit 5 to assess how the hardware worked. Well test data from this stage was used to revise hardware, fluid data input and crew training as well as the testing protocol for Unit 5. Tank strapping tests were also conducted in this stage and were used to verify the uncertainty of liquid measurements for both Unit 1 and Unit 5. The second stage of the test program took place in December of 2007 at Milne Point I-Pad to assess the effectiveness of the revisions made after the first stage of trials. These tests were conducted in series with Unit 1. Page 1 of 5 • • The third stage of the test program involved deployment of Unit 5 without piggy back testing with Unit 1. Unit 5 results from these tests were compared with historical field data and water cut samples obtained during the tests. The intent of this approach was to expedite testing and generate as much data as possible over a larger number of wells and pads. A secondary objective of these tests was to address water cut discrepancies in the data that were noted in stages 1 and 2 due to fluid property input. Additionally, a number of outlier well tests - from S and I pads -were retested in this stage. The major factor contributing to these out of spec tests turned out to be due to improper fluid property inputs - i.e. density, permittivity, and conductivity data. During this third stage Unit 5 returned to S-pad for 4 piggy back well tests with Unit 1. During the third stage of testing special attention was paid to fluid property input. One of the most important inputs for high water cut is the conductivity of the water, and a new monitor for measuring the conductivity of water samples was introduced into the procedure. Specific test protocol covering configuration of the multiphase meters, fluid property inputs, water cut indexing, and Unit 5 operations were developed for this phase of field testing. The crews of Unit 5 also received extensive training in collecting and entering fluid data to the Unit 5 input files. As a part of this training, Unit 5 crew also got instruction on downloading and archiving raw data and service files associated with each test. These files were used later on to reprocess selected well tests with updated fluid properties and configuration. Table 1: Summary of Unit 1 qualification testing Test phase Location Number of tests Test methods July -August 2007 Prudhoe Bay: E Pad 1 well (4 tests) Series testing with Type Prudhoe Bay: L Pad 12 wells (51 tests) 1 gravity separator Milne Point: H Pad 3 wells (3 tests) (ASRC Unit 1); Tank Milne Point: S Pad 7 wells (11 tests) strapping; Water cut sampling December 2007 Milne Point: I Pad 6 wells 17 tests) Series testing with Type 1 gravity separator (ASRC Unit 1); Water cut sampling January - February2008 Prudhoe Bay: V Pad 15 wells (16 tests) Series testing with Type 1 gravity separator (ASRC Unit 1); Water cut sampling March 2008 Milne Point: S Pad 4 wells (4 tests) Series testing with Type 1 gravity separator (ASRC Unit 1); Water cut sampling March -May 2008 Milne Point: B Pad 6 wells (9 tests) Water cut sampling Milne Point: G Pad 6 wells (11 tests) Milne Point: I Pad 6 wells (17 tests) Milne Point: J Pad 7 wells (9 tests) Milne Point: K Pad 9 wells (14 tests) Milne Point: S Pad 11 wells (19 tests) Page 2 of 5 • • Test results for Milne Point well tests Liquid flowrate Results from 24 piggy back tests conducted in 2007- 2008 at Milne point show that Unit 5 can measure total liquid to ± 10% of Unit 1 and Tank tests. (Figure 1). The gross fluid comparison with historic well data was influenced by changes in ESP and BHP behavior. Most differences can be explained from the ESP and BHP changes. Several instances of under-reading gross fluid rates were noted on Schrader wells; but excellent results were obtained on Kuparuk wells (MPK-padl. Water cut The results of some 77 tests conducted up to April 21, 2008 show a water cut uncertainty band of about ±2.5 to ±5%. (Figure 2). The well tests represent wells from six different pads at Milne Point, with a broad range of fluid properties and different methods of lift. This level of water cut uncertainty over a wide range of pads and wells is considered to be extremely good and should improve the uncertainty of oil rate determination, relative to the current methods of well testing. The water cut data showed very good comparison to historic data with almost all results were within the 5% band of historic values. Some differences are explainable due to changes in well trends. Gas flowrate For Milne Point, assessing the gas rate uncertainty is difficult due to lack of quality reference data at these low gas rates. Figure 3 shows gas rate measurements for 24 piggy back tests conducted in 2007- 2008 at Milne point. The dotted lines indicate the ±10% limits. The gas rate comparisons with historic data are influenced greatly by ESP and BHP behavior. In addition, the low gas rate due to low GOR at Milne Point introduces larger uncertainty in the historical data. The results for gas rates were typically on trend and within the scatter of historic data. Figure 1: Liquid flowrate results 6000 5000 ~ 4000 ~_ d 3000 3 0 w 2000 c iooo 0 Page 3 of 5 ^ H pad - • I pad • S pad ' +/- 10 % • ~ /•• •" • • •. y», ~ r; ^),i,~ ~~ 0 1000 2000 3000 4000 5000 Unit 1 liquid flowrate (bbl/d) 6000 • Figure 2: Water cut results ioo% 90 80 70 ~.. ~ 60 V m 50 3 *- ao% Y C ~ 30% 20% ,o% o% • X G pad ® H pad o I pad ^ J pad O K pad • S pad +/- 2.5 ^ • // • ,..~"-. X • .-/ , ~~r • • ~, X ' ~~ Y ' ~ ^ 0% 10% 20% 30% 40% 50 % 60% 70% 80% 90% 100% Sample water cut (%) Figure 3: Gas flowrate results w v ~ 1000 d R 3 750 0 N !0 ~ 500 1500 1250 ^ H pad ' • I pad • • S pad • +/- 10 _• -.. 'f •• -, _ ~,. • c 250 0# 0 250 500 750 1000 1250 1500 Unit 1 gas flowrate (Mscfld) Page 4 of 5 i • Conclusions The ASRC Unit 5 has been put through a field qualification campaign during the period from July 2007 to May 2008. These tests were undertaken in compliance with the AOGCC "Guidelines for Qualification of Multiphase Metering System for Well Testing". During the qualification program 175 well tests were conducted, including wells and pads with different gross flow rates, water cut, and produced fluid characteristics. The objective was to expose Unit 5 to a variety of well testing conditions. Operational information gathered during the testing program has been used to improve the Unit 5 hardware and software. The crews operating Unit 5 have gone through intensive training. Unit 5 has been equipped with analytical tools for measuring fluid densities and produced water conductivity on site. These steps have proven to be very important tools for improving the performance and efficiency of Unit 5. Unit 5 performed some 100 well tests during the qualification program at Milne Point. The uncertainty of these tests was indexed against Unit 1, tank tests, and water cut samples. Evaluation of these tests shows that Unit 5 can measure water cut within ±2.5 to ±5% of the reference water cut measurements. This level of water cut measurement is within the expected long term observations of water cut at these well sites and should result in good production well tests. The gross fluid rate can be measured within ±10% of the reference rate, again with good correlation with historic data trends. Revisions implemented in the Unit 5 software are expected to improve the consistency of the liquid and gas rate measurement. The results of the qualification tests described in this report show that Unit 5 performance is well suited for the Milne Point field production measurements and will produce well test data to the required uncertainty levels. Page 5 of 5 ~~8 • Page 1 of 1 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, March 24, 2008 2:34 PM To: Colombie, Jody J (DOA) Subject: FW: Request for Extension of MPM test results From: Brady, Jerry L [mailto:Jerry.Brady@bp.com] Sent: Monday, March 24, 2008 2:33 PM To: Williamson, Mary J (DOA) Subject: RE: Request for Extension of MPM test results Jane, Thank you for your note below. May 31 st does appear doable to us at this time. Therefore BP is withdrawing our March 13, 2008 request for a time extension. Jerry From: Williamson, Mary J (DOA) [mailto:jane.williamson@alaska.gov] Sent: Wednesday, March 19, 2008 4:04 PM To: Brady, Jerry L Cc: Hartz, John D (DNR); Colombie, Jody J (DOA); Roby, David S (DOA); Maunder, Thomas E (DOA); Pospisil, Gordon; Hartz, John D (DNR); Foerster, Catherine P (DOA) Subject: Request for Extension of MPM test results Dear Jerry, On March 13, 2008, BP sent a request (through Gordon Pospisil) for a time extension for final reporting of multiphase meter field trials you have been conducting. Your request was to extend the final report date from March 31, 2008 to June 30, 2008. The Commission's November 30 approval of your last extension request ordered the reports to be filed by May 31, 2008, not March 31. I've attached that approval. You indicated that a May 31 deadline appears doable at this time, and therefor, BP is withdrawing the March 13, 2008 request for extension. Please let us know if this is correct. Jane Jane Williamson Senior Reservoir Engineer, PE AOGCC (907) 793-1226 3/24/2008 by Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. March 13, 2008 John K. Norman Chairman Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application Report for EMST"' Multiphase Metering System Amendment to CO 547 -Prudhoe Bay Oil Pool Amendment to CO 548 -Endicott Oil Pool Amendment to CO 550 -Milne Point Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 -Put River Oil Pool Amendment to CO 570 -Raven Oil Pool Amendment to CO 402A - Badami Oil Pool Dear Mr. Norman: j ~;or-se ~+rrrrl6TliS~ipr A~c~rage BP Exploration (Alaska) Inc. (BPXA), Operator of the above fields received approval from the Alaska Oil and Gas Conservation Commission to use the EMST"' meter system for well testing and allocation on the following conditions: 1) The EMST"" meter system is operated in accordance with Bf XA's application; 2) BPXA conducts field testing of the EMST"' meter syste i in accordance with plans outlined in their a-mail correspondence to Jane Williamsc ~ from Jerry Brady regarding "3M Field Qualifications Plan" on October 27, 2006; anc 3) BPXA's report of test results is provided to the Commission no later than September 1, 2007. This report date was extended to December 1, 2007 at BPXA's request by a Commission Administrative Approval dated August 24, 2007. BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907) 564-5769 Fax: (907) 5645706 Email: gordon.pospisilC~bp.com Further, the Commission approved BPXA's request to use the VxT"' meter systems for well testing and allocation of the following conditions: 1) The VxT"' meter system is operated in accordance with BPXA's application; • i BPXA Request for Clarification Meeting and Request for Hearing Page 2 2) BPXA conducts field testing of the VxT"' with aCDS-Gasunie separator system in a manner consistent with the agreed upon testing protocols referenced in condition 2 above for the EMST"' meter system; 3) The Commission may revoke the field testing requirement for the VxT"' with aCDS- Gasunie separator upon proper application from BPXA after sufficient operational experience with, and testing of, the CDS-Gasunie separator have proved to the Commission's satisfaction that it operates properly in the field; and 4) BPXA provides the Commission with a report detailing their operational experience with and testing of the VxT"" systems by December 1, 2007. Both report dates for the EMST"" meter system and the VxTM meter system were extended to March 31, 2008 at BPXA's request by a Commission Administrative Approval dated November 27, 2007. BPXA completed testing of the VxT"' and the EMST"' meter system at Victor Pad in the Prudhoe Bay field on February 7, 2008. Currently some additional testing of the EMST"' meter system is underway at the Milne Point field with its completion expected by the end of March. This meter testing was delayed as a result of construction delays for the VxT"" test skid and poor weather conditions in January on the North Slope. BPXA is requesting that the reports due date to the Commission be moved from March 31, 2008 to June 30, 2008. Current plans call for completing the testing of EMST"' meter system at Milne Point and fully analyzing all the data from both the V- pad tests and the Milne Point tests to be presented in a final report to the Commission. Should you have any questions regarding this request, please don't hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Thank you for your consideration on this matter. Sincerely, ,-. ~' Gordon Pospisil Technology & Resource Manager cc: Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA John McMullen, BPXA Sherri Gould, BPXA John Cyr, BPXA Jerry Brady, BPXA Alan Mitchell, BPXA Sonny Rix, ExxonMobil Dan Kruse, CPAI ~~7 by Gordon Pospisil Technology & Resource Manager BP Exploration IAlaska), Inc. November 14, 2007 John K. Norman Chairman Alaska Oil & Gas Conservation Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907) 564-5769 Fax: (907) 5645706 Email: gotdon.pospisilC~?bp.com Re: Application Report for EMST"" Multiphase Metering System Amendment to CO 547 -Prudhoe Bay Oil Pool Amendment to CO 548 -Endicott Oil Pool :Amendment to CO 550 -Milne Point Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 -Put River Oil Pool Amendment to CO 570 -Raven Oil Pool Amendment to CO 402A - Badami Oil Pool Dear Mr. Norman: BP Exploration (Alaska) Inc. (BPXA), Operator of the above fields received approval from the Alaska Oil and Gas Conservation Commission to use the EMSTM meter system for well testing and allocation on the following conditions: 1) The EMSTM meter system is operated in accordance with BPXA's application; 2) BPXA conducts field testing of the EMSTM meter system in accordance with plans outlined in their e-mail correspondence to Jane Williamson from Jerry Brady regarding "3M Field Qualifications Plan" on October 27, 2006; and 3) BPXA's report of test results is provided to the Commission no later than September 1, 2007. This report date was extended to December 1, 2007 at BPXA's request by a Commission Administrative Approval dated August 24, 2007. Further, the Commission approved BPXA's request to use the VxTM meter systems for well testing and allocation of the following conditions: 1) The VxTM meter system is operated in accordance with BPXA's application; 2) BPXA conducts field testing of the VxTM with a CDS-Gasunie separator system in a manner consistent with the agreed upon testing protocols referenced in condition 2 above for the EMSTM meter system; BPXA Request for Clarification ~ng and Request for Hearing Page 2 n 31 The Commission may revoke the field testing requirement for the Vxj"` with a CDS- Gasunie separator upon proper application from BPXA after sufficient operational experience with, and testing of, the CDS-Gasunie separator have proved to the Commission's satisfaction that it operates properly in the field; and 4) BPXA's provides the Commission with a report detailing their operational experience with and testing of the VxT"' systems by December 1, 2007. Due to significant construction delays for the VxT"' test skid and additional testing required to ensure that both metering system EMST"' and VxT"' are functioning within designed parameters, BPXA is requesting that the report date to the Commission be moved from December 1, 2007 to March 31, 2008. Current plans call for additional testing of EMST"' meter system and the VxT"' meter to begin in mid December 2007 or early January 2008. Further it is expected to take an additional 2 months to properly analyze all the data and finalize a report. Should you have any questions regarding this request, please don't hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Thank you for your assistance. Sincerely yours, ~~--. '~ ~ , -, `_ ~,; Gordon Pospisil Technology & Resource Manager Cc: Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA John McMullen, BPXA Sherri Gould, BPXA John Cyr, BPXA Jerry Brady, BPXA Alan Mitchell, BPXA Sonny Rix, ExxonMobil Dan Kruse, CPAI ,~ -=-#-16 bp .. . August 10, 2007 John K. Norman Chairman Alaska Oil & Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 Re: Application Report for EMSTM Multiphase Metering System Amendment to CO 547 - Prudhoe Bay Oil Pool Amendment to CO 548 - Endicott Oil Pool Amendment to CO 550 - Milne Point Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 - Put River Oil Pool Amendment to CO 570 - Raven Oil Pool Amendment to CO 402A - Badami Oil Pool Dear Mr. Norman: BP Exploration (Alaska) Inc. (BPXA), Operator of the above fields received approval from the Alaska Oil and Gas Conservation Commission to use the EMS TM meter system for well testing and allocation on the following conditions: 1) The EMS TM meter system is operated in accordance with BPXA's application; 2) BPXA conducts field testing of the EMS TM meter system in accordance with plans outlined in their e-mail correspondence to Jane Williamson from Jerry Brady regarding "3M Field Qualifications Plan" on October 27,2006; and 3) BPXA's report of test results is provided to the Commission no later than September 1, 2007. Due to si~ificant construction delays, ARSC and BP have just recently begun testing of the EMS meter skid. The skid is expected to take several weeks to test plus another 2 months to properly analyze all the data and finalize a report. Therefore BPXA is requesting that the report date to the Commission be moved from September 1 , 2007 to December 1, 2007. Should you have any questions regarding this request, please don't hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Thank you for your assistance. Sincerely yours, -~(;?~ Gordon Pospisil ' Technology & Resource Manager Cc: bp . . Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA John McMullen, BPXA Sherri Gould, BPXA John Cyr, BPXA Jerry Brady, BPXA Alan Mitchell, BPXA Sonny Rix, ExxonMobil Dan Kruse, CPAI BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 2 ~15 . . 5T A TE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO-02714029 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATIACHED COPY OF ORDER ADVERTISEMENT MUST BE SUBMITIED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 Jodv Colombie April 25, 2007 0 Anchorage,AJ( 99501 PHONE PCN M 907-793-1238 (907) 791 -1221 DATES ADVERTISEMENT REQUIRED: T Anchorage Daily News April 26, 2007 0 PO Box 149001 Anchorage, AJ( 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal~ 0 Display Classified DOther (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE I AOGCC, 333 W. 7th Ave., Suite 100 I TOTAL OF PAGE 1 OF ALL PAGES$ TO Anchorage, AK 99501 2 PAGES REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 029 IO FIN AMOUNT SY CC PGM LC ACCT FY NMR OIST UQ 1 05 02140100 73451 2 /-" //'\ /-, i REQUIS~O~ /Bt "^ 'I:11j) / IDIVISION APPROVAL: tI ( \:\¿/V ~ 02-902 (Rev:.1/94 Publisber/O . . al Co ies: De artment Fisca De artmen Receivin ) ngm p p I, p to g . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: BP Exploration (Alaska) Inc. ("BPXA") has requested authorization to use multiphase meters for well testing and allocation of production for all pools within the Badami, Endicott, Milne Point, Northstar, and Prudhoe Bay Fields. By application dated March 30, 2007, and received April 11, 2007, BPXA requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission"), to use a portable multiphase measurement device for well testing in BPXA operated fields in accordance with the Commission's document, "Guidelines for Qualification of Multiphase Meters for Well Testing" dated November 30,2004 as allowed by the following Conservation Orders: Prudhoe Bay Field: CO 559: Put River Oil Pool CO 570: Raven Oil Pool CO 547: All other oil pools within Prudhoe Bay Field Endicott Field: CO 548: All Endicott pools Milne Point Field: CO 550: All Milne Point pools Northstar Field: CO 551: Northstar Oil Pool Badami Field: CO 402A: Badami Oil Pool The Commission has tentatively scheduled a public hearing on this application for May 31, 2007 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than May 15,2007. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221 after May 29, 2007. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West 7111 Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than May 29, 2007 except that if the Commission decides to hold a public hearing, written protest or comments must be received no later than the conclusion of the May 31, 2007 hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing,;:le .. 'Contact the Commission's Special Assistant Jody Colombie at 793-1221 before May 29, 20. ) ~ /'J / , . Anchorage Daily News Affidavit of Publication 4/26/2007 1001 Northway Drive. Anchorage. AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 201352 04/26/2007 02714029 STOF0330 $242.36 $242.36 $0.00 50.00 $000 $000 $0.00 $242.36 Notice of Public Hearing Si sworn to me before this date: STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: BP Explorotion (Alosko) Inc. ("BPXA"¡ has requested authorization to use multi phose meters for well testing and allocation of production for 011 pools within the Badami, Endic:ott, Milne Point, Northstar, ond Prudhoe Bav Fields. By application doted March 30, 2007, and received April 11 2007, BPXA requested outhorization from the Ala~kaOil and Gas ConservationCommissic)n ("CommiSsion"), to use a poÍ'table multiphasemea· surement device for well testirg inBPXApperat~c, fields in.occordance with the-~Ornrt;1_i~_~ion'sdoC:lJ_~ ment,':Guidellnes for Qualificqtional,,^~ltiphase Meters for Well Testing" dat~dNovember 30,2004 050 lIowedby the following Cq"servation, Orders: Prudhoe Bav Field: C0559: P~tRiver Oil Pobl 'CO'570 :'Ra"en9il :pool 'CO:54hAII'other,oil pools within Prudhoe Boy Fièld Endic:attField: :: ::dZO"548:,AII..E,,cHcoH pools Milne PdirítField: Na~~Z{;~:þf;!¡d^:,ilne:pointPaols . CO 551:.'Northstar Oil Pool Badami. Field: CO 402A:Badami Oil Pool The Comm' . hostentq;iV~I~S¿h'edUI~ád~¡,hl ie heoringon pþlication.for May 31,2007 at 9:00 om at'the. ,'dlthe, Alaska Oil and Gas Conser- vdt i dn~Comrni ssi on 'at 333\iVest 7thi'>. v.~"ue.,S.~1 te 100, Arithoråge,Alas"ka 99501. Ap"rs~".rnaY re- quesHhatthe tentativelY scheduledM(]rl"~'~ held by tiling·a written request )Nith theßo!,,!,,'sslan no latérthónMó,y;J5,2007. If a'requestfor a Maringisnottrm~I,Yf¡led,Œ" C.ommissionmaV,consider the issuance: of an,pr.der without 0 hearing. To learn if the Commission will holdtheþÙþllehearing, please call 79,3' 1221af~er May 29; 2007. . STATE OF ALASKA THIRD JUDICIAL DISTRICT Christine Clark, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Trurd Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchora?;e, Alaska, and it is now and durin?; all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental fonn) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individu Subscribed an I)fLiAY J7 MO? ',;..,'. ,..'.:-:.»" --:--' --.-.:; I ,ri p#di t!º.~/b" p~rsqà .rnaY _ 5 ubm it wri ttencolT}mer;ats regarding th[s qpplicatian to the Alaska. Oil ,and q:Çls Conservation Commission at. 333 We'it 7t.h Ayen1J7' Suite 100, Anchorage, Alaska 99501·:. Wrotten com- ments must be received no later than May 29, 2007 except that if the Commission decides to hold, 0 pub- lic hearing, written protest or camme!1ts q¡ust be received no later than the conclusia!1 oHhe May 31. 2007 hearing. ' . .' If you are a person with 0 disability who may need a sp~cior l')1o(jification.. in.orde.r toctJml11~nt .or t~at- tend th'e public hearing, please contact t.he Commission's Special Assistant Jodý Colombie at '793-1221 before May 29, 2007. . . Is!: John K. Norman Chai.man Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY OMMISSION EXPIRES, (/ r r 9/XJ Z \\lI(((((f((t: ~f..~~y ,4. ;{r'i- .'11IIIIo.: . . .....' # .~~ 0b7~' ·~O..~~~j:·~~ !ß '.b.. ..... ::~: 1/1 ·-c.iBUC : ~ =- ~":;.\. ....... ...."":.ß:::.: -;:, .7~ ~. ~~ ~, ....~ OF Þ.\~"'· . {)....y ........ . . > :.' . . . ^ ~....... :\' "''/./'" ~X¡:lïï~;'~'\"" ')}))JJJJ¡!p) r/ / AO# 02714029 ¡ -I'rHP.i_iSh :,APri:i.. 2~'_:3Û~~_. Ii j' ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS "J MUST BE " """-'CATI' SH"",NG AD>ÆRn~NG ORDER."''''''' AO 02714029 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF - ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC 333 West 7ili Avenue. Suite 100 Anchorape_ AK <)<)SOl 907-793-1238 AGENCY CONTACT Jociv r. 1 1 . PHONE (<)07) 7<)1 -1)) 1 DATES ADVERTISEMENT REQUIRED: DATE OF A.O. R o M Anril)S 2007 PCN T o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 April 26, 2007 THE MATERIAL BE1WEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement. of which the annexed is a true copy, was published in said publication on the day of 2007, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2007, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2007, Notary public for state of ~.4y commission expires 02-901 (Rev. 3/94) Page 2 . . Subject: RE: Public Notice From: "Ads, Legal" <legalads@adn.com> Date: Wed, 25 Apr 2007 14:25:16 -0800 To: Jody Colombie <jody_colombie@admin.state.ak.us> Hello Jody: Following is the confirmation information on your legal notice. Please review and let me know if you have any questions or need additional information. Account Number: STOF 0330 Legal Ad Number: 201352 Publication Date(s): April 26, 2007 Your Reference Number: 02714029 Total Cost of Legal Notice: $242.36 Thank You, Kim Kirby Legal Classified Representative E-mail: legalads@adn.com Phone: (907) 257-4296 Fax: (907) 279-8170 -----Original Message----- From: Jody Colombie [mailto:jody colombie@ad~in.state.ak.us] Sent: Wednesday, April 25, 2007 12:54 PM To: Ads, Legal Subject: Public Notice Thank you 1 of! 4/25/2007 2:40 PM . . Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Wed, 25 Apr 2007 12:54:14 -0800 To: Legal Ads Anchorage Daily News <legalads@adn.com> Thank you Jody Colombie <¡oay coloTI1bie(êi¿adrniILstate.alc.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/msword Ad Order ADN form.doc Content-Encoding: base64 Content-Type: application/msword MPM Notice 2.doc Content-Encoding: base64 1 of 1 4/25/2007 2:40 PM . . Subject: Multiphase Meters Public Notice From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 25 Apr 2007 14: II :26 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, trmjrl <trmjrl@aol.com>,jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <bl@mapalaska.com>,jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@alaskadc.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>" Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustria1.com>, ghammons <ghammons@ao1.com>, rmclean <nnclean@pobox.alaska.net>, mkm7200 <mkm7200@ao1.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoi1.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, James Scherr <james.scherr@mms.gov>, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Karl Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unoca1.com>, Gary Rogers <gary _rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <klyons@otsintl.com>, Steve Lambert <salambert@unoca1.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <cammy_taylor@dnr.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Keith Wiles lof2 4/25/2007 2:40 PM · . <kwiles@marathonoil.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg <jimJegg@admin.state.ak.us>, Catherine P Foerster <cathy_foerster@admin.state.ak.us>, , gregory micallef <micallef@clearwire.net>, Laura SiUiphant <laura_silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobil.com>, akpratts@acsalaska.net, Robert CampbeU <Robert.CampbeU@reuters.com>, Steve Moothart <steve_moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paul_bloom@ml.com>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple _ davidson@dnr.state.ak.us> , Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegarner <jimwinegarner@brooksrangepetro.com>, Matt Rader <mattJader@dnr.state.ak.us>, carol smyth <caro1.smyth@shel1.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoil.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@international.gc.ca>, Cary Carrigan <cary@kfqd.com>, Sonja Frankllin <sfranklin6@bloomberg.net>, Mike Bill <Michae1.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, "Alan Birnbaum <\"\"Alan J Birnbaum \">" <alan _ birnbaum\"@law.state.ak.us>, Randall Kanady <Randal1.B.Kanady@conocophillips.com>, MJ Loveland <N 1878@conocophillips.com> Jody Colombie <jody colombie(w.admin.state.ak.Lls> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf Multiphase meters notice.pdf Content-Encoding: base64 20f2 4/25/2007 2:40 PM . Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahnng NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Mark Wadman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Cin Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 \,t ~\C\\ GV 0 7 ~\{l #14 March 30 Multimetering This section is scanned separately and can be found under the parent folder for this file. -*\3 [Fwd: [Fwd: 3MField QualificationPlan.doc]] . . Subject: [Fwd: [Fwd: 3MField QualificationPlan,doc]] From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: Tue, 14 Nov 2006 15:13:10 -0900 To: Jody J Colombie <jody_colombie@admin,state.ak.us> I sent it. Here it is. Print off the attachment as well -------- Original Message -------- Subject: [Fwd: 3MField QualificationPlan.doc] Date: Mon, 13 Nov 2006 11:37:27 -0900 From: Jane Williamson <jane williamson@admin.state.ak.us> Organization: State of Alaska To: Jody J Colombie <jody colombie@admin.state.ak.us> Jody, This should go into all the MPM administrative amendment files. -------- Original Message -------- Subject: 3MField QualificationPlan.doc Date: Fri, 27 Oct 2006 12:03:00 -0800 From: Brady, Jerry L <Jerry.Brady@bp.com> To: Jane Williamson <jane williamson@admin.state.ak.us> CC: Pospisil, Gordon <Gordon.Pospisil@bp.com>, Digert, Scott A <Scott.Digert@bp.com>, Frontin, Russell A <Russell.Frontin@bp.com> Jane, Attached is the objectives and a brief description of how we intended to perform the North Slope testing. When the test nears I will informally send you more details. Also you are invited to come up and tour the test setup when we are operational. Jerry «3MField QualificationPlan.doc» Jane Williamson, PE <iane williamson(G!admin.state.ak.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission Content-Type: application/msword 3MField QualificationPlan.doc E b Content- ncoding: ase64 1 of 1 11/14/20063:16 PM . . 3M Unit Field Qualification Tests - Preliminary Plan Objectives: . Check out the safety and operations of the unit. . Test wells at representative rates and conditions that the unit will operate in: 0 Various reservoirs and fluid conditions. · Prudhoe (Sadlerochit) · Kuparuk · Schrader Bluff 0 Gas Volume Fractions. · Low as practical « 60%) - 1 00% 0 W atercuts. · o - High as practical (> 90%) Tentative Test Plan: Planned test configuration will be well header> ASRC 3M Unit> ASRC Unit 1 that will be used for reference> pad separator (where practical). This will be reviewed to ensure safety and that all operational concerns have been addressed. Changes may occur after this review. 1-1 #I:l [Fwd: RE: Notict:J . . ~. Subject: [Fwd: RE: Notice] From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Mon, 13 Nov 2006 11 :36:43 -0900 To.; JodyJ<;;D'ôlômbiè <j ody_colômbie@åâmìn:state.ak.µs> This goes into all the MPM files -------- Original Message -------- Subject: RE: Notice Date: Thu, 12 Oct 2006 17:21:27 -0800 From: Brady, Jerry L <Jerry.Brady@bp.com> To: Jane Williamson <jane williamson@admin.state.ak.us> Jane, Below are the dates when the Application Report fro EMS Multiphase Metering System was sent to the company/agency that are financially impacted parties: Company/Agency Contact Name Date Mailed AOGCC Jane Williamson 8/30/06 DNR - DOG Art Copoulos 8/30/06 DOR Robynn Wilson 8/30/06 1 of3 11/13/20063:32 PM [Fwd: RE: Notic~] . " . ~ MMS Kyle Monkelien 10/10/06 ExxonMobil Sonny Rix 8/30/06 ConocoPhillips Dan Kruse 8/30/06 Chevron Gary Forsthoff 10/11/06 Forest Oil Leonard Gurule 10/11/06 Doyon Ltd Ron Wilson 10/12/06 Nana Heli Sanvik 200 11/13/20063:32 PM [Fwd: RE: Notic~] . . ,. '" 10/12/06 Anadarko Mark Hanley 10/12/06 Union Oil Glenn Fredrick 10/12/06 Murphy Ignacio Herrera 10/11/06 Jerry ------------------------------------------------------------------------ *From:* Jane Williamson [mailto:jane williamson@admin.state.ak.us] *Sent:* Tuesday, October 10, 2006 1:57 PM *To: * Brady, Jerry L *Subject:* Notice Could you please send a list of every company/agency you notified and the date of notification. Based upon Table 2A.1 the financially impacted parties are Chevron, ConocoPhillips, Exxon, Forest, Doyon, Nana, Murphy, DOG, MMS Jane Williamson, PE <jane williamson@,admin.state.ak.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission 3 on 11/13/20063:32 PM *1' · FIK H. MURKOWSKI, GOVERNOR DEPARTMENT OF NATURAL RESOURCES o 550 WEST 7TH AVENUE. SUITE 800 ANCHORAGE, ALASKA 99501-3650 DIVISION OF OIL AND GAS PHONE: (907) 269-8800 FAX: (907) 269-8938 November 2,2006 Mr. John Nonnan, Chainnan Alaska Oil & Gas Conservation Commission 330 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: AOGCC "Application Report" for EMS™ Multiphase Metering System" - For Use at Badami Unit, Endicott Unit, Prudhoe Bay Unit and Northstar Unit. Dear Commissioner Nonnan, The Division of Oil & Gas (Division) received the subject application in September, 2006. The application was reviewed and found to be an infonnative rendition of the technology available and a good source of quality assurance infonnation for the proposed system. The Division has a large stake in accurate well allocation in a number of pools on the North Slope. The applicant cited twenty-four different pools where the portable EMS MPM System may be used, and in eight of those pools there are tracts with differential royalties ranging from 12.5-20%. If a new system is implemented, the Division wants to assure it maintains the quality of current well test and subsequent production allocation data. The Division supports application of the EMS MPM System on the North Slope. The Division prefers a test and evaluation period of up to a year before AOGCC issues pennanent Orders regarding the use of the EMS MPM System as a production allocation tool and offers the following recommendations: 1. The Division supports the AOGCC's evaluation of multiphase metering for well test and allocation procedures. 2. The Division's support is based in part on the operator conducting a test and evaluation of six months to a year before AOGCC issues a final order for acceptance of MPM results for production allocation. In addition, the Division: 0 Requests periodic reports on EMS MPM perfonnance and evaluation. 0 Requests BPXA provide a summary of the MPM calibration and maintenance procedures and periodic results of the calibrations. "Develop, Conserve, and Enhance Natural Resources for Present and Future Alaskans. " . . 3. Final approval of the EMS MPM should be contingent on results of the performance during the period of conditional approval, and the concurrence of the Division as mineral owner. Please call me or Jack Hartz if you have any questions about these recommendations. ~L f William Van Dyke I Acting Director cc: Julie Houle, Petroleum Geologist Mike Kotowski, Petroleum Reservoir Engineer Art Copoulos, Petroleum Land Manager Temple Davidson, Economist Jack Hartz, Petroleum Reservoir Engineer *"ID n.."'-'. j,-",-,,,,-,VUUu,,,-,uuauvJ.J. LV VQ."'-'aL\;,.. V\",L. ~U H\;Q.I lilt; Vii VI iVJJ 1\'1 appU\",aLlUU . . Subject: Re: Recommendation to vacate Oct. 26 hearing on BP MPM application From: Cathy Foerster <cathy_foerster@admin.state.ak.us> Date: Tue, 17 Oct200612:10:13 -0800 To: Jane Williamson <jane _ williamson@admin.state.ak.us> cc: John Norman <john_norman@admin.state.ak.us>, Dan T Seamount <dan_seamount@admin.state.ak.us>, Jody J Colombie <jody_colombie@admin.state.ak.us>, Thomas E Maunder <tom _ maunder@admin.state.ak.us>, Dave Roby <dave _roby@admin.state.ak.us> 1 agree Jane Williamson wrote: I recommend that we vacate the Oct. 26 hearing concerning BP's request to use MPM in BP's north slope properties. I participated in a technical overview session with reps from BP, DOG, MMS, ASRC this morning. ASRC is currently assembling the meter skid. Field testing at Prudhoe and Milne should begin next month. The field tests will include testing of Ivishak, Kuparuk and Schrader Bluff formations at Prudhoe and Milne Point at a full range of gas volume fractions and watercuts. The Multiphase Unit will be indexed to the current existing ASRC portable test separator and also compared to the pad separator. The individual meters in all test systems will be fully calibrated prior to testing. Tank gaging will also be used during some of the initial tests. BP satisfactorily answered all questions I had concerning the meter and the requirements of the MPM Guidelines will have been fully met once the field testing is completed and documented. DOG agreed that, depending upon favorable field test results, the MPM should provide sufficient accuracy for use in well testing in BP's North Slope properties. There are no immediate plans to use the meter at Northstar, but MMS has no objection that Northstar be included in this plan - so long as they are notified before the meter is used at the Unit. Cathy Foerster Commissioner Alaska Oil and Gas Conservation Commission I of I 10/] 7/2006 I :04 PM rtearIng vacaLCU . . Subject: Hearing vacated From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: Tue, 17 Oct 2006 12: 19:09 -0800 To: Jerry Brady <bradyjl@bp.com> cc: Jody J Colombie <jody_colombie@admin.state.ak.us> Jerry, Thank you for setting up the meeting this morning concerning BP's application to use the FMC EMS multiphase metering system for well testing within BP operated north slope properties.. All of my questions were answered and we have received no request for hearing. Therefor, the Commission is vacating the Oct. 26 scheduled hearing. Jane Jane Williamson, PE <iane williamson(a?admin.state.ak.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission I of I 10117/2006 1:04 PM #q . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: BP Exploration (Alaska) Inc. ("BPXA") has requested authorization to use multiphase meters for well testing and allocation of prùduction for all pools within the Endicott, Milne Point, Northstar, and Prudhoe Bay Fields By application dated August 30, 2006 and received September 12, 2006, BPXA requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission"), to use a portable multiphase measurement device for well testing in BPXA operated fields in accordance with the Commission's document, "Guidelines for Qualification of Multiphase Meters for Well Testing" dated November 30,2004 as allowed by the following Conservation Orders: Prudhoe Bay Field: CO 559: Put River Oil Pool CO 570: Raven Oil Pool CO 547: All other oil pools within Prudhoe Bay Field Endicott Field: CO 548: All Endicott pools Milne Point Field: CO 550: All Milne Point pools Northstar Field: CO 551: Northstar pools The Commission has tentatively scheduled a public hearing on this application for October 26, 2006 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th A venue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on October 11, 2006. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221 after October 18, 2006. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on October 23, 2006 except that if the Commission decides to hold a public hearing, written protest or comments must be received no later than the conclusion of the October 26, 2006 hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hear' g, p ase contact the Commission's Special Assistant lody Colombie at 793-1221 befo c r 23, 6. Published Date: September 22, AO 02714006 STATE OF ALASKA . NOTICE TO PUBLISHER . ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO, CERTIFIED AO-02714006 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS I' AOGCC AGENCY CONTACT DATE OF A.O, R 333 W 7th Ave, Ste 100 Jody Colombie September 19,2006 0 Anchorage, AK 99501 PHONE PCN M - (907) 793 -12?1 DATES ADVERTISEMENT REQUIRED: T Anchorage Daily News September 22, 2006 0 Anchorage, AK THE MATERIAL BETWEEN THE OOUBLE LINES MUST BE PRINTEO IN ITS ENTIRETY ON THE OATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed STOF0330 Type of Advertisement Legal~ D Display Classified DOther (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE I AOGCC, 333 W. 7th Ave., Suite 100 I TOTALOF PAGE 1 OF ALL PAGES$ TO Anchm:ure, AK 99';01 2 PAGES REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 3 4 ¡::IN AMnllNT ~v rr P~M Ir ArrT ¡::v NMR DIST LlQ 1 05 02140100 73451 2 3 (\ r, a , 0 ' ,\ REQUISITIONED BY, { . . QJQ. / DIVISION APPROVAL: \ i~'~ /VvV~' ¡ \ I . Copies: Department Fiscal, DepartmenlceiVing I 02-902 (Rev. 3/94) Publisher/Original AO,FRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO. CERTIFIED AO 02714006 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF - ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DA TE OF A.O. R 333 West ih Avenue. Suite 100 Jodv Colomhie Sentember 19. 2006 0 A nrhnnlUP A K QQ&:¡O 1 PHONE PCN M 907-793-1221 (907) 793 -1?21 DATES ADVERTISEMENT REQUIRED: T Anchorage Daily News September 22, 2006 0 Anchorage, AK THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER division. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2006, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2006, and that the rate charged thereon is not in excess of the rate charged private individuals, Subscribed and sworn to before me This _ day of 2006, Notary public for state of My commission expires . . , Mary Jones David McCaleb Mona Dickens XTO Energy, Inc, IHS Energy Group Tesoro Refining and Marketing Co, Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft Worth, TX 76102 -6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Kay Munger Michael Parks 200 North 3rd Street, #1202 Munger Oil Information Service, Inc Marple's Business Newsletter Boise, 10 83702 PO Box 45738 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Seattle, WA 98119-3960 Mark Wedman Schlumberger Baker Oil Tools Halliburton Drilling and Measurements 4730 Business Park Blvd" #44 6900 Arctic Blvd, 2525 Gam bell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Jill Schneider Land Department 9649 Musket Bell Cr#5 US Geological Survey PO Box 93330 Anchorage, AK 99507 4200 University Dr Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc, Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough Williams Thomas PO Box 69 Arctic Slope Regional Corporation Barrow, AK 99723 Land Department PO Box 129 Barrow, AK 99723 vups . . Subject: Oops From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Tue, 19 Sep 2006 13:38:49 -0800 To: Legal Ads Anchorage Daily News <legalads@adn.com> Please disregard the first ad order form it had the Journal of Commerce on it. Content- Type: application/msword Ad Order form.doc Content-Encoding: base64 Content- Type: application/msword MPM N otice.doc - Content-Encoding: base64 l of I 9119/2006 1:39 PM ruulI\",. l"1ULH.;ç: . . Subject: Public Notice From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Tue, 19 Sep 200613:41:36 -0800 To: undisclosed-recipients:; BCC: Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjr 1 <trmjr 1 @aol.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p. worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr,state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesno 1 @gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>,jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, loren_leman <loren_leman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm 7200 <mkm 7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>,jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, nI617@conocophillips.com, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Todd Kratz <ToddKratz@chevron.com>, Gary Rogers <gary Jogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <ken@secorp-inc.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews of2 9/19/2006 1:53 PM ïUUlll: l'lUlIl:t: . . <Iris_Marthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, Rob Dragnich <rob.g.dragnich@exxonmobi1.com>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Alicia Konsor <alicia_konsor@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoi1.com>, Cammy Taylor <Camille_Taylor@law.state.ak.us>, Winton GAubert <winton_aubert@admin.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoi1.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg <jimJegg@admin.state.ak.us>, Catherine P Foerster <cathy_foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <laura _ silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobi1.com>, akprarts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve_moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paul_bloom@m1.com>, Sonja Franklin <sfranklin6@blomberg.net>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Cynthia B Mciver <bren _ mciver@admin.state.ak.us> Content-Type: application/pdf PBU END MILNE NS.pdf Content-Encoding: base64 ~ of2 9/19/2006 1:53 PM :#=8 [Fwd: RE: EMS MPM Request] . . Subject: [Fwd: RE: EMS MPM Request] From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Fri, 06 Oct 2006 12:38:25 -0800 To: JodyJ Colombie <jgdy _ colombie@admin.state.ak.us> Please put in the MPM order files. Have you had request for hearing yet? -------- Original Message -------- Subject: RE: EMS MPM Request Date: Fri, 15 Sep 2006 15:18:30 -0800 From: Brady, Jerry L <Jerry.Brady@bp.com> To: Jane Williamson <jane williamson@admin.state.ak.us> CC: Pospisil, Gordon <Gordon.Pospisil@bp.com>, Parviz Mehdizadeh <p.mehdizadeh@cox.net>, Dawson, Steve W (ASRC Energy Services) <steve.dawson@asrcenergy.com>, Frontin, Russell A <Russell.Frontin@bp.com> Jane, We have discussed a testing plan with ASRC and Parviz. However, we have not firmed it up yet. Your note will help spur us along. The basic idea will be to piggy back the EMS unit with and existing ASRC unit through various conditions and reservoirs. This testing will begin once the unit has been commissioned and the operators have been trained. Parviz is scheduled to come up in about a month to help with the training. We will have a test plan in place by then. Jerry -----Original Message----- From: Jane Williamson [mailto:jane williamson@admin.state.ak.us] Sent: Friday, September 15, 2006 3:08 PM To: Brady, Jerry L Subject: EMS MPM Request Jerry, I've taken a quick read of your application. It looks very good. Could you tell me what your specific plans are for field testing the meter system? The Appendix 10 guidelines look good, but I need a few more specifics on what these field testing plans are. I will be recommending that the Commission requires the field tests with results reported to us in the early phases of use. Since this is the first MPM application, and you have to get DNR (and I think MMS approval for Northstar), I think it's best to notice for hearing. I expect the notice to go out on this around Tuesday. If nobody asks for a hearing, we'll be able to continue on and write the orders. Depending upon when Jody is able to get this on the calendar, the approvals should be in hand by end of October. If you want to proceed with testing before that time, please let me know. We can do an interim administrative approval fairly quickly. You'll need to provide your testing plans though (as I've asked above). Call if you have questions. Jane Jane Williamson, PE <iane williamson~admin.state.ak.us> 10f2 10/6/2006 1 :22 PM *1 . . August 30, 2006 Jane Williamson Alaska Oil & Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 Art Co poulos .' .~. Division of Oil and Gas Department of Natural Resources 550 West ih Avenue, Suite 800 Anchorage, AK 99501 Robynn Wilson Tax Division Department of Revenue 550 West ih Avenue, Suite .500 Anchorage, AK 99501 Re: Application Report for EMS TM Multiphase Metering System Amendment to CO 547 - Prudhoe Bay Oil Pool Amendment to CO 548 - Endicott Oil Pool Amendment to CO 550 - Milne Point Oil Pool Amendment to CO 551 - Northstar Oil Pool Amendment to CO 559 - Put River Oil Pool Dear Ms. Williamson, Mr. Co poulos and Ms. Wilson: BP Exploration (Alaska) Inc. (BPXA), Operator of the fields shown in Appendix 2 of the attached Application Report, hereby requests authorization to use a portable multi- phase measurement device, as described in the Application Report, for the purpose of well testing and production allocation within BPXA operations conducted in the Prudhoe Bay Oil Pool, Endicott Oil Pool, Milne Point Oil Pool, Northstar Oil Pool and Put River Oil Pool pursuant to 11 AAC 83.371, 20 MC 25.228, and 20 MC 25.230. The report describes the design, the expected performance and the anticipated applications of the FMC Technologies Enhanced Multiphase System™ (EMSTM) for well testing in these BPXA operations. BPXA also requests an amendment to each of the aforementioned AOGCC Conservation Orders (CO) governing each pool in order to allow for the use of multi- phase meter technology as described in the Attached Report. BPXA has conducted extensive study of multi-phase metering technology. In September 2003 BPXA conducted a field trial in Prudhoe Bay of four (4) different kinds of multi-phase meters. These meters were tested in a series and were statistically evaluated for accuracy, precision, and repeatability against a known standard two- phase separator. Based on the result of this test and other experience gained . . I throughout the world, BPXA has gained an improved understanding of the applicability and limitations of multi-phase metering to North Slope production wells. The EMS TM is designed to deal with the high gas volume fraction production streams encountered in many of the BPXA operations. The EMS TM system can remove high gas volumes from the inlet to the multiphase meters by employing a proven cyclonic separator developed by CDS Engineering of The Netherlands. This separator is known as a Gasunie and it is capable of high degree of separation efficiency as compared to conventional separation technology. With a high level of confidence in the removal of a minimum of 80% of the gas from the well stream, the FMC Technologies TopFlow multiphase meter is permitted to operate within the highest accuracy range for liquid, water cut and gas measurement. The proposed multiphase metering system is designed as a mobile unit. The unit will be operated by AES O&M (ASRC) who has extensive experience in well testing and a track record with mobile test units in the BPXA operations. ASRC has also taken a principal role in designing the unit and is intimately familiar with the operations of the metering system. The AOGCC Application Report submitted herein compiles the data and literature that were used to qualify the design and establish performance levels for the EMSTM skid. This document was prepared following the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued November 30, 2004 by the AOGCC. Approval of this request will advance the use of multi-phase technology for North Slope production measurements. It will allow BPXA to gain operational experience with this meter while demonstrating multi-phase metering technology can provide allocation well tests comparable to a conventional portable separator. It will also free up limited portable separator units, currently used for well production allocation testing, to do flowback jobs on new production wells and after wellwork. Additional benefits from a portable multi-phase meter includes improved testing frequency (faster rig-up, no stabilization period required), production fingerprinting (no vessel dampening), reduced HSE risk (smaller footprint, fewer personnel, no vessel), and opportunity for lift optimization. Should you have any questions regarding this request, please don't hesitate to contact Jerry Brady of my staff at 564-5291. We would be pleased to provide additional information on this subject at your convenience. Thank you for your assistance. Sincerely yours, ~ -- - "'" Gordon Pospisil GPB Waterflood Manager Attachment 2 . . Cc: Frank Paskvan, BPXA Scott Digert, BPXA Diane Richmond, BPXA Mark Weggeland, BPXA John McMullen, BPXA Gary Gustafson, BPXA Rosanne Jacobsen, BPXA Jerry Brady, BPXA Sonny Rix, ExxonMobil Dan Kruse, CPAI Alan Mitchell, BPXA . . AOGCC "Application Report" for EMSTM Multiphase Metering System BP Exploration (Alaska) Inc. July 2006 . . AOGCC "Application Report" for EMSTM Multiphase Metering System BP Exploration (Alaska) Inc. July 2006 . . Table of Contents 1. Introduction...... ........................:...................................... .... ............,..................................2 2. Proposed Applications................................. ....................................................................... 2 3. System Design and Measurement Strategy........................................................................ 3 4. Accuracy and Measurement Methodology... ................................ ............. ......... ................ 6 5. Performance of the TopFlow Meter in Flow Loops.. ....................... .......... ...... .................. 6 6. Field Qualification Tests of Top Flow Meter...................................................................... 8 7. Gas Measurement Accuracy for EMS............. ...................................................................9 8. CDS Separator Performance............................................................................................ lO 9. EMS System Control.. .... ........... ......................... .......... .............. ......... ... .......................... 11 10. Factory Acceptance Tests (FAT) .................................................................................. 12 11. Field Maintenance and Periodic Calibration.................................................................. 13 12. List of Appendices........ .......... ........... ..... ....... .................... ............................................. 14 Appendix 1 - AOGCC REPORT REQUIREMENTS... ...... ................ .......................... ....... 14 Appendix 2- FIELDS, POOLS, AND WELLS. ..... .......... ................ ............... .......... ........... 14 Appendix 3 - TOPFLOW METER PRINCIPLE OF OPERATION ................................... 14 APPENDIX 4 - TOPFLOW FIELD QU ALIFICA TION ..................................................... 14 Appendix 5 - CALCULATION OF UNCERTAINTy....................................................... 14 Appendix 6 - CDS SEP ARA TOR........................................................................................ 14 Appendix 7 - EMS CONTROL SYSTEM ............ ..................................... ............. ............. 14 Appendix 8 - EMS P&ID ..................................................................................................... 14 Appendix 9 - FACTORY ACCEPTANCE TEST ...... ............ ........................ ..................... 14 Appendix 10 - PERIODIC CALIBRA TION ... ...... .................. ........ ............ ........................ 14 1 - 14 . . AOGCC ~~ Application Reporf~ for EMSl'M Multiphase Measurement System "9. intrroduction This document describes the design, performance and the anticipated applications of the FMC Technologies Enhanced IvIultiphase System™ (EMSTM) for well testing in BP Exploration (Alaska) Inc. ("BPX") operations. The EMSTM skid is manufactured by FMC Technologies under a contract to AES O&M (ASRC) to be incorporated into a trailer type mobile unit for well testing in BPX operations. The EMSTM is designed to remove high gas volumes from the inlet to the multiphase meters by employing a proven cyclonic separator developed by CDS Engineering of The Netherlands. CDS Engineering was acquired by FMC Technologies in June of 2003. This separator is known as a Gasunie and it is capable of high degree of separation efficiently as compared to conventional separation technology. With a high level of confidence in the removal of a minimum of 80% of the gas from the well stream, the FMC Technologies TopFlow multiphase meter is permitted to operate within the highest accuracy range for liquid, water cut and gas measurement. This report compiles the data and literature that was used to qualify the design and establish performance levels for the EMSTM skid. This document is to be submitted to Alaska Oil and Gas Conservation Commission (AOGCC) as an "Application Report" to obtain their approval for using this multi phase metering system as an alternative to conventional gravity based test separators for well testing. The "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued by AOGCC (included in Appendix 1), requires operators to submit this "Application Report" before new metering systems are used for production well testing and allocations. Section 3 of the AOGCC document outlines the type of information that the application has to provide. This BPX "Application Report" provides the information that is requested in the Section 3 of the AOGCC document. 2. Proposed Applications The proposed multiphase metering system is designed as a mobile unit and will be used for well test allocation in any North Slope field in which BPX is the operator. The metering system will be operated by AES O&M (ASRC), who has extensive experience in well testing and a track record with mobile test units in the BPX operations. ASRC has also taken a principal role in designing the unit and is intimately familiar with the operations of the metering system. Table 2A-I in Appendix 2 shows the fields, in which BPX is the operator or has a working interest that may use the proposed multiphase metering unit. This Table also shows the working interest owners. Pools that are commingled are shown in Table 2A-I. All parties with working interests, royalty ownership, as well as the Alaska Department of Revenue will be notified about the use of the metering system when the application of the metering system affects such interests. The proposed application will use the mobile multiphase metering system for production allocation. The allocation methodology currently practiced will continue and would not be affected by the multiphase metering system. 2 - 14 . . 3. System Design and Measurement Strategy During the summer of 2003, BPX - North Slope operations conducted an extensive field test of four multiphase metering systems at their V -Pad. These tests evaluated the performance of these systems in NS operating areas. The four meters used in these field tests use a wide range of measurement techniques and strategies, which increased the probability of finding meters that would qualify for measuring the production from various tìelds. The four meters tested included Agar's MPFM401, FMC's TopFlow, Roxar's 1900 VI and Schlumberger's Phase Watcher (Vx29). North Slope well testing provides numerous obstacles to the successful application of multiphase measurement techniques. These obstacles include varying crude quality from three different horizons, high gas-volume fractions (85%-99% OVF), and a wide range of water cuts (0-100% WC). Monitoring is further complicated by the fact that a high percentage of the wells are on artificial lift with either gas-lift or jet pumps powered by water. In either case artificial lift greatly increases the GVF or WC of the fluid stream measured at the surface. The results of the tests showed that all four metering systems qualified in specific or limited operating areas. In general, the higher GVF applications were much more problematic for the meters and resulted in a significantly higher measurement error. Wells with high gas lift rates, or in the Gravity Drainage (00) portion of the field, fall into this high GVF flow regime. Four applications for these meters were identified. They included individual well deployment (usually for new developments), supplementation of current well test separators; a mobile test unit; and replacement of existing test separators. This report deals with the application of multiphase metering in a mobile test unit. Based on the experience gained from the above mentioned field tests, BPX - working with AES O&M (ASRC) and FMC - has developed a metering system that is compact and portable but can also handle high GVF measurements. The unit incorporates the multiphase metering techniques, as well as a unique but tested separation technology to achieve measurement capabilities that are specifically suited for high gas fraction production streams encountered in NS. Figure 1 shows the schematic of the EMSTM with various elements of the EMS shown in blocks. Flow stream from the well is directed into a cyclonic gas liquid separator made by CDS- Gasunie that would convert the initial high GVF stream to liquid rich and gas rich streams. The system is designed so that the liquid rich leg will have a GVF of less than 80%. Parallel liquid measurement lines with 2" and 3" TopFlowTM (TF) multiphase meters manufactured by FMC-FlowSys will provide multiphase measurements in the range of270 - 11,800 BPO. 3 - 14 . . " ~",," .,,'=,"~_,_d ,.~~~~.._.=.'._._'_=_.._,__~.~,. ',.., I Gas leg - Type 1 Gas Meter i O ' ¡ ~-=:::~:.:,-_-:,:=::-,:-:-:::":=-~--~ ____~..__:= :~."3 '_ _," =-======"'::=~-_:" -=-_.. __ _ __.,,_ / ¡ j · ~ j I -' - t 1 I I CDS Gasunie™ I ,f · SeDarator ~ ~ I 'I ,I I ! ~ I i i i I Well Head I I I I Flow line I [ , I r . I I · I 1) I . I liquid Rich leg - 2" and 3" Topflow Multiphase Meters I 1 ! for liquid and we measurements I r i ¡ 1 , ¡ ¡ , I ! , ì ¡ i ~ 1 .=----'~,,.-="""~-=~'""'_"==''''..~.~..,,...,..:o_~'"',_..~=''''~.,'_-="_''.--_'_'""-_''="'_"''''=='~-'='==_='''''~-=''_""",.'''''-':::<==~'=''''=-='''''''=='- -...."~("..=.:"_~-===..,"'=c,,=,c.=,"'="',.-:"',.....-="''".~.,:,'''.-''''-..==.=,,j figure 1 - Block diagram of the high G'VF multiphase metering system For gas measurements, the metering capacity was designed on the basis of maximum gas flow rates of 40 MMSCF/D at 1200 psig, corresponding to the ANSI 600 rating of the equipment in the unit. The EMSTM is also designed to produce a low liquid content gas stream. Gas rates are measured by a Vortex type gas meter. Field experience with mobile units, gained by AES O&M (ASRC) in years of service on the North Slope, was used to make this unit portable, while meeting the well testing, HSE, and work requirements specified by BPX. Figure 2 shows the layout of the system within the mobile trailer. Table 1 describes the measurement performance ranges for the unit. Figure 3 shows the designed flow rate performance envelopes for the unit. Table 1 . SPECIFIED FLOW RATE PERFORlVIANCE RA1~GE FOR THE EMSTM Gas Volume Fraction = 0 - 100% Water Cut = 0-100% Liquid Flow Rates ==270-11,800 BBL /D Gas Flow Rates=500 to 12000 MSCFD@ 300 psig Gas Flow Rates= 10 to 40 MMSCFD @ l200psig 4 - 14 · . CDS Engineering Well stream Gasunie Cyclonic Separator - Inlet - Outlet 2" and 3" FMC TopFlow Multìphase Meters Figure 2 - This Drawing depicts the metering system layout within the ASRC trailer >5000 ~-- - I - : I i I I I i Î I I EMS Operational Liquid Range 20000 I I : i c i ~ 1 5000 .. :; <I:: 3: 52 ~ EMS Operêtional Gas Range :: 1 0000 -'..-'~'-.I--_. ,- ,5!' .,.".._.._- oJ . '1 .~._- ""." 5000 _.,::':::'11-" I -....-.; I .k....;.¡ I _ I II 00--' I o 100000 200000 300000 400000 500000 600000 700000 300000 Actual Gas Flow Rate (cfd) Figure 3 - Liquid and gas measurement envelopes fQr the metering system (The red and blue graphs denote the operational envelopes {Qj' '2'" <id« j" TopFlow meters respectively). The rectangular blocks correspond to ";~ jpœ-îñed liquid and gas flow rates shown in Table 1- 5 - 14 . . 4. Accuracy and Measurement Methodology The specified accuracy of the system for measuring liquid, gas and water cut is shown in Table 2. This accuracy level is applicable to the range of flow rates shown in Figure 3. Table 2 - EMSTM ACCURACY Item Accuracy ( Method) Liquid Flow Rates ± 6% ( Relative) Gas Flow Rates ( combined liquid rich and gas rich legs) ± 7 % ( Relative) Water Cut ± 3% ( Relative) To obtain these accuracy levels the metering system must perform the following major tasks: 1. The CDS separator must deliver liquid with GVFS 80% to the TF multiphase meters in the liquid leg. Data in support of this requirement is presented in section 8 of the report. 2. The TF meter should then deliver the ± 6% liquid rate and ± 3% water cut accuracy. Sections 5 and 6 of the report present data that would support this performance. 3. The CDS separator must also deliver Type 1 gas with low liquid content (Lockhart Martenilli Number S 0.03) to the gas rich leg. The combined gas measurement rate from the Vortex meter used in the gas rich leg and the TF meters in the liquid rich leg should provide ±6% to ±8% gas measurement accuracy as described in section 7 of the report. 4. The control system and control philosophy operating the separator must contend with slug flow conditions expected in well tests and sustain the GVF levels, described in items 1-3 above, in the liquid and gas legs. The control system philosophy and design are described in section 9. Further detailed discussion and information to support that the above requirements can be met are presented in the following sections. 5. Performance of the TopF/ow Meter in Flow Loops Appendix 3 contains literature describing the principle of operations of the TopFlow™ multiphase meters. The Flowsys TF meter has been tested in a number of flow loops. A summary of all the flow loop data - specifically for GVF<80%, is shown in Table 3. Table 3 also shows the statistical analysis of the data for liquid rate and WC accuracy (uncertainty) performance. The Daqing test loop data, most recent tests, was obtained with a partial separator device similar to the configuration proposed in the EMS. The fluids used in the loop more closely simulate fluids encountered in actual well testing. The Daqing data in Table 3 support the 3% water cut and 6 % liquid flow rate accuracy values in Table 2. Figures 4 and 5 show plots of the liquid flow rate and water cut accuracy as a function of GVF. The data in these figures were obtained with different size meters. The liquid flow rates are converted to velocity (dividing the flow rate by the meter throat area) to arrive at a parameter that is independent of the meter size. The data in Figures 4 and 5 shows that the TF meter is capable of delivering improved levels of accuracy in the liquid rate and water measurement as the GVF in the flow stream is reduced. 6 ~ 14 . . TabRe 3 - SUMMARY OJF "JFLOW LOOP~~ TESTS fOR TOPJFJLOW METER flow Loop and Flow Conditions Fluids used to I Number of data Liquid rate I we i Year the test Ranges of liquid simulate Points Accuracy@ I Accuracy was conducted and gas rates Oil = GVF<80% 90% @ 90% Range of we Water = confidence confidence I Gas = I level level Christian WC: 0-100% Diesel, \Xf ater 90 tests below 4% 2% ì Michelsen with NaCl and 80% GVF I I I ì Research - alL Norway - 2000 National WC: 0-100% Stabilized Crude 54 tests below 8% 3% Engineering Lab, Oil, Water with 80% GVF lIK - 2000 MgS04 and Nitrogen AGIP Trecate we: 40- 60% Crude Oil, 13 tests below 17% 6% Flow Loop, Italy Produced Water 80% GVF - 2001 and Natural Gas Daqing Test WC: 0-100% Crude Oil. 12 tests below 6% 3% Loop, Liquid: 121 mYd Produced Water 80%GVF +' 53 China - 2004 to 1190 m3/d and Natural Gas tests with partial Gas: 370am3/d to separator I 11021am3/d 20 u c x CD, 1& 15 - '! x x S10 - ~ ~ 11 - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~)K' - - - - - - - - - - - - -0 - - - -x- - - _.,- - - - - '- - - - - } -, _ 5 -x ¡x - X ID )§( X ' .' ... x x 0) ))!.~) 0 , ~ Xx x x X! ~) ,J, cr.:x ),. e... ,:) x" X,{;,-, i ~ .x/ ;~~'-- ... 0 X ) xc'" J~ j 0) ) .J ') , '.,) o ;¿, x,:>" ~J) 0)(") ) I: . ~ , ,j ") x 0 ).... CD_5- ' x 00° ~' - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - . - - - - - - - - - - - -F - - õ - - - - - - - - -x.x Õ - - ~ - 8 0 x 00 ã;-10 - 0 Flowsys, DOD, 2004 > ." ) FI owsys , CMR, 2000 0 0 '3.15 - x Flowsys, NEL, 2000 0 cr I o Flowsys, Trecate, 2001 :J I 0 -20 I I I I I I X I 10 20 30 40 50 60 70 80 Reference GVF (%) Figure 4 - Accuracy of Top Flow meter for liquid flow rates for GVF less than 80% 7 - 14 · . 20 (,) c ! 15- '! E 10- .g J! 5- ,,0, 0 °0 0 :; v x:- X . 0. - - - - - - - - - - - - - - - - x - - - - - - - - ; - - _A . - - . - - - - - - - - - - - - - - x;: ;. - " - - - . - ~- X - - -V - - o _~ - X .. . X") . ~x DO" II) X X· ~- . >0',)') X).. Û .,X -~_[jt~,;;;,", ~ 0 X '¡ ò--'-'-~_ __. ~'Â-''r-;CJ}( ,--L=i.])- >-'~" '~O- ~ X >f X X· ~ X' XX'X 0 if ~ - - - -- - - - - - -- - - - - - - - - - - - - x- - - . - . - - - - - . - - - - -- j - ~ - - -) - - -0,,- ";:" -5- ° X o 0 ¡ 0 Flowsys, 000,2004 ~ -10 -, Flowsys, CIVR. 2000 i -15 _ X Flowsys, NEL, 2000 3: ° Flowsys, Trecate, 2001 -20 i I I I : I 10 20 30 40 50 60 70 80 Reference GVF (0/0) Figure 5 - Accuracy of Top Flow meter for measuring water cut for GVF less than 80%. 6. Field Qualification Tests of TopFlow Meter In addition to the flow loop tests, Top Flow meter has been involved in 2 extensive field trial campaigns, conducted by BPX at GPB and Saudi Aramco at North Safaniyah offshore platform (see Appendix 4). The GPB field trial test results are consistent with the vendor specification shown in the table below. In particular the measurement uncertainty of liquid and gas flowrates and water cut was demonstrated to be improved by limiting the GVF range. However it should be noted that most of the GPB field test data was taken at very high GVF ( > 90%) and so it is not possible to create statistically meaningful statistics for the lower GVF points. For verification of the measurement uncertainty at lower GVF than observed in the field test it is necessary to rely on the test loop data discussed in section 5. Table 4 - FlowSys TopFlow vendor uncertainty specification GVF Gas flow rate Liquid flowrate Water cut uncertainty uncertainty uncertainty 0-25% NA 5 2 25-60% 10 5 2 60-70% 10 7 2 70-85% 10 7 3 85-92% 10 10 3 92-97% 10 15 j . 5 97-100 NA NA ~. __N_,t\~ -~_ g ~ 14- . . The Aramco field tests (see Appendix 4B) had a less stringent qualification criterion due to the lack of accuracy on the reference test separator and the manual periodic water cut measurement procedure used at the test site. fn these tests the TopFlow meter had to meet the following qualifications: () Liquid Flow Rate: 90% of tests within +/-10% (relative) compared to test separator liquid flow rate. (j Water Cut: 90% of tests within +qO% (absolute) compared to samples from liquid leg. () Gas Flow Rates: 90% of tests within ,/-15% (relative) compared to test separator gas flow rate. The test results are shown in the Figures 48.1 to 48.3, in Appendix 4.The tests were conducted at GVF levels of about 75%. The TopFlow meter performed well during the tests and was qualified for compliance with the performance criteria stated above. The performance of the TopFlow meter in various test loops and field trials are plotted in Figures 4A.l - 4A.3 in Appendix 4 with reference to the specifications claimed by the vendor (Table4). These performance plots support the levels of accuracy for liquid, gas and WC measurements shown in Table 1 for the TopFlow meter operating within the GVF conditions anticipated in the liquid rich loop of the EMS multiphase metering system. It should be noted that the TopFlow meter accuracy for liquid and WC determines the accuracy of liquid and WC measurements for the EMS multiphase metering system. The TopFlow accuracy for gas measurements is however a minor component of the accuracy for gas rate measured by the EMS multiphase metering system as discussed in section 7 of the report. The EMS multi phase metering system can achieve the ± 7% accuracy in gas rate measurements even if the accuracy for gas flow rate measurements by Top Flow meter would fall below ± 15% ( see Appendix 5). 7. Gas Measurement Accuracy for EMS As mentioned previously the gas rates are determined by a 4" Vortex meter. Fig. 6 shows the uncertainty as a function gas velocity and liquid loading for a vortex meter similar to the one to be used in the EMS. Forliquid content of less than 1.0%, expected in the gas rich leg of the CDS separator, the relative uncertainty is better than ±8% of the reading. This accuracy can be attained over a wide range gas velocity (gas flow rates) 9 - 14 . . 30 ~ Dry 25 - -4-- 0.005 0.10% /I'".. --2:- 0.012 0.25% ". ", --;+- 0.024 0.50% ./~--. "-. -2Q - -e- 0.047 1.00% ~ '-." / ~ ¡g ... i "'~ -~ 0,12 2.50% 0 1:15- -+-024 5.0% W \I / ~ ,/ .' .......G---_ t -------- ------.~~ ¡¡: 10 - _,. __~_/..-._...---" <0. ---------~f~ ~ ., " 5 - ---~--- -...:..,' ~ -~--~. X ,.,;:--.--. /.- ?" -¡;:. X-- , ,~ g ~ - ·~I -. ___~- ---- --==€:I 0 ~-- @ - --~--- - - _- I -5 0 5 10 15 20 25 30 35 Superficial Gas Velocity (mls) Figure 6- Vortex meter error as a function of gas velocity and liquid volume fraction at 450 psig (data from National Engineering Lab, UK, join industry project). The amount of liquid in gas varied from 0.1 % to 5% in these tests. The data for 0.5% to 1% liquid content was used to calculate the EMSTM uncertainty. The overall gas measurement accuracy in the EMS system is a combination of measurement accuracy in the gas rich leg (Vortex meter) and the gas accuracy from TF in the liquid rich leg. The procedure used to obtain the overall gas accuracy for the EMS system is described in Appendix 5. The gas rate measurement accuracy for the EMS is dominated by the accuracy measurement in the Vortex meter as most of the gas is diverted and measured in the gas rich leg. Assuming a diversion rate of 95% or higher (see Table 5), well within the capability of EMSTM as described in the next section, the overall accuracy for the gas is calculated (Appendix 5) to be about 6 to 3 ~/" The calculation of combine uncertainty is shown in Appendix 5. 8. CDS Separator Performance Appendix 6 provides literature describing the principle of operation and prior field applications of the CDS-Gasunie. The special configuration employed in design of the separator, described in Appendix 6, enables this device to achieve greater than 98% rate of gas removal. Data in support of this claim is presented in Table 5. The data shown in Table 5 was obtained by CDS Separation Technologies in their flow loop in Anthem, The Netherlands. 10 - 14 . . The measurements for liquid rates were made by liquid ultrasonic meters. The gas rates were measured with a Vortex meter. The mixed fluids were allowed to travel down 25 feet of flexible 4" hoses to allow the flow regime to develop. The water cut in the tlow stream ranged from 0 to 68%. The inlet stream with a GVF level of 99% was diverted to a liquid rich stream with a GVF ~ 36% at the TopFlow meter. At this level of gas volume fractions, the Top Flow meter should be able to deliver liquid rate and water cut accuracy as shown in Table 2. Table 5 - LIQUID REMOVAL EFFICIENCY OF THE CDS SEP ARA TOR Oil Flow Water Liquid Gas Gas Gas we Gas Rate Flow Flow flow fraction Fraction Removal Rate Rate Rate at at Efficiency Separator T opFlow Inlet BPD BPD BPD MSCFD GVF GVF 0/0 227 151 378 191 99% 12% 40,0 98.73% 151 227 378 191 99% 36% 60.0 98.40% 272 106 378 191 99% 19% 28.0 98.63% 151 302 453 170 99% 23% 66,7 98,63% 302 151 453 170 99% 23% 33.3 98.07% 453 0 453 170 99% 32% 0,0 98.09% 9. EMS System Control The control philosophy used in the system is described in Appendix 7. The P&ID diagram for the ASRC Multiphase Metering Unit in Appendix 8 shows details of the control devices. Due to the large variations in gas and liquid tlow rates, separate control valves have been placed in the gas and the liquid lines. The function of these valves is to regulate the pressure balance ewer the Gasunie cyclone separator so that dry gas enters the vortex meter in the gas- rich line of the vessel and that :;Lifiì~ientiy J¿6Qssed liquid enters the multiphase meters in the liquid leg over the complete operating envelope of tnt; ~~it. The benefit of degassing the liquids as much as possible is that the liquid measurement accuracy of the Topflow meter improves with reduction in GVF. The intent is to regulate these valves by using the guided wave radar transmitter located on the top of the cyclone separator in the following methodology. 1. At start up - The gas valve opening will be 0% and the liquid valve opening 100%. In all scenarios the liquid control will be the source of primary control. The reason for this is to minimize the total pressure drop over the skid. 2. High Liquid / Low Gas regime - The system will then try to regulate a liquid level at a 25% set point by closing the liquid control valve. If the liquid valve is more than 70% open then the gas valve will start to close until the liquid valve opening reduces below the 70% threshold. The reason for applying a 70% opening maximum is that if a liquid surge enters the vessel there is valve capacity left to help in the disposal of this liquid. Otherwise the cyclone separator would soon fill with liquid and the liquid is carried over to the gas leg, thus affecting the accuracy of the gas measurement. 11-14 . . Table 6 - Guideline for Expected Factory Acceptance Test Matrix Water Liquid Gas Volume Fraction (%) Cut (bbJ/d) % 80 85 90 93 97 0 270 x X x 10 2600 x x X x 20 5000 x x X 40 7040 x x x 60 9400 x x x 80 12000 x x 11. Field Maintenance and Periodic Calibration P~MC'~i,: m;:¡intenance of the EMS is required. These items are identified by CDS/FMC Report dnd are listed in Appenùi;:: 10. Periodic calibration of the Top Flow systems will be required when fluid properties - i.e. oil gravity or composition and produced water salinity changes. These calibrations will follow the ~r~'2edures also described in Appendix lO as a guide. 13-14 . . 12. List of Appendices AppendiìC 1 - AOGCC REPORT RÐf)UIRElì¡IENTS Appendix 2- FIELDS. POOLS, AND WELLS Appendix 3 - TOPFLOW ¡'I¡IETER PRINCIPLE OF OPERA TION APPENDIX 4 - TOPFLOW FIELD QUALIFICA TION Appendix 5 - CALCULATION OF UNCERTAINTY Appendix 6 - CDS SEPARATOR AppendiìC 7 - ENIS CONTROL SYSTENl Appendix 8 - ELMS /f"~:!) Appendix 9 - FACTORY ACCEPTANCE TEST Appendix 1 () - PERIODIC CALIBRA TION 14-14- . . GUIDELINES For QUALIFICATION OF MULTIPHASE METERING SYSTEMS FOR WELL TESTING November 30,2004 Alaska Oil & Gas Conservation Commission www.aogcc.alaska.gov Prepared by: Parviz Mehdizadeh, Ph.D. Production Technology Inc. Jane Williamson, P.E. Alaska Oil and Gas Conservation Commission :i._()CJC· C GUicl..:-) ii!::_> . ' . . i <itH, I ~'l(i' 7" ,"'~,'H' ',: 'I' '~', ,,'" o _, .0:'-' _ I OJ _1 L~,-, l. ° __0_ l., \... tlc3.flcn of rvl!_tltìpha-:~è \i;~f:riI1~ Syscen1';:; J,:::.ni: \\"¡jIL2l1i1S·)]!._ _~\CjC;CC i 1-3()-i}+ Guidelines for Qualification of Multiphase Metering Systems for Well Testing T able of Contents 1.0 Purpose lIaG Q(I GlalllJllIlIlIlIlI..a.aClla (1111111"1111111111<1111(1 1111111111101.11 """""110. 1111111111111 rJlI (I 1l1I1I."CI 11111 II CIa a II II iii II II 111111 IIQIIII !III 3 1.1 Organization of the AOGCC Guidelines........................... 4 1.2 "Principles of Multiphase Measurements" ........................ 4 2.0 AOGCC Administrative Process ............................................ 5 2.1 Application Contents-General.......................................... 5 2.2 Review Proces~ .... ..................................................,....... 5 2.3 AOGCC Decision............................................................. 6 3.0 Qualifying Multiphase Metering Systems for Well Testing. 6 3.1 Application Contents ....,......................,............................ 6 3.2 Accuracy Expectations,.. ....,.. ...,....... ..............,...... ........... 8 4.0 Validation of Meter Performance in Field.............,.............. 10 4.1 Field Verification ............................................................ 1 0 4.2 Field Test Plan ............................................................... 11 4.3 Reporting the Field Results............................................ 13 -\C)C:'CC GUidehl1èS j::,;r . . ,,'.. 1,n12 )'-1" -.' \ I ":';--"'Q1 7', '--'1"- 1 --:C ; .~. I .:_ ~" L _~. ¡ /_C-,' t " ()UJ!1fic2.tlon :)f f\i!u¡tipha~,-: !\l'~1.C'ring S~\ ~r~nl.~ fJïh: \\!lìL~J13(}lL ,-\'OGC'C i ·]0-0-+ Guidelines for Qualification of Multiphase Metering Systems for Well Testing 1,0 Purpose 1.0.1 The use of multiphase meters for well testing is gaining increased support within petroleum production operations. It is anticipated that Alaskan operators will be pursuing their use in well testing and field production allocation. 1.0.2 Multiphase meters are devices that measure oil, gas, and water flow rates of a well stream with or without partial separation of lil~6ö cC~~('I1t=!nts into individual phases. Multiphase metering techniques were o€'leloped as an alternative to measurement methods using two and three ¡.Jhase gravity based test separators. 1.0.3 The Alaska Oil and Gas Conservation Commission (AOGCC) is authorized to evaluate and approve methodology and equipment utilized for well testing and allocation of production in Alaska per regulation (20 MC 25.230) and Alaska Statute (Sec 31.05.030(d)(6)). 1 .0.4 Industry standards and recommended practices are in place for test separator based single-phase gas or liquid metering. However, there are no standards and few guidelines available for multiphase meters. 1.0.5 Considering that the multiphase metering technology is r91atively new and that accurate well test metering has both financial and reservoir management importance, the AOGCC will require approval prior to use of mutiphase meters to satisfy requirements of 20 AAC 25.230. These guidelines are provided to train and direct the operator and AOGCC on how to qualify these new measurement techniques. 1.0.6 These guidelines address both wet gas and multiphase metering systems for use in well testing. Custody transfer applications are regulated under 20 AAC 25.228 and are outside the scope of these guidelines. 1.0.7 The materials described in the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" were developed to serve the following objectives: ~ ,") r' ~ S \!j',~:C C (JlLJ(è~lne'.~, ~·;~'r . j7 o¡~,ì, '''.'r''''l "'\I' r~'i\'1 'í,]" ~ _ : ,~, j ;;..::: . \..''''':' ~ L.... '. "',_, _l ,~'...... J. '_' -= '; '. t '-' )]ll':sri0r1 of ~iru¡tipha:)è \1 <";'~è!n'-; fdr'_\:- \\/. ¡ lian1S;)lì_j·~()G(_- ] - .~:)-o~ 1.0.7.1 As a guide for the operator in submitting a request to apply new multiphase metering techniques for well testing and allocation of production, 1,07,2 As a guide and process tool for reviewing operators' requests for qualifying a multiphase metering system for well testing, and 1.0.7.3 As a training tool for AOGCC personnel who will be involved in the assessment of the multi phase technology for well testing. 1.1 Orqanization of the AOGCC Guidelines The remaining sections of this document are organized as follows: Section 2 AOGCC Administrative Process: This section outlines the overall administrative process that will be followed for certification of a multiphase metering system. Section 3 Qualifvinq Multiphase MeterinQ Systems for Well TestinQ: AOGCC expectations of documentation to accompany the application for pre-certification or certification of the proposed multiphase metering system are described. Section 4 Validation of Meter Performance in Field: In some instances, the AOGCC may require field verification of meter performance prior to approving use. This section provides recommendations and requirements for conducting these field tests to gather information required by the AOGCC for qual1iil.atiùi1 ~f the multiphase metering systems and outlines requirements for documentation of the field test results. 1.2 IIPrinciø/es of Multiøhase Measurements" A separate document, "Principles of Multiphase Measurements" , is concurrently issued with these guidelines. This document provides basic information on multiphase meters, a list of references for furthor edücation on multi phase meters, a list of terms and definitions, and installation suggestions for multiphase meters. It is recommended that the novice review the "Principles of Multiphase Measurements" document in conjunction with these guidelines. \{)(rC~C Gu¡d<~hll:~:- (_'r . : ¡lei 1 za '-.¡1~,:~l:~~.lI']1a:l;:C!; .~,~5iS:~·~ Jtl'.::atlOn ~~¡f \lu][~Dh(¡~e y ~::;-:nì~ 11-30-!)4 2.0 AOGCC Administrative Process 2.0.1 This section describes the AOGCC review and decision process that will be used in processing requests and summarizes required application contents. Section 3 provides further detail on required application content. 2.0.2 AOGCC approval will be required prior to use of multiphase meters in well rate determination to satisfy requirements of 20 AAC 25.230. 2.0.3 AOGCC approval will not be required for minor changes (such as meter size or minor technical upgrades that will not deteriorate performance) of previously approved meter systems. However, if production characteristics change significantly (such as large changes in GVF and water cut) from the initial approved application, a new application must be submitted. Approval will not be required for use of multiphase meters if the well test results are not used to satisfy monthly production reporting and well test allocation requirements of 20 AAC 25.230. 2.0.4 The AOGCC will only approve use of a multi phase meter system by Commission order adopting or amending pool rules under 20 AAC 25.520 or, in the Commission's discretion, by administrative approval where provided under an existing order. However, in the case of a pool for which pool rules have not been adopted and for which the applicant demonstrates that pool rules are not yet needed, the Commission will consider an ad hoc application for an order under 20 AAC 25.540 approving use of a multiphase meter system. 2.1 A.;;;;!:~atk;:: C~:;t~íì:s-ûeneral The application must include a cover-letter request with a summary description of the proposed meter system, discussion of how the proposed meter will be used for the determination of well production within the allocation system, reference to the conservation orders which prescribe the rules for development and operation of the pool, requested changes to the conservation order, and other documentation described in Section 3. 2.2 Review Process 2.2.1 It is recommended that the applicant contact the AOGCC early in the evaluation process to decrease the ultimate time to process applications and to reduce the risk of later costly revisions to plans. \C)CCC C;Ullle'm·::" , . '7 \¡~ ';,7,.:',"1' i,,' ',,;,' r l' ¡.~ . , ..', . ~ .¡.." \, - " ~ r. " - . '"" ,_._ _ ,"-. _ _ ~ .- . ,~ ,'_.',' i" i , U ,d, ll~ I ,,_ i " ,¡ '- Íl.!'..-3l1.JJ1_\ ¡ ~\ltlJ.ltl p!!(~,~.e ,. è'LCl111::; ~;' :--tè!1l~ I.::lìè ;lJidnl~',-::il_ .-Ä.C)(;C C ¡ - 3 ü-(J-+ 2.2.2 If the application is deemed complete, AOGCC will notice the application for public comment and potential hearing, unless handled by administrative approval. By regulation, a minimum of 30 days is required for public comment from the date notice is issued. In some cases an oral hearing may also be held. Applicants should expect the full approval process, from submittal of a complete application to AOGCC decision, to take 30 to 60 days. 2.3 AOGCC Decision 2.3.1 If sufficient information is provided, the AOGCC may approve the system either unconditionally, or conditionally upon field testing and subsequent reporting of meter performance. Any approval is conditioned upon maintenance of the multi phase meter to provide accurate and reliable measurement, and will require periodic calibration of the multi phase meter and records to be kept to verify the calibration of the meter. 2.3.2 An applicant that is dissatisfied with the AOGCC's decision has the option to request reconsideration ("rehearing"). 3.0 Qualifyina Multiphase Meterina Systems for Well Testina The operator shall submit a proposal to the AOGCC for deploying the multi phase meter or meters in a designated application as a well testing system. 3.1 Application Contents A complete application must address the following: 3.1.1 Discuss the intended appllcé:ll¡0~, p~opùsed location and projected timing of installation of the meter. 3.1.2 List fields, pools, and wells affected by the proposal. Are multiple pools commingled? If so, provide details. 3.1.3 Outline any differences in working interest, royalty interest, and tax treatment for leases or for commingled pools. 3.1.4 Ensure that all working interest owners, royalty owners (e.g. Alaska Department of Natural Resources), and state revenue department (Alaska Department of Revenue) are notified. 3.1.5 Describe the meter make, model, type and measurement , , ',Ci(iC (JU¡j¡=llì1è.:; ¡·~Ji- . ¡>1! 'IZ·,~è;hCl¡Z'.~l~:~:C~ll~¡I]'i¡il:a,~':¡hl1~~b~!~ j"ÍCâC;C¡!1 of j\'íul:;lJh::;:;":3 \f,::'terlllg "lèlì1::- i ! -]iJ-O-l methodology for the intended applications. 3.1.6 Describe plans for field-testing the meter (see Section 4). If no field-testing is planned, provide justification. 3.1.7 Provide data on the performance of metering systems obtained from laboratory or field tests. Discuss the expected effect of the proposed meter system upon the quality of the well test data measurement accuracy and overall production allocation in the planned application. 3.1.8 Provide information on expected precision, repeatability, and bias over the range of conditions for which the meter is planned for use. Accuracy must be evaluated ~r.ross tr.~ full range of expected Droa! ·~tion flow rates, water cut (WC), gas volume fraction (GVF) and process c~r)ditions for which the system will be used (see also Section 4.3). 3.1.8.1 Review accuracy for each phase. 3.1.8.2 The method of accuracy description must be clearly defined. It is preferred that the accuracy be expressed as the percentage (+/.) uncertainty in the flow rates for each phase - i.e. oil, water, and gas flow rates. Other methods may be accepted by the AOGCC on a case-by<~~se basis if sufficient justification is provided. 3.1.ô.3 1\ :"":u~~:'"ica: :::ðgree of confidenCC in the accuracy /"'\ estimate must be provided and method of dete. ;;"lining the confidence level must be discussed. In general, acc\À;'"3cy must be evaluated at a 90% or higher level of confidence. Other confidence levels or statistical analysis of confidence may be accepted by the AOGCC on a case- by-case. basis if the methodology for determining confidence level is explained and sufficient justification is provided. 3.1.9 Summarize the production allocation methodology currently being used and explain how the meter will be incorporated into the existing methods of well production allocation. 3.1.10 Describe the contingency plan in the event the meter system does not meet the expected performance. Can the meter be changed out if the system does not meet expected performance, or if the well conditions change such that the production is outside the ~'U2 j¡I~(a:\~lndeil:':L~I;~;;lae.21: n '!, S, ~l2nb PH\ 'Z \!dÒLd(.;~1~'-~\\:i'l~a~1Sc>n;()(!~!~~ ] - .~,¡.ì-(}c+ original designed operating envelope of the meter system? How will this be accomplished? 3.1.11 Submit plans for quality assurance of long-term accuracy. 3.1.12 Describe the proposed systematic maintenance of the measurement system, including methods and frequency of periodic calibration. Describe the proposed record keeping and reporting format. 3.2 Accuracv Expectations 3.2.1 Generally, the AOGCC will expect accuracy for the pay fluid (oil or gas) from the multiphase meter to be within ± 5% over the full range of rates, GVF and we that the meter will measure when in service. It should be noted that this 5% is relative to the reference equipment. 3.2.2 When a multi phase meter is tested against a reference test separator in the field, the accuracy of fluid measurement by both the test separator and multi phase meter will affect the accuracy of the data obtained by the process. Using a root mean square (RMS) approach, the total probable error (accuracy) of the process is determined by: TPE = (ETfS + E2MP) ~ Where: TP!:: = to.ta! probable error in the measurement ETS = error due to the Test Separator measurement E MP = error due to the Mi.iltiphase Meter measurements As an example, if the test separator accuracy is 5% and the multi phase meter accuracy is 5%, the total probable error will be 7%. To obtain a meaningful multi phase meter accuracy, it is critical that the error of the reference equipment be less than 5%. (See also 4.2.2) 3.2.3 Some circumstances may warrant the use of multiphase metering for production allocation even if the meter accuracy is outside the ranges noted above. The AOGCe will consider applications on a case-by-case basis if thorough justification is provided with the application to the AOGee. uc"--\~ '_;u:d~¡]n=o . )Jr" z ':\]73C~.:~<:U' Il::'!U'. UL I , .- C-'...,· , " 1 -... ¡: ~\ ,11 I ; ,-. '\,~ '~~, .-...,.,., ,- . . srC:'~'¡'L-' 1:111(.= +d11311L-,-=·n. \CJGC'C l.,cJ!ldCJtJ',.,.1 ,-'. _\¡L\.Lrl.:c)Il<:..>~...,-.:... . '_~~¡ :Jl::;' ·3C·UC+ 3.2.4 The applicant shall provide justification for use of a meter system that will operate outside the above stated accuracy criteria. The following are examples where the AOGCC may determine it to be appropriate to relax these criteria. 3.2.4.1 If the meter is used solely for reservoir management and there are no significant financial impacts resulting from well test allocation with multi phase meter systems, less accuracy may be acceptable. 3.2.4.2 Relaxation of accuracy criteria may be appropriate if agreed to by all parties that are financially impacted by inaccuracies of the meter system. 3.2.4.3 It may be very difficult to obtain valid, accurate well tests with conventional separator based systems. As an example, some produced fluids may be extremely difficult to separate and lack of adequate separation will cause large errors in readings. In such instances, use of multi phase m~tp.r~ operating outside of the stated accuracy targets may prov:de better accuracy and may l;~ ::,ref~r::lble to use of separator based systems. 3.2.4.4 Multiphase meters often red uce the measurement system footprint and visits by on-site personnel compared to gravity based separation systems. Multiphase meters may therefore provide an environmental advantage in new, remote drillsite developments and may improve chances of development approval from other regulatory agencies with authority over land use and environmental conservation. 3.2.4.5 Multiphase meter systems may facilitate more frequent well tests as compared to a gravity separator based system. The stability of production during the non-test times will greatly affect the overall allocation accuracy. With more frequent testing and the resulting greater certainty in well test production, overall production allocation may be improved even if the absolute accuracy of the multiphase meter is less than that of the gravity based test separator. ¡-:: -\00C",- GU¡(k:!i1~' i',)" . J., ," \ -:hJ¡ ¿a·e) ,~dli' - ';~ ;. .~! iL-jcar¡::,n c\t'\full1Dh3.:St: \.::(>'=:1'111'1 . T,;;)!~,:.:c \v¡¡¡~ '¡;'-'ì"':,'¡1 .} ("G;~-'(' , - ' _,.1 _ V. , 1 i.... , ',''-",C. .. J '-~ "--- ¡ -~i;-U-+ 4.0 Validation of Meter Performance in Field 4.0.1 The AOGCC will generally require field validation of meter performance prior to final approval. This section provides a guide to the operator in planning a field test to verify the performance of the measurement system and required documentation of these tests. It is strongly encouraged that the field test plan be reviewed with the AOGCC prior to actual field-testing to ensure required data is obtained and to help speed the approval process. 4.0.2 In determining whether to waive the requirement of field testing in a particular situation, the AOGCC will consider such factors as other performance validation options, including prior successful field tests for similar types of fluids and flow conditions, the purpose to which the multiphase metering system will be put, and the practicability of field testing. 4.0.3 Situations where the AOGCC may choose to waive requirements of a field test include but are not limited to the following. 4.0.3.1 Field validation may be unnecessary if the meter system has been successfully tested in a field with similar fluids, flow regimes, operating conditions, rates, GVF and we. Results of the prior testing must be provided. 4.0.3.2 If the meter is used solely for reservoir management purposes and other lab or field tests are available at si~:!3r conditions, a field test may be unnecessary. 4.0.3.3 Field validation oí :;:~Itirhase meters may be difficult, logistically impossible or highly impractical in some .. instances, particularly for new, remote drill sites. In lieu of a field test, the AOGCC may accept other lab or field tests conducted at similar operating conditions 4.0.4 If the AOGCC determines that a field verification of the proposed multiphase metering system is required, the processes described in the remainder of this section must be followed. 4.1 Field Verification 4.1.1 The field tests must be conducted under normal field operating conditions. 4.1.2 Field tests require comparison to reference field measurements. Options used to determine the reference flow are: , c~'-~:ì~~;a~~:~~:ei i~¡~;1 !'l~ha'.ki;ng ·~...S[em" ' \. ....·1 r' .., - - 'r-.' ,': , 7 C,; - ;', '-lll" -'.I~ ',,_. '_' t ~. ";....Lj ,_,,~ "__,'\.... .0 l ,'_ ,! J&ne \V 11 [¡.3.nl~\"ll. I i - ~ ,J-!)-4. 4.1.2.1 Capturing fluids that flow through the system during the test and measuring them with secondary equipment. This option requires extra equipment that must be calibrated per appropriate standards. 4.1.2.2 Indexing the performance of the new system against an established well test measurement system such as a conventional gravity based test separator. 4.1.2.3 A combination of the above. 4.1.3 There may be a large uncertainty in the reference measurements. Pre-calibration and maintenance of the reference measurement system must be performed prior to conducting the field trial. 4.2 Field Test Plan The following is a guide for planning of field tests and may be revised to suit specific conditions. 4.2.1 Establish performance expectations that are within the design and tested constraints of the system. 4.2.1.1 Multiphase metering accuracy degradation typically occurs for wells that have operating liquid rates, gas rates, water cut, or gas volume fractions outside the system's designed accuracy range. 4.2.1.2 The multi phase metering system must be sized and designed to handle the flow range, pressure, and temperature (ambient and production) conditions existing in the field. 4.2.1.3 Multiphase meter performance ì:; also related to the fluid composition such as salt content of the liquids, impurities in the gases etc, which can change over the field life. 4.2.2 In a majority of qualification tests, 2-phase or 3-phase gravity based test separators are used to verify the performance of other multi phase measurement systems. Since these systems are used as the reference, the test plan must document the procedures used to calibrate and establish the accuracy of the liquid and gas measurement devices, the water cut analysis and monitoring, and the data acquisition and recording. 4.2.3 Full separation is rarely achieved and the procedures must make 1 ~ i ,1 ¡" ¡ "'. C(iC i~ CU!c!c'!'!L" ¡,Jr . i\(C:)',diL:'_.l'C<ClUC¡,,;'n ¡ 'c CllC ~larl 1';::HtC'n ,~1f' :Y¡u¡li:JhJ~.=. -.~c~nl1~ ::.)~. ~Lènl:, . -" . ',¿-- -. ~ L3::ê !1l1?111SCilL ,'~\~j\.lC L - 2 ,_::-1 an allowance for reduced instrumentation accuracy of the reference under field conditions. 4.2.4 Multiphase meters must be calibrated initially to accommodate the properties of the field fluids. The calibration procedures to be used prior to the field tests must be described. The calibration procedures must cover both the multiphase metering system as well as the reference systems. 4.2.5 Quite often the multiphase meter, the reference test separator, and the tanks used for fluid measurements are operating at different pressures and temperatures. Measurements made by these systems must be converted to rates at standard conditions (14.65 psi a and 60 OF). Actual test measurements, prior to conversion to standard conditions, must be retained. Procedures used to determine shrinkage and conversion of volumes to standard conditions must be addressed. 4.2.6 Once the initial calibration is done, the field test results must be obtained without further intervention in the settings of the multiphase meter. If repair, resetting, or recalibration is required during the field tests, the nature and frequency of these ¡1'1tc:rvelltlOnS ~:.:~t be recorded and reported. 4.2.7 One of the major objectives of the fia!d test is to evaluate the performance of the multi phase metering system over the full range of gas volume fraction and water cut since these are the two principal factors in determining the accuracy of the multiphase metering systems. To accomplish this, an outline of the test matrix to be used in the field tests is needed, noting the range of flow rates, GVF, and we to be covered in the field tests. It is recognized that this matrix may be limited by the flow rates of the wells available, however the test matrix must cover a wide enough range to allow for practical evaluation of the performance. 4.2.8 The testing program must cover enough data points to allow a statistical evaluation of the accuracy performance such as the number of points in the tests that can meet the acceptance criteria of Section 3.2. 4.2.9 The proposed method for reporting the field test results must be described (see Section 4.3). \'«:c ,JUtl:çill1"~ . \Z ""'l."\""" cv,hnìlr'J [tV' ~....\.. . . ,~....< - ! - - ,-" ,...." j '-' .::::>..' -'- ()Uzl!JtiC.:lElDn \,'IIJ¡Clph2,~e _'. ,_t.:-nng 3YS[e;1L~ d:lè V·; 1!ll3n1~cìn. ~C.<~1CC· i - _~ ·:.'-'-0-+ 403 Reøortinø the Field Results 4.3.1 Thorough documentation will be required if field verification is required by the AOGCC prior to final approval of the multi-phase meter system. A report must be submitted to the AOGCC describing the results of such field trials, including accuracy results. The guidelines described in this section are recommended for formatting the report of the field test results. Alternate formats may be used. Regardless, it is required that evaluation of performance be provided as a function of factors (rates, fluid properties, operating conditions, GVF, WC, etc.) found to significantly affect accuracy. 4.3.2 All flow performance data for the metering system must be described in conventional oilfield units at standard conditions. 4.3.3 Individual well test results as measured by the multiphase meter and the reference measurement system must be provided and ;;-:~:ûda ~!;8 fcHnwing: 4.3.3.1 Flowing press'-Ì;"~ - measured at the meter in pounds per square inch absolute (p~;2\ 4.3.3.2 Flowing temperature - mti2c;ured at the meter In degrees Fahrenheit (OF) 4.3.3.3 Oil rate - Stock Tank Barrels of Oil pei Day (STBD) corrected to standard conditions, at 14.65 psia and 60°F. 4.3.3.4 Water rate - barrel per day (BPD). 4.3.3.5 Gas rate - thousand standard cubic feet per day (MSCFD), at 14.65 psi a and 60°F. 4.3.3.6 Gas-oil-ratio (GOR) - (SCF/STB) the gas volume flow rate, relative to the oil volume flow rate, both Co~\!-=rted to volumes at standard pressure and temperature. 4.3.3.7 Gas Volume Factor (GVF) - gas volume flow rate, relative to the multiphase volume flow rate (oil, gas, water), at the pressure and temperature prevailing at the meter. The GVF is normally expressed as a percentage 4.3.3.8 Water cut (WC) - the water volume flow rate, relative to the total liquid volume flow rate (oil and water), both converted to volumes at standard pressure and temperature. The WC is normally expressed as a percentage. !GC'C ,-ìllilkll!1~; for . '·w, '\¡_"'(dZj.~ll;'C' [¡y - -. .' ,r . . " ' ,,' --, -_ . '". 1:. _, _ ' ,r\~í'o~ .i3JI1¡C3n'Jll or ;"'·/:UltIpha:---_: _ '~c,:nn6 '::,.\ .::t'~n~3 J~n,:: ',,\, I llcìì1ì~Un,-\,-_)lJ'"",,~ -3()-O4 4.3.3.9 Water~in~liquid ratio (WlR) (optional) - the water volume flow rate, relative to the total liquid volume flow rate (oil and water) at the pressure and temperature prevailing at the meter. The WLR is normally expressed as a percentage. 4.3.3.10 Fluid properties including: · Oil volume factor (Barrels at meter conditions/STB) · Gas volume factor ( Cubic feet at meter conditions/SCF) · Water salinity · Oil gravity (0 API) · Gas specific gravity 4.3.4 Figure 1 shows an illustrative graphical method that may be used to display accuracy results as a function of oil, water, and gas flow rates, WC, GVF or other important factors. In this figure the y coordinate represents flow rate error relative to the reference measurements. 4.3.5 Repeatability of the measured data and confidence level (see 3.1. 8.3) must be stated. The repeatability is expressed by the following relationship: repeatability = (max error)- (min error) ~ number of tests .. .- !Fig. X - An illustrative graphical method of reporting the accuracy performance of multiphase metering systems. These plots should be provided for each phase compared to GVF, water cut, and other important parameters. liquid F~owrate Error vs, GVF 50 I ' Test Data. :::, Oil.. 40 i f-----¡---l- - I 1.. ;::, ~ ~ 30 I :- ~~20 I ~ i .l~ .... 0) 10 . " Ij ':J '.:>1 ~ - I -' ~ . ... ", ---' ,. ,,, ,..,. ."_' ~.J---\ _.. ,.1= .J. I.L.. I \ ..) 'I ~' -_} t, , '- 0 ¡ I ~ I J. ,\---.,---,':> \ 1·>,-, :> 0 L J I... -' 'f \ j ~ '.>1 ' .. ;JIll ~. n.-_ - r-ro ' b..'I.",...",..--~ _ - ~-~ O 0)-10 1\ -' -' r-'~~ I - > I. .\ T> !L-àL~' '. " LL .- I I\.-...:¡" -æ .20 I ,\-'1,-- "'CO) I I !~ ':¡ 0;; ·30 . Blue Lines, Range of relative flow rate error i ¡-s- cr ~.40 I ! l-, ,- I I ( 1\-1! -I -50., .=k;\ 20 30 40 50 60 70 80 90 100 Reference GVF (%) ________________________n_m_____n___ ___ _______________________n____ - ---- - ---- ---- -- - - -- - --- - - ----------- _______n____n______________ _______________n______n_________________ ___ ___________________n___________ _ __________n__m_______ --~~~-~-~- _n_'_ '''' _",__ nn_ . . . . -~-=~"'-="_...,-------- ¡: ~ 'i' ßPXA PRUDHOE All OIL 36,395491 % 36.¡¡69365% i3P e"pi"ra¡;on 26.355356% '~hevf'onTexaúo U50¡¡O¡¡% t-orest em ¡¡,O197158% ¡,¡,t . RIVER UNIT 10 Mile$ We,,! CPAi 4niiidarim 22.011'1. . ., --" '11\11, "~~,~.._-~--~~"~-'~,--~~,~_.- . . . . -- ~--~^-~,--- are from Survey Access Roads 1 :63360 Quadrangles. BPXA i\Aar¡ Untt Operator based on 1973 aerial periodic updates ì Unit boundaries shown effec!ive Aprii 4 6 KJlometers not warrant that the data is use. ----< am:i 2 4 Miles for any claims from users use of this UTM6INAD27 e . BUlL.EN . . 1í ,H Technology Principle of Operation FlowSys TopFlow Multiphase Flow Meter May, 2005 . . ~NDEX t GlEN IE RA L... "" ................................................... ..................................... ....................... ...... ...... ............................... 3 2. PRINCIPLIE OF OPIERA nON AND fUNC1l0NAL DIE SCRiPTION ............................................................ 3 2,\ PRINCIPLE OF OPERATION '''0 "'''0,,,,,, ,,,,,,,,""'''0'',,,,, ~ ..... ."......................... ......... "'''''0'''' "'oo"',,,,'o.J 2,2, fi.JNCT!ONAoL DESCR!PTfON 5 22/ Capacitance sensor"" ..... . ...... ".5 2.2J Conductance sensor '" ............. ,,, 5 2J3. Venturi meter,,,,,,,,, """'" ............ .6 2-2,40 Cross-correLation, " .... " .... ,... . . . .. . . .. . ........ . .......... ..... ,. ....... ",,,0' "..6 '0/ . . FlowSys Top Flow ffiJ Multiphase Meter cTiea::hfJ1}cO(\j)~lr 1 0 General This leaflet contains the principle of operation of the TopFlow multiphase flow meteL 20 Principle of Operation and Functional Description 2.1. Principle of Operation The major parts of the FlowSys TopFlow meter are the Venturi and the electrodes incorporated with the extended throat of the Venturi insert. The flow rates of oil, water and gas are calculated based on the measurements obtained by the capacitance or conductance sensors and the measurement of the differential pressure across the Venturi inlet. No separation devices or other flow conditioners, e.g. mix6:ïS or by-pass lines are required wit¡,in the operating envelope of the TopFlow meteL However, the biggest advantage is the fact that the FlowSys concept does not make use of a radioactive source. Temperature PrC!:ssure I I Capacitance / ... ... Conductance ·1 ?4rm./ r Watercut Condo ~ FraCtÎ()1'f . Oil Flow Rate AA~I~" FloW~e ... þ Venturi (DP) ~t:>en~itY+- Gas Fraction lu\~I! WatC!:r Flo,", Ra.t~ ""'IC: ~,.. ... 60s Flow Rate ... . ., X -correlation (Velocity) Schematic block diagram of the FlowSys Multi-Phase Flow Meter The principle of operation can be summarized in the block diagram above. The differential pressure (DP) is measured across the inlet and throat of the Venturi insert. The electrodes connected to the Venturi throat measure the capacitance or conductance of the mixture. The velocity is found from cross-correlating the high-resolution time signals from pairs of capacitance and conductance electrodes, respectively. As there is no gamma densitometer, the FlowSys meter does not measure the fluid mixture density directly. However, the mixture density is determined indirectly, through the momentum equation of the Venturi. The DP and the flow velocity is used as inputs to this calculation. Page 3 of 6 -'IV;> . . FlowSys I apr-Iow il [j'\E!~ihtlJ1J(¡!)ij@!!J~ Multiphase Meter The set of equations utifized in the calculations of the fractions are listed below: 1. !PIelì"M = J{ ':i2's-:/c;, ,'::!'ÕJtas·Q/]) I COrnld = J( '3;;$:;1'1, }Y'Ð't-=c,è;I,:;, Saiinitv :» 2. Density = f(DP, vel) =223:);/1 ~ DensGas + Q)åJD/1 CJ if)ensOii + ~,:!:ö}i~-=JG!~ ~ DerasWaiter 3. Ga$~f,,: + Cm~h + -'X,,;rtaj";¡'; = 1000io The fractions of oil (Oi/%), water (Water%) and gas (Gas%) are calculated from the equations above, Note that the permittivity (Perm) equation is valid for oil-continuous mixtures while the conductivity (Cand) equation is valid for water-continuous mixtures, The permittivity (obtained from the capacitance measurement) or the conductivity (obtained from conductance measurement), DP and velocity (veD are the input measurements and are being measured by the capacitance/conductance sensors and the DP transmitter, The water salinity and the densities of oil, water and gas (DensOi/, Dens Water and DensGas) are input parameters entered into the TopFlow computer. These parameters are normally set during commissioning, The Water-Liquid Ratio (WLR) is defined as: WLR= W Qter% Oil% + W Qter% The set of equations for the calculation of flow rates of oil, water and gas are listed below: 1. ')~Ù Fl0'i'J ~~\!:~ = Area () vel () Oi]"»;;' 2. -'[1;¡<ra,' F~'D"jIJ Rta:ts = Area () vel () -'Jy;¡,t,=~·,:J)!!! 3. ;·33$ Flo~'J :F?ælt~ == Area ~ vel () Gj,?J$~"] The cross sectional area of the pipe (Area) is known based on the geometry of the Venturi, the velocity (veD is measured by cross-correlating the electrical signals from the electrodes and the fractions of oil, water and gas are found from the set of three equations for the fractions, as indicated above, With the methodology described above the FlowSys TopFlow measurement system is based entirely on analytical equations, Page 4 of 6 "it, . . FlowSys TopFlow 81 'iÏt2diJ¡ro(!J)ß\ID~W Multiphase Meter 2,2. Functional Description A functional description of the individual parts of the TopFlow meter is given in this section 20201, Capacitance sensor The capacitance sensors are located in the extension of the Venturi insert. Capacitance describes the ability to store electric charge on two conductors that are separated by an insulating material. Area Length The capacitance is measured between two metal 4 þ electrodes. The metal electrodes are incorporated in .~ PEEK and flush with the inside pipe wall and are . Emix therefore not obstructing the flow in any way, - The capacitance between the electrodes is a measure I of the permittivity (dielectric property) of the fluids between the electrodes. C 80 . 8mix . Area - Capacitance ap- Length &0 i~ lhe permittivity (dielectric constant) of vacuum &mlx is the permittivity (dielectric constant) of the mixture The permittivity (dielectric constant) will vary depending on the percentages of oil, water and gas inside the meter and is an input to the set of equations presented in the principle of operation, 2.2,2. Conductance sensor The conductance sensors are located at the same place as the capacitance electrodes. Conductance is a measure for the ability to transfer electric current through a conductive material, The conductance is also measured between metal electrodes, These electrodes are also incorporated in Area < Lenath . PEEK and flush with the inside pipe wall and are ~' therefore not obstructing the flow in any way, The resistance between electrodes is a measure of the conductivity of the mixture between the electrodes. Length (j , = mix Res(Q). Area Resistance O'mlx is the conductivity of the mixture - The conductivity will vary depending on the percentages of oil, water and gas inside the meter and is an input to the set of equations. Page 5 of 6 .~~> . . FlowSys TopFlow [1- Multiphase Meter '?(\!<tIlnB1l<nlU(])~:¡y 2.2.3. Venturi meter The differential pressure (DP) is measured between the inlet and the throat of the Venturi insert Distances and angles of the inlet section are according to ISO 5167 The density of the mixture inside the TopFlow meter can be derived I from the Venturi equation. II dP ./ DP Pmix = K· Velocitl ( " \. p~ K is a constant, DP is measured and the velocity is being measured I r ...;:inq cross-correlation on signals from pairs of capacitance or II conductall':~ electrodes. Velocity 2.2.4. Cross-corre~ation Cross-correlation is a mathematical algorithm to calculate the time shift between two signals, This method is used on the capacitance or conductance signals to calculate the fluid velocity inside the meter. & - Upstream The distance. d. betw6en the set of - Downstream sensors are fixed and known and /V~ when the time shift 1: is found by "\ .r ~ .' './ . . i" / ", cross-correlating the signals, the '. f '-,./ .,... '.f Velocity can easily be calculated. ~ The sensors, here illustrated as Time blue and red, will for the TopFlow - -. Calculation of Velocity meter be capacitance sensor in ~ Î) . d case of oil continuous flow and Veloczty = - conductance sensors in case of ~ ~ -1 r water continuous flow. 7:: Time shift between signals The oil- or water continuous state is a feature of the liquid only, irrespective of the content of gas in the fluid mixture. Page 6 of 6 . . APPENDIX 4A FLO\VSYS PERFORlVIANCE GPE MUL TIPHASE METERING TESTS Summary from Report No: S/EPT/047/03 Andrew Hall - Pipeline Transportation Team The GPB multiphase metering tests were conducted during August- October 2003. Four multiphase meters were tested. The four meters tested included Agar MPFM-401, FMC Flowsys, Roxar MPFM1900 VI and Schlumberger PhaseWatcher (VX29). A brief description of the measuring principles is included in the table below: Meter Volume flow Gas fraction Water cut Agar Positive displacement and Venturi Microwave MPFM 401 Venturi Device Device (GHz) i FMC Cross correlation and Venturi Electrical impedance Flowsys Extended Venturi Device (MHz) Roxar Venturi Device and cross Gamma densitometer Electrical impedance (MPFM 1900VI) correlation (137Cs 662 keY) (MHz) Schlumberger Vemuri Device Gamma densitometer Gamma densitometer PhaseWatcher Vx 29 (¡33Sa 80 keY) (l33Sa 29 keY) All testing was done through the various MFMs in series, allowing for direct, real-time comparison, and then benchmarked through the ASRC portable test unit. The trial took place at V -Pad, utilizing the common test header to maximise efficiency, as well as providing the opportunity to test wells producing out of all three Prudhoe reservoirs - the Ivishak, Kuparuk, and Schrader. The tests also involved calibration and verification of the ASRC separator with nine tank tests, with at least one tank test per reservoir. Each vendor was allowed to audit the ASRC separator for details on operation and equipment, and each signed an agreement that ASRC would serve as the test benchmark. Evaluation Criteria - Measurement Accuracy Three different procedures were used to assess the meter performance. Also the final meter evaluations considered other factors such as installation, operability, HSE, and cost. The following evaluation procedure - called "the 5% criteria" was used specifically to rank the measurement accuracy for all four meters. This procedure recognizes the value of low measurement uncertainty and weights the results accordingly and therefore is more pertinent to the discussion of the measurement performance, which is the focus of the AOGCC report. In the 5% criteria, each test point was rated according to its deviation from the reference value for liquid flow rate, gas flow rate, and water cut. A value of 5 was allocated if the liquid or gas flow rate is within ±5%, and the water cut was within ±l %; a value of2 was allocated if the liquid or gas flow rate was within ± 1 0%, and the water cut was within ±2%; a value of 0 was allocated if the deviations were outside these ranges. To allow for uncertainty in the ASRC test separator, used as reference data, an allowance of 5% on liquid flow rate, 2% on gas flow rate and 0.5% on water cut was made before calculating . . the above scores. The points were totalled and then divided by the number of test points to give a normalised score. The values describing the perfonllance of the Flowsys meter, using the 5% criteria, are shown in Table 4A.1. None of the multiphase meters tested could attain the perfect score of 15. This is to be expected since the flow streams tested at this location were all very high in gas volume fraction. Multiphase meter performance deteriorates as the GVF increases. The data shown in Table 4A.l demonstrate an improvement in measurement uncertainty of liquid and gas flowrates and water cut by limiting the GVF range. In this evaluation a GVF limit of 95% and a liquid flowrate limit of 1100 stbí d were used for comparison with other meters in the trial. For the Flowsys meter most of the remaining outlying points were eliminated by further limiting the maximum GVF to 93%. It should be noted that the within the proposed EMS multi phase metering system, the Flowsys will be operating at GVF< 60%. The OPB test data were all focused on high GVF region of the test matrix and therefore did not produce many test point at low GVF. Therefore the discussion in section 5 of the report uses other test data from flow loops, which has a higher population of low GVF tests to supplement the assessment of uncertainty presented in this appendix. Table 4A 01 - Summary scores for multiphase flow meter 5% criteria Parameter FMC FMC lVIeasurement All data GVF < 95% _ Capability Liquid> 1100 stbíd Liquid flow rate 2.6 3.7 Gas flow rate 2.9 3.3 Water cut 1.2 1.3 TOT AL score 6.7 8.2 Figures 4A.l - 4A.3 show plots of data collected from test loops and field tests reported in references 1- 5 on the uncertainty of the measurements for liquid, gas and WC for the Flowsys meter. These plots were used to assess the anticipated performance of the Flowsys meter within the EMS multiphase metering system. . . 50 " Flowsys Holstein NEL, 2005 _ 40 - - 'Iendor specification III Flowsys, Prudhoe Bay 2003 (,) c I F!owsys, NEL, 2000 III 30 t ... " .æ " Flowsys, Trecate, 2001 III i, '0 0 ... 20 1 Flowsys, CMR, 2000 0 ... ! '0 ,0 ' )- III I ~ > 10 + ;) " <:: l'CI J -" -~ > ãi l ,~ ~'~'-¡:O~ ;' ",.-=co _, .~ .. -= ""~,,,(.: ~_ .0.-: ... .to- ~ ,=- "-10::'" .,=", ., - , =-- - .~ 0 <\0...,(, 0 ~ '"' ~ ~ .. ~ 0 ') ~ ¡ ~Æ ;< ,: )C, ~,'{ > i(~~Ç;.~; ~ 0:. _ ~-' ~ .:~ ~~ -ð-J :& ~ ',( v "\ 0) o " ~ i' ~'iP: "o£c x()C-"ijC{:~~qgY> , ... 0 i==- '" -= ="'=-;=-'=>1> - = '" =... -'='"" =.,.-==a -,'~ ~ ....p~ o.:J 0 ~::fJ,j( ">0:: "/> ... . ~ G\-. ~ -=0 y'" oJ¡þ. 0fJ"0 æ ',,;- -;. :u ,10 - ' "0 ,,"g "'J> >o~, ') III ... '0 =- -; l'CI 0 " j ,20- " 0 ¡:¡:: '-1 ::æ -30- ::s 1:1' :;j ,40 - ,50 i I 0 10 20 30 40 50 ÔO 70 80 90 100 Reference GVF ("!o) Figure 4A.l - Flowsys - liquid flowrate uncertainty vs. reference GVF (Test Loop and Field Tests) 50 - I " Flowsys Holstein, NEL, 2005 ! 40 - ~ , vendor specification Gì '.7. Flowsys, Prudhoe Bay, 2003 u Flowsys, NEL, 2000 c 30 - ! 0 Flowsys, Trecate ?()I': I .! ~ 20 +1 I-IOWSYS, CMR, 2000 ... ~ ), 0 - 0 ~ 10 - - .--'- " ^"'=' -"~ ;- ,&,,;.:: ,=oo->'~......;", ~ ~o=>O 0-=0 "," ~ ..".,.." ~ <:: l'CI ::::;J- 0 _, 000 0 ~ /) ãi . 1-;;~.o °0°0) " ... o 0; x' ::0 ~:: ~ - :~~":. ~~~>,;' ç- ~ ... ": () 0,_ ~ 0 <;::'-0' ~ ~o(jX " ....) g ,10 - ~ - ~ :"g - O"~ - ~ , <~- -' ~o ~fx Co ~;fi:;0~ ;¿o ~: ~ - ) CD CD - ~-<o -~'~"X *~Q g J f! -20 .,. 0 /: ~ " , 0 Q ¡:¡:: ,30 - , !II l'CI 0 ~ ) > ,40 < } , x -50 0 10 20 30 40 50 60 70 80 90 100 Reference GVF ("!o) Figure 4A.2 - Flowsys - gas flowrate uncertainty vs. reference GVF (Test Loop and Field Tests) · . 25 ~ o Flowsys Holstein, NEL, 2005 ' i 20 '- , 'lend or specification ãì Flowsys Prudhoe Bay, 2003 ' U I ; 15 Fiûv\lsys, NEL, 2000 i Ji 0 Flowsys, Trecate, 2001 ¡ ! Flowsys, CMR. 2000 i E 10 , e C) 1 '; 5 ""Q) _0 I .... /( ...::> 0,) I ::J :< 9 < x_ -~ --. ':::- ~- ~ ~ .. o a ~ .~';"( -- ~ ""- ~ -X~ =- ~ ~: 7" -. ~"'~:'J,__ ':)~;";-~~::.- "",:~] o:"~~'<. -- ~." p,,:> i en n ,,~- - CiI - "",qo.~ 'ox, " (L, '-"á~~~'$.3';::~ V - ,"---'; .g U "' '- " __ .. _ '. __ 3 _. 0-= ~ ~ ~ -~ V ~ í)::: .. '-~¿fé~(þú-' .. :j~~~ (30 . 'f::.~~~~('~:'~<J _~~u" - I Q / - :> 0 '~ .£r~ c.O_ '" ~ õ ~ ,,-:~:".. .~, i ~ 'C,"~ ~ 0 . Ii( 'i. I - -5 " 0 0 C) 09<,-"::" ! '- ~ :::> ó^ I o o' ," i ~ I ~ -10 ¡ ~ I U I Qj -15 ~ , ~ . -20 .-; -25 I o 10 20 30 40 50 60 70 80 90 100 Reference GVF (%) Figure 4A.3 - Flowsys - water cut uncertainty vs. reference GVF (Test Loop and Field Tests) REFERENCES LIJ Klepsvik, 1., Dahl, E.O. anà B3.k~r, A.C., "Multiphase Flow Test Report - Top Flow Multiphase Flowmeter," Christian Michelsen Research Report, CMR-00-FI0021, September 2000. [2] Hall, A.R.W., "Evaluation of the FlowSys 10pFlow Multiphase Flowmeter," NEL report 200/2000, October 2000. [3] Mazzoni, A., Halvorsen, M. and Aspelund, A., "Field qualification of the FlowSys TopFlow Meter", report from AGIP Trecate test facility and FlowSys, April 2001. [4] Hall, A.R.W., "Field evaluation of multi phase flow meters for high gas fraction well test metering," BP EPTG Report for Greater Prudhoe Bay, S/EPT/047/03, December 2004. [5] Hall, A.R.W., "Qualification of an 8-inch FlowSys TopFlow (FMC) multiphase flowmeter for Holstein," BP EPTG Report for DW GoM Production (Holstein / Mad Dog PU), S/EPT/096/05, November 2005. . . AJPPENDRX 4B ARAlVICO TEST RESULTS Field le~~ ~?ckground The field tests were carried out by Saudi Aramco at the offshore North Safaniyah field. This field is considered to be a low GOR production area (Estimated GOR = 200 - 400 SCF/BBL). The GVF of the flow streams tested was about 75% during all tests. The Flowsys meter was tested for three months. A service barge (as shown in the above photo) was used to handle the well testing. Data form conventional two phase test separator on the barge was used as the reference. Information on the accuracy of the reference devices on the separator is not available. Reference water cut was determined based on manual sample from liquid leg. The TopFlow meter was installed upstream of the test separator and was tested under normal well testing conditions. The Flowsys meter was operated by the barge operator personnel. There were no "calibration" of the meter after the tests started and no service maintenance was required. Performance Criteria The Aramco requirements were: ~ Liquid Flow Rate: 90% of tests within +/-10% (relative) compared to test separator liquid flow rate. =~~........ -- 0 "Vater Cut: 900/0 of tests \vithìn +,'-10% (absolute) compared to samples from liquid leg. 0 Gas Flow Rates: 90~ó of tests within +i-15°/ó (relative) compared to test separator gas flow rate. The Test results are sho\vn in the following Figures 4B.1- 4B.3. The TopFlow meter perforrned 'Nell during the test, including the water cut measurement and was approved by Aramco to comply with the perfonnance criteria stated above. The uncertainty in the method of taking manual samples from the liquid leg is reflected in the water cut data scatter and the water cut performance criteria of -'-/-10% (absolute). The deviations seen in the water cut comparison includes both the uncertainty in the T opFlow and the uncertainty in the reference manual sampling. :.T.'7uIf":=/).J:' c: . ,.-- -.. - ---- FlowSys : ~i:-J:-I -I n:, uuw I i DOOD I . ,,'" ¡ 3 eooo - !: ¡r ...... ! ~..~~"- ~ eooo .. -,--- -: '----~~"--- ! ~ 9-_': .;:.: ~.:::- --' i 4DOO I .. · ./l--' _ ,,- "' ~+ -~ 'to ···001 2000 ~~.- -. ' ..'." + .{;,i)o" :".- - @ 7'- IJ :z-noo 4001) GOOD Boom 1000iJi 1~@ T e&t Barge LiquId Rate \SB'-:PDl Figure 48.1- Liquid flow rate accuracy - ~ -' ~'f:f~!~~~!:-A~-::'~: ,~: I- t I ,-: r :: FlowSys MPFM ~¡ 10000 I u ~ - " ~ ~ 30,.. ",1 11;) I'" "S 0a-_ _ a:: SOOO ._ ," :à-<"'~---- f>' Õ ,~.-.:~O ,')- == 400!} . "","~V/ ~ r. ;*'r,- ~ . ~1¡.'~- ,g' ZOOO ~~ ,.'~'; ..)~"So g~ I ,) 2);)9Q 4ðOO .moo ,~ 1OOo!'1F.) 1~ Test 8aï'ge on Rate (STBPO) Figure 4B.2 - Oil flow rate accuracy '" :~ d-f~,·:(!!.~~:~..~~c: IJ ¡:tl.~ 0:: FlowSys 11)0 30 ~ '¡W ~' =~ - 7.0 " ~- ~ U ßO ia ~ - 50 .' ifJ ~ Qr .- :i -'0 , Q ~ !i ,- u.. .9- ' lb ~ ~ ,- ~ .. .c¥II 2J) . . .' .. ~ :!L H) ", r ... .' ;¡:, ~ io I iJ ¡p' · i)(!I~_i§." \ 'D 14J 20 ~ ~ 51) so 7(1 8D 00 1'00 Test Ba rge 1pl:Jter Cut (~,~) Figure 4B.3 - WateJr cut Accuracy '~ "- Andrew Hall has suggested the following formula for CDS tested the Gasunie cyclone in the lab with very little liquid, At a calculating combined uncertainty in mixed streams GVF of 90% and higher (up to 99.99% at actual conditions), the cyclone ET = {SORT [(OVíOTrEV^2 + (QTF/OTrETF^2]) separated at least 98% of all liquid droplets of 10 microns and bigger (at QT= Total volumetric rate the ASRC conditions). The total carryover depends on the incoming QV = volumetric rate through the Vortex meter droplet size distribution. So at these high GVF's the Gasunie cyclone QTF = volumetric rate through the TopFlow should stay below the 0.5%v liquid in gas carry over. EV = accuracy of Vortex meter At lower GVF's we do not have quantitative test data. However the ETF = accuracy of TopFlow for gas cyclone was tested in a skid similar to EMS ( with Shell and Daniel MPFM) about 5 years ago at NEL. /l.t that time an ultrasonic meter 'Nas used to measure the gas rich leg. This meter stopped working if the Note: The above formula calculates a mixed stream liquid in gas exceeded 1% by volume. The UT meter never uncertainty that is independent of the total gas flow rate reached that point during the one day testing. It is therefore reasonable to assume the liquid loading of the gas measured by the Vortex meter is less than 1 %. Assume gas diversion for all flow rates (see Table 5) Assume liquid volume fraction of 0.5% to 1% in the gas rich leg of EMS Vortex Meter Accuracy @ 0.5% 5% see Fig. 6 Vortex Meter Accuracy @ 1 % 10% see Fig. 6 TF Meter Gas Accuracy 15% Average Vortex Meter Accuracy for 0.5 to 1 % liquid 7.50% see Fig. 6 Diversion Rate EMS Accuracy % EMS Accuracy % Ave Vortex Accuracy 5% Vortex Accuracy 99% 7.6% 5.2% 98% 7.7% 5.4% 97% 7.8% 5.6% 96% 7.9% 5.7% 95% 8.0% 5.9% 94% 8.1% 6.1% 93% 8.3% 6.2% 92% 8.4% 6.4% 91% 8.5% 6.6% 90% 8.6% 6.7% 89% 8.6% 6.9% 88% 8.7% 7,0% 87% 8.8% 7.1% 86% 8.9% 7.3% 85% 9.0% 7.4% 84% 9.1% 7.5% 83% 9.2% 7.7% 82% 9.3% 7.8% ( )':-~ \. : -, - - 1". ,':---. cJ· ·_-Jt ï-\ ----' "'----- xy - sŒ:¡palI"atö©ff"iJ technology , An ~~;:::;;;'; T~chnologiEs Subsidiary CDSoGaS!u!J1Re cyc~oll1e scrubber The GLJ scrubber was originally developed by Gasunie Netherlands. Gasunie being faced with undesired condensate fonnation in its gas transmission system in the Netherlands, has tested various types and makes of different gas-liquid separators. On several occaSIOns it was shown that a separator that failed to meet the given specifications of the manufacturer caused the problems due to unremoved liquids. With the experience from testing and theory Gasunie developed its own separation device and tested it in its own high-pressure research facility. Full-scale tests carried out under high pressure showed that even at very high gas flow rates the catch efficiency was close to 100°/Ó. Gasunie separators are already more than 15 years in operation and have performed very well. In the Dutch gas transmission system 1000 to 2000 separators are in use. In 1999 the Gasunie cyclone was improved together with CDS Engineering in a joint improvement project. The result of this project was that the pressure drop over the original Gasunie cyclone was reduced by a factor two while maintaining the same separation performance. The improved separator is called CDS - Gasunie separator and is exclusively marketed by CDS Engineering. The advantages of a CDS-GU cyclone compared to a conventional scrubber are: ~ Small size and weight as a result of high allowable gas load up to K = 0.9 mls. '3 High liquid í gas ratio's can be handled ~ Maintenance friendly, ~v rnoving parts or small channels -low fouling tendency. While the initial Gasunie separator has been tested extensively up to K values of 0.9 mis, there are not many references that work at this K value. The most important reference of Gasunie separators at high K value are NAM locations Tjuchem and Bierum that operate at K values of up to 0.9 mls. CDS Engineering BV;, Delta 101. 6825 MN Arnhem. The Netherlands. Tel: +31 267999100 Fax: +31 267999119 HR. Arnhem 090.90.976 Certificate No: 652134 ('- : )"-Ì, ~, _-=-=:J ,L -==__:J~_/ .\ --- ~~~/ '--' &" 10 '. . sepa!l"3I ~ilO>i!"i! J~iSdh n(O~cogy v An~;r:5K~ T~chnologies Subsidiary ¡Principal of CDS-ga§unie de§ign 'ra,,'ss The CDS-GasunieT:v1 Cyclone Scrubber can be used for separation of ~u:!;>~ liquids (water, hydrocarbon, glycol, etc.) from gases (natural gas and ] (iI 'J other), for the protection of downstream equipment (compressors, ,! r gas turbines, flow meters, etc.). Solid particles (dust, sand, etc.) will I~ ~ also be removed, making the scrubber suitable for use as a gas := :f! f 1 wellhead separator. ~, ~~..- , · H t ¡).o! ,',. ,n :>:~~!ss '¡ a \' gas :Jl; \ :r4 ~ "t ~'~~J~s:JtJ' Operating Principle = ii' r II f The optimised blade geometry brings the combined phase into r ~ rotation. The resulting centrifugal force moves the liquid and solid ¡ f particles towards the vessel wall, where they form a liquid film I I flowing downwards to the bottom of the vessel. The gas exits the ¡ ~ vessel through the central pipe connected to the gas outlet nozzle. I : The baffles in the bottom of the vessel stop the rotation of the liquid, t -:... ---_~~ and the blocking plate prevents liquids from being entrained with ~ . . t the gas. In this way it is ensured, that no gas carry under or liquid ! ¡ cany over can occur. II ! The optimised vane geometry is shown in the picture below. ~I__" ,__-.I . .'.- ¡< I .' ~ i· I ~~ I _.c¿J ~"~~.'::' ]..~ if n ~ nutlet __co I _ ,,__, ,_ _ ~_ "" CDS Engineering BV, Delta 101. 6825 MN Arnhem, The Netherlands. Tel: +31 267999100 Fax: +31 267999119 H.R. Arnhem 090.90.976 Certificate No: 652134 ..' d I"": ;' ):-,., l ',~, ,--,t,\ --~ ~ --- ---,-- ../ . <. ; '-" se¡pa~atñoIn '((5CrH'o~~g!y ,.- An:r;~¿r~ Technologis$ Subsidiary The Gasunie has made this graph long time ago. [n the testing they used natural gas and glycol with a liquid percentage ofmax 2 %v. Operating pressure was 40 barg (580 psi g) and operating temperature was 25 JC (77 OF). Separator comparisons 100 ,- -~ :..--.. ~. ~ .~... ,--------- - - "-.- -----'. v :¡J ">J ." r' ¡ ;> .,.J4!. ;"{ 90 ;~ ì -:: .... ¡ ,J vane separator ,... i ; Gasunie cyclone ,0 '; gravity separator 0' >. 80 ,-- '; multicydones v c .- meshpad Q '0 :> coalescer separator :f r;;. Q ~ 70 ... co u 60 .~ "'" )- 0 _. _u__.~:-_.___~___,._ _._.-.__ _. . __ ~...._'-__.___'_"_'"_ ___"__ <..1-'-"'-. _~__~ ___.-..---._..__~_ _..___ _c_ _ __ -_.--~-...., . 02 04 Or6 0:8 1 0 Gas Load Factor , .! jJ "'as Gas Load Factor = V <Ta- >¡: ~ " CO> > P iiq!lid - P gas Pgas = gas density [kg/m3] Pl1quld = liquid density [kg/m3] vgas = superficial gas velocity [m/s] Catch efficiency is defmed as the percentage of liquid that is separated by the separator. The liquid was injected into the gas and thus the inlet liquid flow was known. The separated liquid is coliected in the bottom of the separator and measured as well. In order to get a complete mass balance a filter had been placed in the gas outlet to measure liquid carry over. A catch efficiency of 80 % means that 80 olav of the injected liquid has been separated and 20 o/aV was carried over with the gas CDS Engineering BV, Delta 101, 6825 I\t1N Arnhem, The Netherlands. Tel: +31 26 7999100 Fax: +31 267999119 H.R. Arnhem 090.90.976 Certificate No: 652134 -- ~ ------- ---. -.-" -- _. __H_ EMS Control Philosophy CLIENT: ASRC f PROJECT: BP Alaska Rev No. Details of Revision Prepared Checked By I Date By I Date 5 4 3 2 2nd Issue for Review OS 14-09-05 1 1 st Issue for Review OS 10-09-05 Business Park IJsseloord 2 t~ ]""~~JS t Delta 101 6825 M N Arnhem "'~:.:J, :.::-/ c::=-', /Jb The Netherlands sepatratfion technology f? Tel. (31) 26 7999100 An . :;C'Ds Technologies Subsidiary Fax. (31) 26 7999119 Client Order No. Field/Platform BP Alaska End User ASRC ~ ". Client Document No. CDS Project No. CDS Document No. Rev No. No. Pages P04-11006 P04-11006-CPH 2 16 ~ Rl"v n~tp ?~n~n~ r.WF-"J 1% ....¡ " =:J'tV' \ V(.J""'" ...,.¡IVV. ¡--tv . -....... . --".....- -. . n' ~ _- \.,~" / K8vision: 2 sep2lí!"a<til'0>~ tECntnoßo~ (,~'! '~ Date: 14.09.05 A~ T:;':~ T::chnologiG$ Subsidiai'Y Talb~e of Contents 1 > Introduction>...,..... >,..... > >. > >. > >,.. >. >. > >,. >. > >. > > > >.., >., >"""" >.:.., >.. 0 >:". >,.", >. > > >...,. >. >..3 2. Control Philosophy.., ,> ... .>. '> >, .., >. >.>...., ..>.".. >. > >.. >. >. > > >.., >.., >., > », >... >, " ."". ,. ,. >,.3 2.1 High Liquid / Low Gas......".,...,........ ...,......"........................ ..... ..................... .......3 2.2 Low Liquid / High Gas ....................... ................. .......... .......... ........ ....................... 4 2 [)f ~ .---= J.. -=-=I,:~Y".~, ,-,L.Jv ..JV'...J. i!V _, V r . 4.....,,·...,.....,' 5iEpa ratãot!1 't~dtu¡¡¡¡O)~o~ '¡~/ R.evlsion: 2 --~ Date: 14.09.05 Ani::.:,; TEchraojogÎE5 Subsidiary ~o ~ ntrod lUIctnolnJ This document is meant to outline the control philosophy for the EMS (Enhanced Multiphase System) skid that is to be supplied to and operated by ASRC. 20 ContR"o~ PhUosophy A particular design consideration for this system is the high design line viscosity of 1000 cP and hence the very low Reynolds numbers that could be present in the venturi of the Topflow multiphase meters. The problem with Reynolds numbers below 5 x 1 Q^4 is that there is no published data as to the performance of converging nozzles and therefore there will be a large uncertainty in to the measurements from the meter. To overcome this issue a different control philosophy is recommended as compared to other EMS installations whereby a minimum, and yet to be determined, pressure drop is to be maintained over the Topflow venturi. Due to the large variations in gas and liquid flow rates separate control valves have been placed in the gas and the liquid lines. The intention of these valves is to regulate the pressure balance over the cyclone separator so that dry gas enters the vortex meter in the gas line of the vessel and that sufficiently degassed liquid enters the multiphase meters in the liquid leg over the complete operating envelope of the unit. The benefit of degassing the liquids as much as possible is that the measurement accuracy of the Topflow meter improves. The intention is to regulate these valves by use of the guided wave radar transmitter located on the cyclone separator in the following methodology. Some control scenarios are explained in some detail below. <J At start up the gas valve opening will be 0% and the liquid valve opening 100%. In all scenarios the liquid control will be the source of primary control. The reason for this is to minimise the total pressure drop over the skid. 2.1 High liquid flow Gas ~ The system will then try to regulate a liquid level at a 25% set point by closing the liquid control valve. G If the liquid valve is more than 700/0 open then the gas valve will start to close until the liquid valve opening reduces below the 700/0 threshold. The reason for applying a 70% opening maximum is that should a liquid surge enter the vessel there is valve capacity left to help in the disposal of this liquid. Otherwise the cyclone separator would soon fill with liquid and carryover this liquid to the gas leg, thus affecting the accuracy of the gas measurement. 1 of n · _:.=J_J _ ==.J(!Y/} Revision: 2 5<: pa 1i"atßiO>ii1 '1:Œ:CÙì1 ii1JO~V~ \~/ -=-' Date: 14.09.05 .~n ;r:;=(~ Technologies Subsidiary 2.2 low Liqusd I High Gas () The system will try to regulate a liquid level at a 25% set point by closing the liquid control valve with the gas valve fully open @ Should the dP over the venturi in the Topflovv meter be less than the minimum value then the 25% set point of the level transmitter shall be ignored. In this scenario the dP over the venturi will become the controlling parameter. The reason for this is to increase the Reynolds number in the venturi to ensure that no loss of accuracy is seen. () To achieve the minimum pressure drop over the venturi of the Topflow at the lower liquid flows then gas needs to pass through the meter. As a result then depending upon the particular fluids being processed the level in the cyclone separator may fall below the 25% set point. () In this control mode it is likely that the liquid control valve will be nearly closed due to the higher dP over the gas leg. If a liquid slug arrives then there is a risk that the separator will rapidly fill up and therefore the gas vortex meter may become flooded with liquid. To overcome this scenario then should the liquid level rise above 50% in the separator the liquid valve will be forced to open. At the same time the gas control valve will start to close. Once the rise in liquid level is arrested then normal control will be re-established I initially by opening the gas control valve followed by the liquid control valve. - 4-ofó ---- '!~V, " S;:U:»2Iir3ntüDrJ {CiE,::[hñ!!)~O~ ' ~/ . .. Re\Jision: 2 An ';::2~ Technologies Subsidiaí"Y ~ Date: 14.09.05 I Standard inputs I ~''''''''''''''''''~;:~:~;~'''''''''''''''''''''''1 ¡ . _ (Analogue) ¡ ..-+- Temperature ¡ I Outputs I ¡ (Analogue) ¡ Meter 1 i r......··..........·......·..···..·....··......·....·..........·........··......¡ !" <i' ¡ Pressure drop ¡ : : I: (Analogue) : ¡ Contro!dLevel Set Point ~ ¡ : i ¡ to 3 Party P&ID I ~ ~ I _ i Conductance ~ : ...: (Digital) ¡ I : : I : : High level Set Point to ~ : A i Capacitance 1 ................._....~':~:.:~~l~m_... ~ : ~ Lm.............m.(::~;=').........m..mJ -4 .. q . Gas Control 4 ^ Valve ~ ä (Analogue) -<f? " 3ra Party PID Controller .-.¡ 4 ú ... UqU~a~~ntrol : I I Additional inputs I (Analogue) ! ,.....!.......~~.~.:~:~~..~~:~.~~.....}...._ r....,....·..···...·..H..··..·....·..·..·.......··......··..··....l I : I 1 r j <:: Gas Flow I: I ~ ~ Pressure j I ... ~ (Analogue) i : ¡ ( j.~ Gas Valve I Outputs I : ~ ~ I Temper::¡f\Jr~ I ¡ Positioner I i (Analogue) I ~ : i I i i'........................................................................~....: I i j fI Liquid Valve ¡ j ~:4 ¡ Pressure drop ¡ Positioner i Control level Set Point ¡ i (Analogue) i ¡ to 3rd Party P&ID ~ ¡ ¡ ¡ ..... I ~ i ~ i "" Level Transmitter : : Meter 2 ~ Conductance : I i i ~ (DIgital) i ,................................................................... · . . . · . . . · . . . ¡ High Level Set Point to II ¡ ¡ ¡ ¡ 3rd Party P&ID ¡ 4 ~ Capacitance ¡ I ¡ ¡ ~~ ¡ ...................................... ...........0· I..... I I... ,.,....,....,.n.. ,;' ~ .......n~...... ........ ~...... ...... ," ,.,.. .......... ,...... '" 1.1 ~ ~ ~ ~ <t - ~ w Figure 1: Control Schematic n of h )) )) SAFE AREA V -1 00 0----- MUL TIPHASE METER CONTROL I.D. 364 mm COMPUTER TIT 2860 mm & DESIGN PRESSURE 1335 psig NOTE 3 & DESIGN TEMP. -50/+250° F rfl 600# RF m 600# RF ~ ~ ~----------------------------------------------- I SCOPE II SCOPE CDS II J FB J ¡ \ ASRC I 3" 2500# NOTE 1 IC()JI . ) ¡ 3" ® I ® f----~~-----n---" ~" . 1- . bL3"600# 4" NOTE 6 ¡ CD æQ I' ..J BD - fPSv :' \ w .--... , I ~ ;[T ""02 ""Q - - SET OIJJ5 "'''I :' - a.. 2"900# (\ :. '\ I ü !; 3" ::¡ _ : 2" FIT í' ADDED SPOOL & VALVE :::> " : CD CD SCOPE ASRC ~ 3 '-__n___ Ci----------- ~ 001 ~ Ii CDS WILL SUPPL Y BLIND FLANGE II Q 3" H2 CHOKE I 0 0 >- NOTE 6 FB NOTE 6 FB z z FB ~ I I' I I >< >< ---jI N3;1 I ADDED VALVE I rYl u.. Q I (.0 6"x3" .\ - 20xD - VORTEX - 5xD - f2 - t- SCOPE ASRC I L.lliJ y c:o '~I ' , I ~ u... _ 2500# ! 600# 01 CD I ' rrl I INLET 5K ¡ : _ Q I Z : FB NOTE 6 NOTE 6 FB Q l.U I i lJ!LJ I ~ æ V 100 H I I I ~ æ Ö ' , ~ NOTE 2 - C()J TURBINE METER (FUTURE) 0 6",3" Z "I FB FB I OUTLET 5K II 01 I I l-r ~ SCOPE ASRC I Dill 3 ![()Jh-![()J N I~ NOTE 6 2 I I I I - 3" FC 4"x6" NOTE 6 I SDV 0 ~r-----------------------' . ~cv 600# 12500# I ' NOTE 5 Z .. LIT ¡ : (Î\___-- 002 . 001 ~' L~ 12"1 CD V Fa : l' WLJ 5 CD--"-- _ ~ - - - - - - - ~ ¡ ¡ _~I n"l :z I \ ¡ ¡ I~ II \ " CD (.0 I, \ @G ~_______________________J ~i ~ - NOTE 6 NOTE 1: SKID BYPASS LINE, TRANSMITIERS SCOPE CDS 01 _ ~ F8 2" " ,,~ FB NOTE 2: BYPASS LINE AROUND CHOKE. ! MOUNTED ON SCOPE ASRC SPOOL 0 ¡y-y, 3 x4 r-rY1 NOTE 3: DESIGN PRESSURE STATED IS EQUIVALENT TO ! I IlA..flt-- -i1--CJ--Li1.).JJ1 I I A FULL ANSI 600# RATING AT 250°F. ;_____n________________~ NOTE 6 DESIGN OF THE SKID IS TO BE SUCH THAT : ¡ _ ;---------------------~ _ ~---------------------~ THE FULL ANSI 600# RATING, APPLIES AT ALL ---1ml- IK;'~ I 1 ¡ @¡L¡ @iTEMPERATURESINTHEDESIGNTEMP,RANGE. ,,:: -______1. OPT ¡ _______1. OPT : NOTE 4: DELETED 4 == ¡ : - œ: ¡ 002 ¡ œ: ¡ 001 ! NOTE 5: GUIDED WAVE RADAR TYPE INSTRUMENT WITH : ¡ ~ : @: ~: @ : INTERNAL MAGNETIC LEVEL GAUGE. . I : : u.J: : 2" '-___n_n_______________"~ 4" ::¡¡: ------.~- PT: :iE -------~- PT : NOTE 6' Yz" THREADOLET WITH THREADED PLUG ~ ¡ 002 ¡ ~ ¡ 001 ¡ . ~: : ÊE: ~ --1C()J~ ~ -------t- ;O~ ~ ¡ (D ~ n-----t- ;O~ O~ ¡ (D ! : ~..-....-. : :---Þ--- 2" I[()J~ = NOTE 6 T ,_____________________J - T ,---------------------, - - f" ¡_n_......_____n____; 3" 1.3 DESIGN TEMPERATURE/PRESSURE UPDATED 130706 MG DS Q i ¡ 12 DESIGN TEMPERATURE/PRESSURE UPDATED 270606 MG DS æ ¡ ¡ ¡ 11 COMMENTS lISRC liDDED. cV'S MOVED 0030306 MG OS ¡ ¡ I Rev,s,on Description 01 Rev,sion Dole Drown Checked - 2" ¡ ¡@-E3-DoteNome ~DS ¡ 2" ¡ Drown 190405 MG ~ Ù NOTE 6 - NOTE 6 :.-----T-----------.; FB Checked - - t· t h ~ ~ 2"x3" 4"x3" separa Ion ec no ogy '\.t . I I I ~~L-. Process 190405 OS AnofllCTechnologiesSubsidiary ZJ I L.---'l~r--- Size Proecl BP WELL TESTING Client Ooc,No. - NOTE 6 A 1 Clie~t FMC ~~;nt:e~ef P04- 11006 lnUcy·l- I C:;...nle T;tI~ pkln n I n L _ _ _ _ _ - - - - --- - - - - - - - . ~ "-" APPENDIX - 9 GUIDELINES JPERlFORIVIANCE OF fA\CTORY ACCEPTANCE TEST l. If at all possib Ie these documents should be in electronic form including Computer Aided Design (CAD) drawings of the mechanical aspects of the equipment. 2. Agreement between the way the manual says to hook up the equipment and \V'hat was actually done. It is suggested that the final set-up be done in the presence of the customer. ., If the Multiphase Measurement System utilizes one or more HNII's (Human-Machine-Interface) ~, that have screen presentations including graphics with dynamic data appearing on the displays, they must be validated for proper data placement, calculation, and update frequency, 4. If the muItiphase measurement system is a wet gas system, water cut may not be a required solution. Conventional water-cut instruments such as microwave, or capacitance, or radiation densitometer do not function properly at these elevated gas volume fractions. 5. If the measurement system is wet gas or GVF >98% at the meter conditions, the FAT will probably have to be at a third party facility. This is especially true for Venturi and Sonic meters. Measuring the liquid in high gas fraction can use the tracer teclmique but one can also use a separator or a second verified meter. 6. If the desired FAT matrix exceeds the vendors system capabilities, the FAT would have to be perfonned at and by a third party test loop. If the FAT is performed at a third party test facility, the purchaser may wish to have either personally witness or have a third party witness the rests. It must be clear if the vendor can make any changes after hook-up and commissioning and during any repeat tests. The flow loop operator must be involved in any pre-test meeting so he understands the ground rules. The flow loop operator may have to detennine the time of stabilization between each matrix point. 7 All valves, solenoids and other end devices that are part of the metering system need to be activated and perfonnance tested to detennine if they operate properly. 8. Agreement must be reached between vendor and purchaser on how to handle the changing of any meter or system factors during the FAT and later during final field commissioning. It is recommended that no factors be changed during the final FAT matrix. Items to be made available to users at the end of FAT 1. The venn":!,, ~h()l_lld supply a fonnal listing of ALL parameters and constants along with their values at the conclusion of the FAT. The accepted ranges and identification of those that can be changed by field personnel should also be supplied. 2, Sign-off sheet to sign, acknowledging that the system met the agreed upon matrix of tests. 3. Report of system mt::é1~lLî':;::~!'t results with illustrations in the fonn of error graphs and exception explanations. Signed calibration sheets for all rnstruments. 4. Data sheets for all instruments with process variables and equipment model numbers, stating especially any changes in scaling or ranges done during the FAT. 5. Schematic of the test loop showing the location and distances between of all components and metering devices, the location of the MP meter, the length of flow line before the fluid stream reaches the MP metering system. -~--. ..... 1=1 '~~ ~~' AJP PEND][X ~ 10 GlIJlDEJlJNES PERIODIC FiELD TESTiNG ~ CALIBR.t\ TION Periodic field-testing may be required as a scheduled maintenance wherein the end devices or metering systems have to be verified. This verification may rangeÎrom simple calibration of end devices to certifying equipment to some standard. To verify the metering systems, it may be enough to test a given well and if the results are the same as previous tests, the system is declared satisfactory. What test options are available are driven by the well rates. This is especially true for wet gas measurement systems, which generally exhibit very high gas rates and very low liquid rates. If the wen production rate is higher than a couple of hundred barrels per day, the only options fur verification may be testing/indexing the new metering system against a Type I multiphase metering system with gravity separation. The following list should be used as a guideline for conducting periodic field tests: 1. Calibrate all individual instruments that form any part of the well test function including process instruments, level controllers, etc. Retain calibration records of these instruments. 2. If the system utilizes single-phase meters, perfonn meter proves with a master meter in series or by removing the meter and calibrating it remotely. Incorporating a prover loop or connecting to a prover tank also suffices. If during this proving process, valves isolate parts of the system, those valves must be checked for signs ofleakage. 3, Validate all system constants and factors to insure that the flow computer calculations are as expected. Over time, factors are sometimes changed to cover a one-time event but for some reason are not changed back to their proper value. 4. If a sampler is used, it should be cleaned and the sample size calibrated. It is assumed that the sampler is installed properly and that the sample extracted is representative of the fluid conditions. If the sample head is a kin~tic type, its internal parts need to be maintained. Poor sample representation is very often the result of poor homogeneous mixing due to low fluid velocity, slow pacing, or improper installation location (II-26, XII-9). 5. The pressure of the well, selected as the ~'proofwell", should be recorded before turning it into the test system. The test rate for this well may depend on the closeness of the test pressure to the production pressure. This has little to do with proving but the registered results when compared to the well's historical perfonnance, affects the acceptance of the proving. Also all counters and accumulators should be checked and cleared to zero at the time the test officially starts. 6. The duration of the test period is a function of the well and the method used in verifying. If historical performance is the reference, the well duration should be in excess of 12 to 24 hours. If the proving is only comparing volumes and rates between the system and reference and not considering what the well "'should" produce, the test time can be much shorter:- i.e. three to four hours or however long it takes to fill a calibrated tank or accumulate enough data (see reference IV-16). 7. Gas is typically the hardest fluid to verify because it cannot be stored in a calibrated volume. Because of this it tends to be the most uncertain of measurements, especially in Type II and Type III meters. If it is separated as a single phase, then verification is straightforward by inference. If it is not separated, verification may have to be done by a test separator. 8. It is suggested that multiple verification runs be made utilizing different wells. If the accuracy of data collected is consistent, that should be sufficient. However, if the error spread is greater than 10% high to low, additional runs need to be made, in order to produce a better average. This is inferred from reference XI-8. In order to have a 95% confidence that the measurement is accurate, the measurement average error cannot be any less than 10%. The reason for repeated runs is the dynamic nature of the measurement, which changes measurement conditions ever so slightly even if the same well is tested. Some wells have a wider range of dynamic performance than other wells. Another reason for variation of results is system calibration, which is why the verification tests are made. Because there are three fluid phases, verification results must include all three phases (see reference II-17). 9. Once the proving is completed, the appropriate meter factors are calculated and entered into the measurement system. For conclusiveness, one final series of tests should be run to verify the meter factors. 1-1 '~y ftj """-' -- !5j! Ii JI!r C:' ·Ä 7J -- -. ~J _J - ---.; "'--. > , - 'I I I í I Flowsys TOPFlow MUltiPhase Meter Site Verification Test Procedure I Docul/Jent type J Doc. no : PRD~OOOOO24544 , Procedure , Page : 1 of 1 0 Status R.eleased VersioQ Change 00. r Date Versiou r RevisioQ 1500000028763 10.03.2004 00 ~ This document is the propertv of FMC M . f - , . easlIremem SOlutIon d' to any party "ithoUt the Written consent of Fi'vIC a~I. IS nOt to be reproduced Or disclosed ¡ ELECTRONIC OR] TN easurement SOlutIOn. Use '. 'G I A.t r IS resPon s 16 Ie fOr veria Cation of I'e I eased . ." . U revblon Status On docu1t¡ent COpy I '"-' I Version : I Revision: ~,. 00 - Page no. : 2 of 10 Table of COJnte!m1t§ 1 PRE fA C IE ..................................................................., ......................... Go. 0............. .................... .3 ,2 § ITJE ,\/ ERtf [C A Ti û N TEST... ....................., .......... ....... ....... ............ ........ ............... .........0.... 4, 2.1 E L ECTR I CA.L P.-'\R TS ...,...................................,.................................................................... 4 2.1./ Currenl loops".......,..............................,......................,.,....,.............."...,......,....".....,., 4 2./.2 Tr ans mill er s .. .. . . . .. .. .. .. .. .. . .. . .. .. . ' .. .. .. .. . .. .. .. .. .. .. .. .. .. .. .. .. .... .. .. .. .. . .. . . .. .. .. .. . .. .. .. . .... '............. 5 2.2 MECHANICAL PARTS......... ................................... ..............................................................6 2.3 CAPACITANCE AND CONDUCTANCE SENSOR....................................................................... 7 2.3./ Capacitance sensor.,.....,.......,..........". ......., ,.... .......,...'...........,..,.....,...",'...........,...... 7 2.3.2 Conductance sensor.. ......... ...................................'.......,.,.,................. '.........".........,... 8 2.4 TopFLOW PERFORivLANCE .................. .................... ....,... .... ...... ..... ........... ......... ............... 10 3 CO RRE CT IV E ACT ION S....................... ........................ ....... .................... ..........,............ .... 10 4 S ITJE VERIFIC A T£ON REPO RT .................................,....................................................... 10 "[c FlowSys TopFlow Multiphase Meter . !J Site Verification Test Procedure I v . ....---' J Revision: I ~---- I erSlOn: 00 - Page no, : 3 of 10 R PREfACE The FlowSys TopFlo~~ l\Ilultiphase l\tfeter is manufactured by FMC Measurement Solutions based on technology and electronic components from FlowSys ASA. Customer SIllIPPort~ Contact FMC l\IIeasurement Solutions Address ~ FMC Technologies Inc, 737 N Padre Island Drive Corpus Christie Texas 78406 USA Telephone (1) 361 289 3484 No.: Telefax No.: (1) 361 289 1115 lE-lVIaH: dan, householder'0fmcti. com [n.ternet: www.fmcmeasurementsolutions.com Copyright All technical infonnation contained in this manual, including any drawings and technical specifications, shall remain the property of FMC Measurement Solutions and may not be used (other than for the operation of this product), copied, multiplied, passed on or communicated to a third party without prior "vritten permission of FNIC ~1easurement Solutions. © 2004 FMC Measurement Solutions Trademarks Products listed are trademarks of their respective manutàcturers. Company names listed are trade names of their respective companies. This revision IS based on FlolASys TJptlow Site VènficatIon Test Procedure, Rev Oa 12.1 [,2002 1f' flowSys TopFlow Multiphase Meter ~ Site Veri fication Test Procedure --' Version: I Revision: '-=v' 00 - Page no. : 4 of 10 2 §1[TE VERIlFICA'IION TEST The objective of the Site Verification is to verify the factory calibration of the T opFlo"v lVlultiphase l\tfeter as "vell as verifying the mechanical parts of the T opFlow meter. The Site Verification test is performed after the meter has been taken out of the line. The Site verification can be divided into the following items: I! Verification of mechanical parts [] Verification of electrical parts !3 Verification of capacitance and conductance sensors !3 Verification of T opFlow performance (Flow Test) The presented procedure covers possible site verification tests that can be performed. Some sites have the possibility of performing all tests while at other sites it is only possible to do some of the tests described belo"v. A seperate Field Verification Test procedure is covering tests that can be performed "vhile the meter is installed in the pipeline. 2.1 ELECTRICAL PARTS The electrical parts that are checked during the Field Verification test is the following: II OPT ransmi tters 18 Temperature transmitter II Pressure transmitter 2.1.1 Current loops All current loops (4-20mA) for the different transmitters are verified by applying a known current. 4, 12 and 20mA are applied to all transmitters. The measured currents read from the user interface shall be within 0,50/0 of the applied currents. ì~' . FlowSys Topflo,*! MuiÜphase Meter "3 - §~;:~ ëJ erificatioif if ~t Yrocedure ..... , J i J Version: l Revision : I '~ I 00 - Page no. : 5 of 10 I 2,L2 Trransmitters The transmitters have been precalibrated. The calibration of the transmitters are veritìed by using pressure and temperature calibration kit. The foUowing pressures and temperatures are applied to verify the calibration. Transmitter 1 2 i 3 Pressure Transmitter 1 B ara 500/0 of max Ñlax o P transmitter o mEar 1250 mEar 2500 mBar Temperature l\1inimum 500/00fmax l\t1aximum I . i transml tter ¡ The minimum and maximum values are referred to the settings of the analogue sensors included in the TopFlow meter. The settings are found by entering the Parameter Setup menu through the TopFlow User Interface. The User Interface Software is further described in a separate Software ûperating Ivlanual for the T opFlovv meter. If the measured pressure or temperature for a transmitter are not vvithin 20/0 of the set pressure or temperature, the transmitter shall be recalibrated. It is also recommended that the pressure and temperature transmitters included in the T opFlow meter are included in the same maintenance programme that is used by the customer for Othtl similat tr~-t1smitters in the field. Q FlowSys TopFlow Multiphase Meter S ire Verification Test Procedure -- I j Revision: ---- - I Version: 00 - Page no. : 6 of 10 202 l\-lECHANJICAL JP> AR1'§ The objective of this check is to verified that the dimensions of the TopFlovv meter have not been changed due to erosion or that a layers of any kinds are not being build up inside the T opFlo\v meter. The T opFlow meter is visually inspected after the meter is taken out of the line. If a layer of any kind has been build up inside the Top Flow meter an estimate (within ±0,5mm) of the thickness of the layer shall be made and reported. Dimensions that are being used by the TopFlovv meter in the calculation of flow rates are being measured. The physical dimensions of the Top Flow meter that are being measured are: 13 Venturi throat inner diameter (E-F). (j Upstream pipe inner diameter (G-H). !! Downstream pipe inner diameter (C-D). The measured dimensions shall be within the tolerances given in the mechanical drawings of the T opFlow meter that is being tested. If any of the dimensions have changed and are outside the tolerances given in the drawings, the dimensions must be updated in the T opFlow software. The dimensions are updated through the Parameter Setup menu in the User Interface of the TopFlow meter. The Geometry menu can only be accessed by operators authorised to logon as Service. The dimensions measured are clearified in the sketch belovV': I I C - - - - - - - - - =-=-- - - - - - - - - - - - - - - - - - - - ' D \ / E -------------------------------F I \ G -------------------------------H I I 1f- FlowSys TopF1ow Multiphase Meter Site Verification Test Procedure - - - --- -- I Version: I Revision : -- , 00 - Page no. : 7 of 10 203 CAP ACKT ANCE AN]!) CONDUCTANCE SENSOR The capacitance and conductance sensors are verified individually through static checks. The procedure is only performed for the fluids available at the site. 2.301 Capacitance sensor The multi phase flo\v meter is placed vertically and a blind flange including a tapping point mounted at the bottom of the meter. I I -...., IVlultiphase meter .-/ Blind flange ... ~ ~ Tapping point The meter is in turn filled with varoius liquids of known permittivity and the capacitance is read from the user interface of the multiphase meter. The meter is first filled with the liquid of low"est permittivity and the liquid of highest permittivity is the last fluid added to the meter, Fluids used: Fluid Theoretical i I Permitti vi ty Empty pipe 1,0 Diesel i 2,15-2,25 ¡ The temperature of the diesel and the temperature of the meter shall be within ±2°C. The temperature of the meter is read from the user interface. Calibration sequence: 1. Record the temperature of the diesel and read the temperature of the sensor through the user interface. 2. The meter is empty. Record the measured permittivity from the user interface. '"'\ Close the buttom valve and fill the meter with Diesel. j. 4. Wait 5 minutes for small bubbles to float to the top, 5. Record the measured permittivity from the user interface. 1f FlowSys TopFlow MuItiphase Meter ~ Site Verification Test Procedure - I Version: I Revision: ~ - 00 - Page no, : 8 of 10 6. Open the tapping point and drain the liquid from the meter. The measured permittivity is read from the user interface of the TopFlow meter. It is required to logon as Service to vie"v the measured permittivity. The User Interface Software is described in detail in the Software Operating Manual of the T opFlow l\Ifultiphase l\Jfeter. The acceptable limits for the measurements obtained during the static check is shown below, I Minimum Ivlaximum Empty ! 0,98 1,02 pIpe Diesel 2,1 2,35 Table Acceptable limits for static checks. 203.2 Conductance senso¡r The multi phase flow meter is placed vertically and a blind flange including a tapping point is mounted at the bottom of the meter. I I ~ l\1ultiphase meter ~ Blind flange ~ ~ <: Tapping point The meter is first filled \vith the mixture of lowest salinity and the liquid of highest salinity is the last fluid added to the meter. The measurements are filled into a Conductance Calibration Sheet. The following mixtures are added to the meter: i lVIixture # I Salt content Mixture 1 I 6g/1 IvIixture 2 50 g/l Mixture 3 1 00 g/l Table 1 tv'lixtures for Conductance Verification The temperature of the mixtures and the temperature of the meter shall be within ±2°C. The temperature of the meter is read from the user interfac.e.. '~!f c -- -- FlowSys TopFlow Multiphase Meter '.J Site ':¡,l~rifica.tion Test Pr.<}c~durç cc__ , Version : , Revision : '--- 00 - Page no. : 9 of 10 Verification sequence: 1. Record the temperature of the mixture and read the temperature of the sensor through the user interface. 2. Close the buttom valve and fill the meter \-vith lVlixture 1. "" \Vait 5 minutes for small bubbles to float to the top and for any -'. temperature effects to be minimum. 4. Record the measured salinity from the User Interface (requires logon as Service ). 5. Open the tapping point and drain the liquid from the meter. 6. Repeat step 2 through 5 with the other mixtures. I t is verified that the measured salt content is measured vvithin ±3 % of the salt content of the saline water solution. The measured salinity is read from the user interface of the TopFlow meter. It is required to logon as Service to vieV\r the measured salinity. The User Interface Soft\Nare is described in detail in the Software Operating Nlanual of the TopFlo\v Ñlultiphase Nleter. 1f FlowSys TopFlow MuJriphase Meter 1 Site Verification Test Procedure '''"'-' Version : j Revision : '--/ 00 - Page no. : 10 of 10 204 TOPIFLOW PJERFORlVIANCE If available~ a flow test can be performed at a multiphase test facility. The flow test is described in Section 1.4 of the FAT Test Procedure for the TopFlow meter. 3 CORRECTIVE ACTIONS Tests and verifications that are not vvithin acceptable limits shall be and corrective actions vvill be proposed. 4 SITE VERIFICATION REPORT A Site Verification report shall be made. ~ 'f' FlowSys TopFlow Multiphase Meter la Site Verification Test Procedure #6 ') 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 PUBLIC HEARING 3 4 In Re: ) ~/IIED ) 5 Guidelines for Qualification of Multiphase) Metering Systems for Well Testing ) ~ !þ-' 6 ) -"t4t '" " 7 Att.j'Qa". r~ r ~ ~ 8 TRANSCRIPT OF PROCEEDINGS 9 Anchorage, Alaska January 11, 2005 10 9:00 o'clock a.m. 11 12 COMMISSIONERS: 13 JOHN NORMAN, Chairperson 14 DAN SEAMOUNT 15 16 17 18 * * * * 19 20 21 22 23 24 25 METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 - X - - ^ - - ). Anchorage, Alaska 99501 (907) 276-3876 ORIGINAL ;¡¡¡¡¡¡;rìr,':~~ v -~ ) ) 1 TABLE OF CONTENTS 2 3 OPENING REMARKS BY CHAIRPERSON NORMAN Page 3 4 TESTIMONY OF JANE WILLIAMSON Page 5 5 DISCUSSION Pages 7 - 20 6 END OF PROCEEDINGS Page 21 7 8 9 * * * * 10 11 I 12 I 13 14 15 16 17 18 19 20 21 22 23 24 25 METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) ') 3 1 PRO C E E DIN G S 2 (On record) 3 CHAIR NORMAN: I'll call this hearing to 4 order. This is a hearing before the Alaska Oil and Gas 5 Conversation Commission being held on the morning of Tuesday, 6 January 11th, the hour is 9:05 a.m. Notice of this hearing 7' was duly published in the Anchorage Daily News. The date of 8 publication was December 2nd, and additionally notice of this 9 hearing was sent out to all persons who have registered on the 10 AOGCC's distribution list for receipt of official 11 I publications. 12 I The purpose this hearing is to consider rules 13 governing the use of multiphase metering for well testing and 14 allocation of production within all pools within the Colville 15 River, Endicott, Kuparuk River, Milne Point, North Star, and 16 Prudhoe Bay fields. The Commission has initiated this hearing 17 on its own motion; the purpose being as indicated to regulate 18 the use of multiphase metering for well testing in the 19 designated fields. 20 Any persons that have not previously received a copy 21 of the Commission guidelines that have been developed may do 22 so now or at any point in the hearing. Any persons present 23 who may require special accommodations, either for hearing or 24 other matters, likewise, please see the Commission Special 25 Assistant, Jodi Colombie, and we will do our very best to METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) ) 4 I 1 accommodate you so that you can participate meaningfully in 2 the hearing. 3 I have before me an affidavit of the publication 4 showing that the publication occurred on the 6th of December, 5 2004, and the hearing today will be conducted in accordance 6 with the normal rules of the Alaska Oil and Gas Conservation 7 Commission. A transcript of the hearing will be prepared and 8 available for review by any persons desiring same. With us 9 today is Sharon Wilcox of Metro Court Reporting who will act 10 as the court reporter. Unless there is a reason to do so we 11 will not plan to swear witnesses today, but we will accept 12 oral testimony from any persons, as well as any additional 13 written comments that may be offered into the record. 14 I'll begin the hearing by calling upon -- well, first 15 of all I will also introduce Commissioner Dan Seamount, seated 16 to my left, and my name is John Norman, Chairman of the 17 Commission. A quorum is present so we do have a legally 18 constituted meeting. Commissioner Seamount, before we proceed 19 do you have any comments? 20 COMMISSIONER SEAMOUNT: No, I don't, Mr. 21 Chairman. 22 CHAIR NORMAN: Then I will call upon 23 Commission engineer Jane Williamson to offer a statement in 24 the record concerning the purpose of these multi-phase 25 metering guidelines and what the Commission proposes to METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) 5 1 accomplish by adopting them. Ms. Williamson. 2 TESTIMONY BY JANE WILLIAMSON 3 MS. WILLIAMSON: The staff here recommends the 4 adoption of the guidelines for qualification of multi-phased 5 metering for well testing and this is dated November 30th, 6 2004, for use of multiphase meters in well testing on the 7 North Slope. And we're looking at this for a trial period of, 81 I would say, two to three years use. I want to go over what 9 our authority is, what the purposes are of well testing, what 10 are multiphase meters, why are we considering these - - this 11 technology, the purpose of the guidelines, and also the -- how 12 these guidelines were created and what our final proposal and 13 implementation would be. By statute and regulations we have 14 authority over well testing in Alaska. Also, we require as a 15 minimum one well test per month and in some pools we require 16 two well tests per month. 17 Well tests are used for production management and 18 allocation of production. On the North Slope all the major 19 fields have several oil pools producing into common 20 facilities. Now, these pools aren't separately measured 211 through LACT meters. Rather the full field is measured I I 22 I through LACT meters so well production and pool production is I allocated back through well Because you have separate 23 ¡ tests. I 24 ¡ pools with potentially separate ownership and separate tax 25 II treatment, it is quite important that we have - - insure ,I il !\ I: JWETRO COURT REPORTING 'I 745 West Fourth Avenue, Suite 425 Ii Anchorage, Alaska 99501 II (907) 276-3876 ) ') 6 1 accuracy on the well test metering. 2 Now, currently no well test can guarantee accuracy 3 within a LACT meter quality. So, again, it has to be 4 allocated back and it's roughly you can get plus or minus five 5 percent on the accuracy with normal well testing. Now, 6 multiphase metering technology is a little bit different from 7 conventional technology in well testing. Conventional 8 technology separates out gas from the fluids and separately 91 meters the gas from the total fluids, and sometimes water and 10 oil are also separated. This is because the typical metering 11 that you have out there is not accurate when you have gas, any 12 significant gas within the fluids and vice versa, fluids in 13 the gas. 14 Well, there's new technology that would allow metering 15 without full separation of that gas and that's what we're 16 looking into now. There are no standards out there for 17 multiphase meters so what we decided is that we needed to look 18 at this on how we would implement allowing multiphase meters 19 to be used in Alaska. 20 Now, this -- we started this process early in 2004, 21 some of the owners at Prudhoe Bay Unit carne to us saying that 22 they had done some tests, multiphase metering, and that they 23 might be corning to us with applications for their use and they 24 wanted to know what we were going to require. We. . . . . 25 CHAIR NORMAN: I'm sorry, what year was that? METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) I 7 1 MS. WILLIAMSON: That was 2004, that was I 21 believe that was February or March time frame. We hired a -- 3 an expert consultant, his name is Parve Medesaday (ph) , to 4 help us with setting up some protocol for this and also to 51 provide some - - a tutorial on what multiphase meters are and what needs to be considered. together initial 6 We put 7 guidelines in May, initial drafts in May, submitted it to all 8 the operators in Alaska, as well as vendors, other federal and 9 state agencies, and others even outside of Alaska that are ex- 10 -- have expertise in multiphase meters. We've had several - - 11 a couple meetings revising these and we've incorporated I 12 believe everybodys comments into these guidelines. 13 I have with -- that I wish to put into the record, two 14 letters, one from ConocoPhillips and one from Exxon that takes 15 no exception to the use of the guidelines and also comments on 16 that it is a thorough process that we went through and it's - - 17 lays out our requirements well. 18 As far as our future, we want - - it's early to try to 19 put these into regulations, we need to test these out and make 20 sure it works, and so I'm recommending two to three years of a 21 trial period. In that period of time we may find that they 22 I are ready to go into regulations, and I believe that's it. Do I 23 ! you have any questions? I, 2411 CHAIR NORMAN: Let's take the letters first if 2511 you don't mind. II ,I II II METRO COURT REPORTING 'I 745 West Fourth Avenue, Suite 425 ¡, Anchorage, Alaska 99501 (907) 276-3876 ) ) 8 1 MS. WILLIAMSON: Okay. 2 CHAIR NORMAN: Can you briefly identify each 3 letter and then we'll ask the court reporter to mark them so 4 that they can be attached..... 5' MS. WILLIAMSON: Sure. I 6 CHAIR NORMAN: I believe you mentioned one 7 letter from ConocoPhillips and a second from Exxon. 8 MS. WILLIAMSON: Yeah, I - - the first is an e- 9 mail letter, it is from Mike Hanus dated January 7th and he -- 10 he's with Exxon, so he was representing Exxon on these 11 guidelines. The second..... 12 CHAIR NORMAN: And the letter -- the letter, 13 I of course, will speak for itself, but. . . . . 14 MS. WILLIAMSON: Yeah. 15 CHAIR NORMAN: .... .for clarity, the letter is 16 supportive or does the letter make any suggestions..... 17 MS. WILLIAMSON: It takes no exception to them 18 being implemented and it says that they're thorough in regards 19 to application requirements. They did say the ability to meet 20 accuracy expectations would be a challenge but that's 21 something we'll work through within this trial period. Again, 22 they felt it was good we were looking at it on a trial period 23 before going into regulations. They're asking to be kept 24 informed. 25 CHAIR NORMAN: Okay. Then if you don't mind i1fETRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) ') 9 1 if you'll have me that to keep our records straight we will 2 ask that that be identified as our first attachment to the 3 transcript. 4 MS. WILLIAMSON: The second one is from 51 ConocoPhillips, Mike Wheatall, dated January 11th. CHAIR NORMAN: Neatall? 6 7 MS. WILLIAMSON: Wheatall. 8 CHAIR NORMAN: Wheatall. 9 MS. WILLIAMSON: W-h-e-a-t-a-l-l. They have 10 no objections to the issuance; they indicate that they're 11 appreciative of the technical participation that we stimulated 12 and that we allowed input from the -- the fact that we allowed 13 input from all these different agencies and companies. And 14 they feel that it will provide a productive basis for a 15 discussion for multiphase meters in the future. 16 CHAIR NORMAN: Very good, and if you don't 17 mind again, if you'll have me that we'll keep the record 18 straight. 19 MS. WILLIAMSON: And otherwise, we've had no 20 objections that have been submitted to the Commission. 21 CHAIR NORMAN: Commissioner Seamount, any I . 221 questlons? 23 I COMMISSIONER SEAMOUNT: I have a few. You II 24 II mentioned that conventional meters are -- have plus or minus Ii 251 five percent accuracy. I I METRO COURT REPORTING il 745 West Fourth Avenue, Suite 425 !I Anchorage, Alaska 99501 II (907) 276-3876 ) 10 1 I 11 MS. WILLIAMSON: In total. Each individual 2 piece of the metering can be within plus or minus I believe 3 it IS one to two percent I but when you add up the total systeml 4 it can -- you can have an uncertaintYI I shouldn/t say 5 inaccuracy I an uncertainty of in the three to five percent 6 range. I 71 COMMISSIONER SEAMOUNT: Okay. You might have 8 missed this or I might have missed this and you might have 9 said itl but how -- what does it look like the multiphase 10 meters compare to the conventional? 11 MS. WILLIAMSON: It -- what we/re requiring is 12 it to be within five percent of - - in comparison to the 13 reference equipment that/s being used so it would be compared 14 to test separators for instance. However I we have a broad 15 range of criteria where we can loosen that a bit and in the 16 event that - - for instance if this is the only way that you/re 17 going to get a development goingl which is the case in some 18 places in the Gulf of Mexicol you may be willing to decrease 19 that accuracy expectation. There/s several things that could 20 come into play there. 21 COMMISSIONER SEAMOUNT: Increase the 22 expectation of accuracy..... 23 MS. WILLIAMSON: To say plus or minus 10 241' percent uncertainty. 25 ¡I COMMISSIONER SEAMOUNT: And this will apply to II !i METRO COURT REPORTING !! 745 West Fourth Avenue, Suite 425 ! Anchorage, Alaska 99501 ¡ (907) 276-3876 ) ') 11 1 all the pools or do different pools have different ranges of 2 accuracy or sensitivity? 3 MS. WILLIAMSON: That would be all the pools. 4 COMMISSIONER SEAMOUNT: So like North Star 5 would have the same accuracy with multiphase metering as the 6 Prudhoe Bay oil pool? 7 MS. WILLIAMSON: And it -- yes, and again 8 though, when a company applies for that multiphase metering, 9 they would provide the justification for the use of the 10 meters, they would provide information on the accuracy that's 11 expected and if they're asking for an exception to that 12 accuracy, then we would evaluate that. 13 COMMISSIONER SEAMOUNT: Okay. During this two 14 to three year trial period, will these meters be used as 15 official meters? 16 MS. WILLIAMSON: It will be in the same manner 17 as well testing, it would be allowed for -- this would be, 18 , these applications would be for allowance of the use of them 19 in an allocation system so, yes, they are official for 20 I allocation of production. 21 COMMISSIONER SEAMOUNT: And what criteria will I I be used to approve the use of these after -- what's 22 i I mean, I I 23 II the criteria for multiphase metering passing the test within 24 !\ the two to three year period? Is it just accuracy or is it - - II 25 II I gu e s s . . . . . Ii I I I' METRO COURT REPORTING ,I 745 West Fourth Avenue, Suite 425 II Anchorage, Alaska 99501 II (907) 276-3876 ) 12 I 1 MS. WILLIAMSON: And reliability.. . . . 2 COMMISSIONER SEAMOUNT: And reliability. 3 MS. WILLIAMSON: And there would be - - have to 4 be maintenance and within our pool rules we'd likely have some 5 requirements for coming back to us with information as to how 6 they performed. 7 COMMISSIONER SEAMOUNT: And finally, while 8 you're going through this pre-hearing period looking at the - - 9 or what, this preliminary evaluation, the multiphase metering, 10 what were the references you used, I mean, who was involved in 11 determining the accuracy or testifying the accuracy? It 12 sounds like the Commission worked on it, the operators had 13 some input, Mr. Medis -- Medesaday (ph) ? 14 MS. WILLIAMSON: Medesaday. 15 COMMISSIONER SEAMOUNT: Medesaday and how much 16 did you rely on the manufacturers? 17 MS. WILLIAMSON: Okay. We did involve several 18 manufacturers in this and I must say that what we're 19 requesting on the accuracy is at the tighter range of that. 20 What we were told is yes, they can -- it's a challenge but 21 i they should be able to meet it. There are some, I have - - I 22 ! just heard yesterday that there is some concern from one of I 2311 the companies as to whether or not that might be a little bit :[ 2411 too tight. Again, I guess we erred on not making it too lose 25 II but rather allowing for a process by which you can expand that II !I Ii 'I METRO COURT REPORTING Ii II 745 West Fourth Avenue, Suite 425 !¡ Anchorage, Alaska 99501 I: (907) 276-3876 II ) ) 13 1 so - - does that make sense? 2 COMMISSIONER SEAMOUNT: Uh-huh (affirmative) , 3 okay. Thank you, Ms. Williamson, I have no further questions. 4 CHAIR NORMAN: I have just a few. In the 5 course of developing these guidelines and working them over, 6 has opposition to their use been expressed by any parties? 7 MS. WILLIAMSON: No, I haven't.. ... s! CHAIR NORMAN: Either formally or informally? 9 MS. WILLIAMSON: On an informal basis I should 10 say that yesterday I - - it's not opposition, a concern on 11 whether or not the accuracy requirements are too tight. It's 12 not - - and this was not official, it was one person from a 13 company. Otherwise, I've had no opposition and I should say 14 this was like just yesterday when I heard this so. . . . . 15 CHAIR NORMAN: So, that particular concern is 16 not addressed to that fact that it's inaccurate, it's that the 17 Commission is expecting too much out of multiphase metering? 18 MS. WILLIAMSON: Yes. 19 CHAIR NORMAN: Or may be expecting..... 20 MS. WILLIAMSON: Maybe. 21 CHAIR NORMAN: During the - - this test period 22 of I believe you said two to three years, will multiphase 23 . metering be operated in some cases parallel with conventional I I metering or is this replacing the conventional metering 24 :1 2511 entirely? II METRO COURT REPORTING Ii 745 West Fourth Avenue, Suite 425 II Anchorage, Alaska 99501 II (907) 276-3876 ) ) 14 1 MS. WILLIAMSON: There's no plans to go out 2 and replace all test separators, for instance, but I would 3 anticipate that there will be places where instead of test 4 separators, they will put multiphase meters in. I would also 5 expect that there will be more tests of meters in parallel 61 with a test separator to check their validity for use and 7 allocation purposes. 8 CHAIR NORMAN: Until - - I'm going to state my 9 understanding and then would appreciate it if you would 10 correct me if I'm wrong but, as long as these are adopted as 11 guidelines, that's what they will be as guidelines. How would 12 you suggest the Commission proceed if someone is not foll- - - 13 if an operator is not following the guidelines, what will be 14 the plan of the Commission? 15 MS. WILLIAMSON: Well, first of all, as it 16 would be set out, the operators would be required before using 17 these in an alloca- - - these multiphase meters in allocation 18 purposes, they have to come to us, otherwise they would not be 19 I in compliance. I mean, this is on the North Slope, so they 20 would not be compliance if they didn't come to us. Secondly, 21 they would have to be - - follow the requirements as far as 22 documentation of what they're going to do and then get our 23 approval for their use. As far as what we would do if they 24 weren't in compliance, I guess I'm not certain we would bring 25 it in front of the Commission, the staff would bring it to the METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 II ) ) 15 1 Commission for their determination. 2 CHAIR NORMAN: Sure, I understand that, I 3 appreciate that and I understand that we're somewhat plowing 4 new ground here. I would note for the record that in order to 5 be able to have tight enforceability, we're going to need to 6 progress to the regulation standpoint and that there are 7 constraints on agencies enforcing guidelines that haven't gone 8 through the full regulatory adoption process. But that's a 9 bridge we can cross as this unfolds. 10 A second question, where else - - in what other 11 jurisdictions right now is multiphase metering being utilized? 12 MS. WILLIAMSON: The major area where this was 13 started was the North Sea and a second area is the Gulf of 141 Mexico, Venezuela has a lot of them. They are just kind of starting in the California area, in the heavy oil arena. In 15 16 some of these - - the technology started in areas where - - 17 offshore where in order to allow for testing of wells, they 18 wouldn't actually develop a pool because it's too small if you 19 required full testing, with a normal meter. So they tried to 20 determine and come up with the technology where they could 21 separately test this and then come up with, for instance, sub- 22 I sea multiphase meters. So, that was kind of the start of the I, 23 'I whole process. In the meantime, the technology has improved I 24 II as far as accuracy and now it's being considered in I, I' 25 II replacement of more conventional - - in a more conventional I, I. METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 I ) ) 16 1 manner. 2 CHAIR NORMAN: Insofar as standards are 3 concerned, you mentioned that currently there are none in 4 existence. What about the government of Norway, do they have I 5 a standard? 6 MS. WILLIAMSON: They do have a handbook of 7 multiphase metering that goes over the technology and some of 81 the expectations on that technology, as does Great Britain. 9 It is a little different from ours and these guidelines 10 ' provide a procedural mechanism on going through the - - getting I 11 multiphase meters approved so the guidelines are more 12 procedural than theirs are. Theirs is more of a technical 13 evaluation. Again, though, they're not standards and nobodies 14 gone to the point of setting up standards for multiphase 15 metering. 16 CHAIR NORMAN: And MMS in the gulf how do they 17 -- what guidance does MMS offer to operators for use of 18 multiphase meters, if you know? 19 MS. WILLIAMSON: Well, I - - anything I say 20 would be hearsay so I'd rather - - I don't know that they've - - 21 I've gotten the impression from Parve that we are farther 22 along on this than they are so I - - and again, that's just 23 kind of hearsay. But MMS was involved here or did come to 24 some of our meetings as did BLM, and they showed no objection 25 to what we were doing. METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) ) 17 1 CHAIR NORMAN: In I believe all of the pools 2 fields where this will be - - these guidelines will be approved 3 for use, I'm guessing that the state of Alaska is the owner 4 there. Someone else may want to speak to this but my question 5 for you is have we had any communication from the state 6 about - - the states about calculation of the state's royalty 7 interest or measurement for revenue purposes, Department of 8 Revenue taxation? 9 MS. WILLIAMSON: The DNR, whose representative 10 is here today, verbally has stated to me that they don't have 11 any problem with it. DOR has not chosen to comment so -- so I 12 don't know. 13 CHAIR NORMAN: And I believe DOR has received 14 notice of these proceedings. . ... 15 MS. WILLIAMSON: They certainly have. 16 CHAIR NORMAN: Okay. They're aware of it. 17 I Are there any parties that may be affected by this that have I 181 not received notice to your knowledge? 19 II MS. WILLIAMSON: Not to my knowledge. 20 ,I CHAIR NORMAN: As the Commission monitors 211 multiphase metering, during this trial period, what would you I 22 ! see as a next step, when would you see taking a look at the I 23 ¡I experience level, what period of time, six months, 12 months? 24 I! MS. WILLIAMSON: Well, first of all, we need a II I, I: 25'1 couple at least, two to three applications to go through and I: II Ii II METRO COURT REPORTING Ii 745 West Fourth Avenue, Suite 425 .\ Anchorage, Alaska 99501 Ii (907) 276-3876 ) 18 1 see whether or not the application process is going to work. 2· Then beyond that performance is going to be a key area and ! I 3 we'll want to look at that so I would say you'd want to have 4 some of these installed and working for about six months. 5 Again, I think a - - certainly a three year period, we should 6 see whether or not it's going to be workable and if it - - if 7 we need to extend it, we can do so. 8 CHAIR NORMAN: And if you can in basic terms, 9 tell me how you would approach gauging reliability against 10 what measure would you gauge it? You're going to get a 11 reading on the - - out of multiphase metering, but how are you 12 going to know within what..... 13 MS. WILLIAMSON: Whether or not it's 14 reliable.. . .. 15 CHAIR NORMAN: .. . . . tolerances -- yes. 16 MS. WILLIAMSON: .... . long term? There are - - 17 I will be requirements on and going through and testing the 18 I meters, not necessarily against the test separator, but to - - I I 19 · there are tests that can be done on this - - on separate pieces 20 of the meters to ensure that it's still reading at the same 21 levels that it was before, so we'll be looking at that. We 22 will also be looking at - - and I don't know if this will make 23 much difference but see whether or not there's anything 24 strange going on with tests over time. Are you seeing a lot 25 of variation in tests that you wouldn't expect? So, we'll be METRO COURT REPORTING 745 West FQurth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) ) 19 1 taking a look at that. Those are the major ways and then if 2 we see some real problems, we would go back to the operator 3 and ask them to give us information as far as what's some more 4 going on. 5, CHAIR NORMAN: In that monitoring process will 6 the AOGCC be relying upon operator reports or will AOGCC 7 inspectors have the capability to independently test this? 8 MS. WILLIAMSON: I think we would try to do 9 this through the reporting mechanism. Normally AOGCC 10 inspectors do not go to inspect test separation equipment. 1 11 I That's not to say they can't, you know, but they -- normally 12 we haven't done that at the Commission. 13 CHAIR NORMAN: We have a variety of reservoirs 14 that may begin to use this and my question's a general one but 15 to what extent can we rely upon differences in ownership to 16 cause working interest owners themselves to take an interest 17 in accuracy, if you follow what I'm saying. In other words, 18 for purposes of allocating production within a unit for 19 I example, that certainly is in the interests, that's something i 20 working interest owners pay attention to to make sure they're 21 getting their fair share. Within these test areas, will we Ii 22 :1 have that incentive for monitoring by parties with potentially 23 , differing interests to try to ensure accuracy? il Ii I 24 I MS. WILLIAMSON: I think so. On the North 25 Slope particularly at Prudhoe Bay and Kuparuk, we have a METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ') ') 20 1 process where at least once a year we get together to review 21 allocation and production. Within that process I would see 3 that we might take a look at multiphase meters in a separate 4 manner here, but in these allocation meetings, we have 5' representatives of DOR, DNR, AOGCC and the owners, so that's 6 everybody that would be affected by inaccuracies and 7 allocation. So, I see that we have that mechanism now and 8 this would be just incorporating that into the current 9 mechanism. 10 CHAIR NORMAN: Thank you. Commissioner 11 Seamount, do you have anything further of Ms. Williamson? 12 COMMISSIONER SEAMOUNT: No, I don't. 13 CHAIR NORMAN: Okay. Well, Ms. Williamson we 14 thank you very much for your testimony. You've stated things 15 very clearly and you've answered all our questions. I would 16 ask if you wouldn't mind that you remain here, you may stay 17 seated, and I'll see if there are any other parties present at 18 ' this hearing that wish to offer any testimony. Are there any 19 other persons present in the room who would like to testify? 20 Okay, the Chair does not see anyone asking for recognition so I 21 ! the Chair interprets that as no other persons wishing to offer 22 testimony. 23 I would like to thank you for all of your effort in 24 bringing this forward and I think it's a challenging project 25 and it's interesting to see Alaska pioneering in this endeavor METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) 21 1 and I'm sure that we'll be revisiting this subject 2 periodically as we all gain experience in it. I'll call once 3 more for the purposes of the record to see if there are any 4 other comments or any other persons wishing to say anything. 5 Again, the Chair notes that no other persons have requested to 6 testify. Commissioner Seamount, any final comments? 7 COMMISSIONER SEAMOUNT: None other than I 8 agree with your thanks of Ms. Williamson and the task force in 9 working on this project. 10 CHAIR NORMAN: Okay. Then, without objection, 11 we will adjourn and these proceedings are closed. 12 (Off record) 13 14 * * * END OF PROCEEDINGS * * * 15 16 17 18 I 19 20 21 i ! 22 I 23 Ii ¡ 24 25 METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ) 1 C E R T I FIe ATE 2 SUPERIOR COURT ) 3 ) ss . STATE OF ALASKA ) 4 5 I, Jerri Young, Notary Public in and for the State of Alaska, do hereby certify: 6 THAT the annexed and foregoing pages numbered 2 7 through 21 contain a full, true and correct transcript of the Public Hearing before the Alaska Oil and Gas Conservation 8 Commission, taken by Sharon Wilcox and transcribed by Jerri Young: 9 THAT the Transcript has been prepared at the request of 10 the Alaska Oil and Gas Conservation Commission, 333 West Seventh Avenue, Anchorage, Alaska, 11 DATED at Anchorage, Alaska this 24th day of January, 12 2005. 13 SIGNED AND CERTIFIED TO BY: 14 15 ~\\\\\\UUIIIII~ Cf~~~ ~~o~.~.~... ~ I 16 ;s ~ ... .. ~ Jerri Young . s~·· .. ~ ;:::~ l \>oR Y .... ~ Nota~ in and f. Alaska ::: ! " \.:: 17 = 1U: 0 ; (J : co: My Commission Expires: 11 03/07 = """): " if. , : ..:.c: - ~ Z ~'V : U)- ~ \. ~~ l qr.;::: 18 ~ .. . ""~ ~ ...... ...,.~~~ ~ ........".0 0 ~ ~ · State ~ 19 111111I1n\\\\~ 20 21 22 23 24 25 AIETRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 v.. ) ConocoPhillips Alaska RE: Guidelines for Qualification of Multiphase Metering Systems for Well Testing January 11, 2005 John Norman Dan Seamount Commissioners Alaska Oil and Gas Conservation Commission (AOGCC) 333 W 7th Ave # 100 Anchorage, Alaska 99501-3539 ConocoPhillips Alaska, Inc. ("ConocoPhillips") has no objection to the issuance of the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" contained in the November 30,2004 draft posted on the AOGCC website to be considered at the January 11, 2005 hearing. ConocoPhillips appreciates the technical participation stimulated by the AOGCC among Operators, Service Companies, and Consultants, allowing input throughout the compilation of these draft Guidelines, These Guidelines will provide a productive basis for discussion as multiphase meters are introduced to North Slope operations. We look forward to further opportunities in assisting with revisions of these Guidelines, as experience is gained in multiphase"metering technology. Regards, 1m. )tV, W~ Mike Wheatall GKA Operations Manager cc: Paul Dubuisson Steve Kruse (r) Scott Fahrney Mark Ireland (r) Chirs Alonzo James Rodgers (r) Kenneth Martin Elizabeth Goudreau ; ConocoPhillìps Alaska. Inc, is a Subsidiary of Co no coP hill ips Petroleum Company ---0 -r ___u -- --- -- 0---------- --- - ._._u -'-r-- .., ) ') Subject: Re: Hearing Jan 11 - Adoption of:NIPM guidelines for North Slope Reservoirs From: rnike.hanus@exxonmobil.com Date: Fri, 07 Jan 2005 14:09:50 -0900 To: Mary Williamson <jane ~ wiIliamson@admin.state.ak.us> " " CC: sonny.rix@exxonmobil.com, "rob.g.dragnich@exxonmobîl.com, chàrles. s.luna@exxonmobi1.com, BradyJL@BP .com, ScottFahrney@conocophillips.com, roy.ck.meyer@exxonmobil.com, mike.j.n1ullally@.exxonrrlobil.com Mary, I have read the latest draft of the guidelines, and within ExxonMobil we do not take exception to them being implemented on a trial basis. Recognizing that the AOGCC has authorization over well test metering, the guidelines are thorough with regards to application requirements for getting a multi-phase metering system approved. The ability to meet the accuracy expectations in Section 3.2 will be a challenge, However, we recognize that the use of multi-phase meters is dependent on giving well test and production allocation results that are comparable or better than that which can be achieved with test separators. Before the AOGCC moves forward on adopting these guidelines into state-wide regulations, EM would like to have the opportunity to review and provide comments. I will not be attending the January 11 hearing, but please include me on correspondence on the hearing results. Sincerely, Mike Hanus ExxonMobil Mary Williamson <jane williamson@admin.s To: "Rodgers, James T" <James. T. Rodgers~~c:.onocophillips ..£S?m> , tate.ak,us> Scott.Fahrney@conocophillips.com, mike.hanus@exxonmobil.com cc: E?'?}~}:~.~h~h~.~.~gSJ..~h.':h?...~-9 ' BradyJL@BP.com Subject: Hearing Jan 11 - Adoption of MPM guidelines for North Slope 01/04/05 06:04 PM Reservoirs All, We will be holding a hearing on Jan. 11 at 9 am concerning adoption of our MPM meter guidelines for North Slope pools. It would be good to have on record whether the major owners of the North Slope fields support the use of the guidelines or if there are any concerns. Jerry Brady indicated that BP is planning to send a short letter in support. I was wondering if Exxon and Conoco-Phillips would consider doing the same? We anticipate that we'll adopt these guidelines for a trial period, and ultimately we'll propose adoption within the State-wide regulations, with revisions which result from this trial period. As we haven't received comments on this latest (Nov. 30) draft, I expect that 10f2 1/10/20055:31 PM ...,,_. .JI......"""_.............s.O u_....... .10..... ... ...""''"'.t''''...v........ 'J..L .....".......... ....."'.... b""'..L"-I.""'.&.J..J..J..'-i1.J .LV'" .1...V.i."'...... U1.VJ:-''-i ... ) ') there are no major concerns with the guidelines. Though we haven't received comments, Chairman Norman wants to hold the hearing anyway as these may ultimately be adopted within regulations. The gu i dl e i ne s are a v ail ab 1 e on 1 i ne a t ,::V~J.Y:..:u~g.9.~_C:;_.:,..?:.,~_~~l~,§._.:..9S?=v.::.lM~_~~_~g~~,~.9.~..~_.þ..~~ Please call if you have questions. Jane 20f2 1/10/2005 5:31 PM ) ) Recommendation to Adopt Multiphase Meter Guidelines in North Slope Pool Rules Recommendation AOGCC staff recommends adoption of the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" dated November 30, 2004, for use of multiphase meters for well testing for all North Slope pools. Commission Authority By Statute (Title 31, Sec. 31.05.030(d)(6» and regulation (20AAC25.230), oil, gas, and water production from Alaska wells must be measured using techniques and equipment acceptable to the Commission as accurate and reliable (20AAC25.230). By regulation, the Commission requires well tests to be conducted a minimum of once per month. By conservation ordesr, two well tests per month are required in many North Slope pools to provide quality assurance in production allocation. Purpose orWell Tests Well tests are an important component in reservoir management and allocation of production to pools. Production from many of the Alaska re~ervoir pools is commingled on the surface and processed using common facilities serving several pools within a field. Total field sales volumes of oil and gas are continuously monitored using custody transfer metering systems, generally referred to as LACT meters. LACT meters are required by regulation to provide accurate measurement to +/-0.25%. Because the pools do not have dedicated processing facilities and pool sales volumes are not separately measured through LACT meters, production volumes must be allocated back to wells on the basis of well tests, and then to the pools on the basis of comparison of the total sales volume to the summation of all well production estimated through well tests. Figure 1 is a simplified flow diagram illustrating the typical flow and allocation metering in a North Slope field where production from multiple pools is commingled. No well test equipment can guarantee accuracy to the requirements of the LACT meters, and wells are not continuously monitored, further causing uncertainty in production allocation. Often pools within the same field will have differing working interest, royalty interest, or severance tax treatment. Inaccuracies in well tests will cause errors within the final reported production of a pool, potentially affecting revenue of parties. It is therefore essential that the equipment and methodology for production allocation provide for accurate measurement. MuItiphase Meterin2 Technolo2V Multiphase meters (MPMs) appear to be a promising substitution for conventional test separator based well test systems, With multiphase metering, full separation of fluids is not required. Alaska faces very high capital costs for new developments, and MPMs may play a part in decreasing these costs, decreasing facility footprint and perhaps improve allocation of production. BP Exploration (Alaska), Inc. (BPXA) and ConocoPhillips Alaska, Inc. have conducted field trials of a number of commercially available MPMs in Prudhoe Bay Unit and Kuparuk River Unit pools to assess their effectiveness in current operations as well as for future asset developments. January 11, 2005 Page 1 of3 Recommendation to Adopt Multiphase } Guidelines in North Slope Pool Rules ) Multiphase metering is a relatively new technology. Industry standards and recommended practices are in place for 2-phase or 3-phase test separator based systems. However, no standards and few guidelines have been published for multiphase meters. Purpose of Guidelines Considering that the multiphase metering technology is relatively new and that accurate well test metering has both financial and reservoir management importance, AOGCC initiated a project to understand multiphase metering technology and prepare for its application to well testing. With industry input, "Guidelines for Qualification of Multiphase metering Systems for Well Testing", were prepared to direct the operator and AOGCC personnel on how to qualify these new measurement techniques and to provide a consistent process for the evaluation of the proposed metering systems. We believe that with consistent processes, the overall effort and time to prepare and process applications will be reduced, while assuring sufficient accuracy is maintained. Custody transfer applications are regulated separately and are outside the scope of the guidelines. Content of Guidelines Two documents were prepared to provide a consistant process for preparation and review of applications for use of MPMs, and to provide basic education to the layman on the principles of multiphase measurment. The first document, "Guidelines for Qualification of Multiphase metering Systems for Well Testing" (November 30, 2004) is the governing regulatory document and "Principles of Multiphase Measurements" (November 30, 2004) provides basic information concerning the technology, a list of references for further education, and a list of terms and definitions. The guidelines describe the AOGCC administrative process for review and ruling upon application for MPM installation, requirements for meter performance and documentation to be submitted within the application, and recommendation for the conduct for field tests, if required. Process of Guidelines Development In the development of these guidelines emphasis was placed upon ensuring adequate review be afforded to industry. The effort towards development of the guidelines began in early 2004, with an initial draft submitted in May 2004 to all Alaska operators, vendors of MPMs, other state and federal agencies, and industry experts involved in multiphase metering and well testing. The guidelines were revised to incorporate subsequent comments received. A second draft was then distributed and final guidelines incorporating industry comments were published in November 2004. The Alaskan petroleum industry has shown support and substantial involvement in the development of the guidelines. Proposal for Application of Guidelines In the near future, the AOGCC anticipates applications for use ofMPMs in North Slope fields. We wish to test the workability of these guidelines in the coming year or two. We may then recommend adoption of the guidelines within the statewide regulations, with revisions as needed based on the initial applications in the North Slope Fields. January 11, 2005 Page 2 of3 #5 . ) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Guidelines for Multi-phase Metering January 11, 2005 9:00 AM NAME - AFFILIATION ADDRESS/PHONE NUMBER TESTIFY (Yes or No) (PLEASE PRINT) ¿>/ 6~/ ç~ Ap</~~c),,;;/~~S~/Ç'07 ¿Cr&820 /V6 /\<J., JfyYtr. S' 1G.~ ç WY7ù{OfA; il If; J 76 7 -t S-c¡- 7ZZ(, ;Jo o Ci.¿p ~{-~ k~u:--- 11'?-l~)'L- ¡Jó TÓAvJ!JJ~, /tMJ a~ ( 7J¥3 - léQ~ Y"4- #4 Re: [Fwd: Re: [Fwd: Scheduled Hearing· "'undry Exemptions]] ) ) Subject: Re: [Fwd: Re: [Fwd: Scheduled Hearing on Sundry Exemptions]] From: Thomas Maunder <tom _maunder@admin.state.akus> Date: Thu, 06Jan 2005 14:37:31 -0900 To: John Norman <john_norman(@admin.state.akus> CC: John D Hartz <jack_hartz@admin.state.akus>~ Dan T <dan_seamount@admin.state.ak.us>, Jody J Colombie I have been working on them to be ready and will send them to Rob. Tom John Norman wrote: Jack and Tom-as you know we left the record open until January 19. Can you begin preparation of the amended orders so we will be ready to issue them as soon as the record has closed? Rob should of course review all final drafts. Thanks John -------- Original Message -------- Subject:Re: [Fwd: Scheduled Hearing on Sundry Exemptions] Date: Wed, 29 Dec 2004 15 :31: 16 -0900 From:John Hartz <jack hartz(â¿admin.state.ak.us> Organization:State of Alaska To:Rob Mintz <robert mintz(â¿law.state.akus> CC:tom nlaunder(â¿admin.state.ak.us, dan seamount(â¿admin. state. ak.us, john norman(â¿admin.state.ak.us, steve davies(â¿admin.state.ak.us References:<s 1 d2b4d8.054(â¿smtpa.law.state.akus> See my comments below. jack Rob Mintz wrote: Two issues. As to AOGA "involvement in final wording" of the order coming out of the current proceeding, my view is that AOGA's further input should be in the form of written comments or oral comments at the hearing, and not through additional informal contact. Therefore, AOGA should probably be told that if they have anything further to contribute it should be at the hearing, and the hearing should therefore be held unless AOGA says it declines. As to inclusion of service wells in the matrix, my understanding is that the matrix that came out of the series of workgroup meetings was intended to reflect ( 1 ) desired changes in Commission policy regarding development wells and (2) current Commission policy regarding injection wells. Once the Commission issues its order regarding development wells, the matrix will reflect current policy regarding both development wells and service wells. As such, a combined matrix would not need to be adopted by an order if the purpose is simply to serve as a convenient guide to Commission requirements. In fact, anyone cou~d read the app~icab~e Commission regu~a tions and orders and come up wi th his or her own matrix for tha t purpose. 10f3 1/6/2005 4:30 PM Re: [Fwd: Re: [Fwd: Scheduled Hearing ( "'undry Exemptions]] ) ) Rob - the last sentence is not correct - 20AAC25.280 lists generic type workovers, however, there are 10's to 100's of operations that can be done that may fit within some of the generic categories. The matrix is a convenient way to aid the operator to understand which "workovers" are important or have meaning to AOGCC. The objective is to ensure compliance with the spirit of the regulation. -- jdh If I recall correctly, the reason a development well matrix was proposed to be added to the order currently under consideration was to eliminate any uncertainty as to whether the specifics in the matrix correctly interpret the general rules otherwise stated in the conservation orders. So under the new order, the matrix wil be not just a convenient guide but also a set of rules with independent and direct legal effect with regard to develoment wells. If rules in the form of a ma trix wi th independent and direct legal effect are also desired for injection wells, a new proposal will have to be published and opportunity for hearing provided, because that is well beyond the scope of what was previously noticed. The notice specified 20AAC25.280 which is applicable to injectors also. Doesn't it follow that if something comes out of the hearing or documents submitted in response to the notice can be taken into consideration when drafting the rules or inclusion of a second matrix? I believe sometimes we should broaden our view to make our efforts more efficient - i.e., resist the bureaucratic impulse. -- jdh Thomas Maunder <tom maunder@admin.state.ak.us> 12/29/2004 12:27:23 PM »> I guess it would be nice if I copied you on the message if I am going to ask you a question. Tom -------- Original Message -------- Subject: Scheduled Hearing on Sundry Exemptions Date: Wed, 29 Dee 2004 11:57:34 -0900 From: Thomas Maunder <tom maunder@admin.state.ak.us> Organization: State of Alaska To: John Norman <john norman@admin.state.ak.us>, Daniel T Seamount JR <dan seamount@admin.state.ak.us>, Steve Davies <steve davies@admin.state.ak.us>, John D Hartz <jack hartz@admin.state.ak.us> All, The hearing for the sundry exemption orders is scheduled for Tuesday. Linda has asked me if there would be a hearing. The purpose of this message is to offer a review of the matter so that the need for a hearing can be determined. 20f3 1/6/2005 4:30 PM Re: [Fwd: Re: [Fwd: Scheduled Hearing Î -"mdry Exemptions]] ') There has not been any request for a hearing. The operators through AOGA did submit a comment letter supporting the effort, requesting they be involved in the final wording and requesting that an injection well matrix be included. Rob and I spoke regarding their request to be involved in the final wording and his opinion was that their involvement is limited to what has happened in the prior meetings of the workgroup and their comments. Final wording of the orders will be at the Commission's discretion. We also briefly discussed including an injection well matrix. With regard to including the injection well matrix, originally there was a combined matrix and prior to the notice Rob had me split it in two with one for development (production) wells and one for service (injection) wells. The notice only addressed development wells. Expanding to include service wells too should not entail much work, however I do not know how the process is effected. Does the notice limit the scope of the action or does the comment from AOGA afford the Commission the opportunity to include service wells too? If the hearing were to be held, do we consider AOGA's letter as a request to expand the coverage?? If the scope of the notice trumps everything, then there is no need for a hearing. If it is possible to consider AOGA's request to include an injection well matrix, then the hearing should be held so that matter can be considered and a determination be made to broaden the coverage to injection wells. Rob, for the benefit of all what is your opinion. Tom 30f3 1/6/2005 4:30 PM #3 Re: [Fwd: Multi-phase Metering] \ ¡I I/O ~ v¡ aWl ) o~ Subject: Re: [Fwd: Multi-phase Metering] From: John Norman <john_norman@admin.state.ak.us> Date: Thu, 23 Dee 2004 13:37:22 -0900 To: lVlary Williamson <jane _ \villiamson:ª)admin.state.ak.us> CC: Dan T Seamount <dan_seamount@l.admin.state.ak.us>, Jody J Colombie <jody_eolombie(~admin.state.ak.us>, John D Hartz <jack_hartzl'@admin.state.ak.us> Jane-Jody-because these guidelines will have application to many operators, we should hold the hearing at the appointed time, just as we did with the BOPE regulation change. Jane, you should be prepared to make a statement for the record concerning the background leading up to the final guidelines, the intent of these guidelines, and the fact that at some point in the future the Commission may contemplate adopting these as regulations. Jody- we will want to make a record of this hearing. Thanks, John Mary Williamson wrote: Yes, that's the hearing. However, we've had no request for hearing and no comments back on the last draft, so I expect I'll recommend vacating. John Nonnan wrote: Jane, do I need to plan to attend this? -------- Original Message -------- Subject:Multi-phase Metering Date:Tue, 30 Nov 2004 15:29:05 -0900 From:.i ody eolombie(â)admin. state.ak. us Reply- To:.iody colombie(â)admin.state.ak.us To:winton aubert(â)admin.state.ak.us, bob crandall(â)admin.state.ak.us, jolm norman~admin.state.ak.us, dan seamount(â)admin.state.ak.us, j ane willian1son(â)admin.state.ak. us The following meeting has been added to your Agenda. Proposed by:Jody Colombie Access level: Normal Importance level: Normal Subject: Multi-phase Metering Tuesday, January 11, 2005 Time: 9:00 am to 12:00 pm (NAST9NADT) Location: Hearing Room ii John K. Norman <John Norman(â)admin.state.us> I! 10f2 1/3/2005 3 :44 PM Re: [Fwd: Multi-phase Metering] Commissioner Alaska Oil & Gas Conservation Commission 20f2 1/3/2005 3:44 PM #2 ST ATE OF ALASKA ) NOTICE TO PUBLISHEI ) ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO-02514026 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE. BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 Jody Colombie December 1, 2004 0 ilnchorage,AJ( 99501 PHONE PCN M - (907) 793 -1 ?? 1 DATES ADVERTISEMENT REQUIRED: T ilnchorage Daily News December 2, 2004 0 PO Box 149001 ilnchorage, AJ( 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement X Legal D Display D Classified DOther (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TOTAL OF PAGE 1 OF ALL PAGES$ TO Anchorage, AK 99501 2 PAGES REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LlC 1 05 02140100 73451 2 3 R:Q~" C~ DIVISION APPROVAL: ---Ä,- \ . -"-- .- \ ) ( ~ Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Rules governing use of multiphase meters for well testing and allocation of production within all pools within the Colville River, Endicott, Kuparuk River, Milne Point, Northstar, and Prudhoe Bay Fields The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to regulate the use of multi-phase meters for well testing and allocation of production within all pools within the Colville River, Endicott, Kuparuk River, Milne Point, Northstar, and Prudhoe Bay Fields. The proposed rules are set out in the document "Guidelines for Qualification of Multiphase Metering Systems for Well Testing", dated November 30, 2004, which may be inspected at the Commission's offices or on its website at www.aogcc.alaska.gov/MeterGuide.htm The Commission has tentatively set a consolidated public hearing on these proposed actions for January 11, 2005 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on December 17,2004. If a request for a hearing is not timely filed, the Commission will consider the issuance of orders without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit written comments regarding these proposed actions to 'the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on January 3, 2005, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on January 11, 2005, If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, t)e conta~mbie at 793-1221. Daniel T, Seamount, Jr. Commissioner Published Date: December 2,2004 ADN AO# 02514026 ) ) Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES#2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 360257 12/02/2004 02514026 STOF0330 $175.20 $175.20 $0.00 $0.00 $0.00 $0.00 $0.00 $175.20 STATE OF ALASKA Notice of Public H.earing STATE OF ALASKA THIRD JUDICIAL DISTRICT ''''~Alaska OilandGasConservation Commission . ., '¡:¿:é:' Rules governing use of multiphase m~ters for Teresita Peralta, bemg flrst duly sworn on oath deposes and says . well testing and allacQtion of p~oduc!lon that she is an advertising representative of the Anchorage within all pools withi~t~eC<?lv111e ~lverJ . . Endicott Kuparuk RwerJ Mlln.ePo\!1tJ Dally News, a dally newspaper. . ,..Northstar,andPrudho~ BayFu~lds , "The Alasko Oil and Gos Conservat,ìo'n Commis" That said newspaper has been approved by the Tlùrd Judicial sion (, CommiSSion"') on ils Qwn. motion, .Pfr~posel~ . . . 10 fegulol~ the use- of mulfl·pho,e meter. or we Court, Anchorage, Alaska, and it now and has been pubhshed m le."Iing ond ollocollon of pro0L!ction Nlln,n all ,?oolS h E 1" h 1 "11 d ·1' within Ine Co',,;\I;: R.'J~f EndlcúlT, Kup(rlJk ~lVer, t e ng IS anguage contmua y as a a1 y newspaper m 1\' Po nl NOfThstor, ond PrLldhoe Bov' Fields. Anchorage, Alaska, and it is now and during all said time was ~~~~ropl()."ed rLlleO) ore ."el aul '0 Ih~ ao_c~t~t · d . fi " , 1 "Guidelin"'''' for QLlolii,col,onotlV1ulllP 0."", e e . prmte ill an of ce mamtamed at the aforesaId p ace of ing SŸste'rñs.for Well Testing", dated Nove~be.r 3?, publication of said newspaper. That the annexed is a copy of an 2004,Which. maybe i,nspected at }he Comml~s\on s . . .. .. offices or on its we\:¡slte at: advertisement as It was pubhshed in regular lssues (and not m www.aOgcc.alas~a.göv/MeterGuide.htm supplemental form) of said newspaper on the above dates and Th~ (.;"T.rr.;;;;,.(.t,.): 1~,,.)livel'f!)eto~onsoli- that such newspaper was regularly distributed to its subscribers J",~.j 0...'[,1 ..: r.~ 'J' .f. J ".r. I r.~:~ proposed ClctIO~!1,s fO~ d· 11 f ·d . d Th h full f h f h d .1·:.("....),· Ii J,(I:, .]1 ., (11,1 'J('I. ..01 the Alaska I an urmg a 0 sal perlO. at t e amount 0 t e ee c arge ':.:J';, ':':"';';' ,,)1,,:.,·. ':.:"'r.ry',, " "Jr. at 333 W~st7th Av- for the foregoing Publication is not in excess of the rate charged ~ r".'~:u."'; 1').). .:. (.,: r.,:.r:,)9~, "Ias~a 99501...-'tPtd · ... son may request that the tentptlvelY,sc,,~ u e pflvate mdlvlduaIs. heòrÎngbe held bY fHingo written request with the CQ!nmissionno later than 4:30 pm on December 17, 2004. ..' , ~ 1(.) '';':''J.;;I (.:.,.) h,:-.')r;Ì1~is n.ot timelyfUed, the .. ..mrr',,:; ..:.f, .," I .:-:.r.: ..:I~ r the Issuance .of .orde~s ;,,011'.,.,,01 (' r.~or.r.~ ¡.:. I,;'J'" if the Commission will · ~ ~ If' V hO.ld',the,p,Ub li,C,',t:I.e...ar.ing/,ple,.,as.e,..,.call..7".9.,3-12~.1," SIgned 'f ß f/v{ ~\ n addition, a person may submit w~ltten com- ments regarding fhese propo~ed actlo~s ~o the Alaska Oil and Gas Conservation Commission at 333 West ithAvenueJ Suite 100/ 'Anchoragel. Alaska 5 . d d b h· d 99501 Written commènts must be received no ubscnbe an sworn to me efore t 15 ate: later than 4:30 pmonJanl.!,9r,y3, 2005,e.xcept ~hat · /\ if the Commission decides ,to hol~ a public h~armgl JII) . ¡ r written comlllent, s mus,t, be received no loter than · ,I)' Ý 9:00 om on January 1L 2005. :; /\v (r " . - -' . '-- - If you are a person 'with a disabilÌfv who may need speci.al accommoda~ions i~ order to com·, ment or .to attend the public hearing, please coo- bl"" d f S f 1 k tact Jodv Colombie at 793-1221- Notary Pu lC In an or the tate 0 A as a. Th' d D" ., A h Al k Daniel T. Seamount, Jr. l! IVlSIOn. nc orage, as a .1 '. J .. ' Commissioner ! : l¡ .) !');\ '7 ADN AO# 02514026 MY COMMISSION EXPIRES: /.1 d.c / ;''7: ~ t' / Publish: December 2, 2004 -" I . j I I' ,', ~ 1 ," ! , ¡ j': , j. I I' / 'j {i /) f, ¡ -, / 'I ' · ii H' j. '/. f I } " , " 'I' _ I ! ,.IM'h/\. "I t I j ... A, I I, ! ,'f '; " /0; .' J ¡ ,<} r.!.Lt.!í i ./} ',.i ,II. v\xj./ ì/ , ,'-"', ,/ //~ ! ß ~ . ,/ RE: Public Notice ) ) Subject: RE: Public Notice From: legalads <legalads@adn.com> Date: Wed, 01 Dec 2004 12:30:10 -0900 To: lody Colombie <jody_colombie@admin.state.ak.us> Hi Jody: Following is the confirmation information on your legal notice. Please let me know if you have any questions or need additional information. Account Number: STOF 0330 Legal Ad Number: 360257 Publication Date(s): December 2, 2004 Your Reference or PO#: 02514026 Cost of Legal Notice: $175.20 Additional Charges Web Link: E-Mail Link: Bolding: Total Cost to Place Legal Notice: $175.20 Your Legal Notice Will Appear On The Web: www.adn.com: XXXX Your Legal Notice Will Not Appear On The Web: www.adn.com: Thank You, Kim Kirby Anchorage Daily News Legal Classified Representative E-Mail: legalads@adn,com Phone: (907) 257-4296 Fax: (907) 279-8170 ---------- From: Jody Colombie Sent: Wednesday, December 1,2004 11 :33 AM To: legalads Subject: Public Notice «File: Ad Order form.doc»«File: multiphase notice.doc» 1 of 1 12/1/2004 1 :31 PM 02-902 (Rev. 3/94) Publi~.__. 1--1ginal Copies: Department Fiscal, Depar receiving AO.FRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO 02514026 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF · ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue, Suite 100 lody Colombie December 1, ?004 0 Anchorage, AK 99501 PHONE PCN M 907 -793-1221 (907) 793 -1 ?? 1 DATES ADVERTISEMENT REQUIRED: T Anchorage Daily News December 2, 2004 0 PO Box 149001 Anchorage, AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared A TT ACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, Notary public for state of My commission expires 02-901 (Rev. 3/94) AO.FRM Public Notice ) Subject: Public Notice From: lady Colombie <jody_colombie@admin.state.ak.us> Date: Wed, 01 Dec 2004 11:33:54 -0900 To: Legal Ads Anchorage Daily Ne\vs <legalads@adn.com> Order Content- Type: applicationlmsword Content-Encoding: base64 ....::::::::;:'( '. .1 Content-Type: applicationlmsword¡ : multIphase notIce.doc b 64 . 'Content-Encoding: ase ;J,._.,__.,.._.._..__._____-.-.-:.,_.._~.__._.__.___..~__..._._,._~~____..__._~.~~.~.._;....;..;....~., ._._--.--_._.__._--_.,..__...,-_.__..._;...~ 1 of 1 12/1/2004 11:35 AM Public Notice S ubject:PllblicNotice From: lody Colombie <jody_colombie@admin.state.ak.us> Date: Wed, 01 Dec 2004 11 :34:22 -0900 To: Cynthia B Mciver <bren _mciver@,admin.state.ak.us> Content- Type: application/msword . i ! multiphase notice. doc . . . i ¡. . Content-EncodIng: base64 ......,. 1 of 1 12/1/2004 11:35 AM Public Notice Subject: Public Notice From: lody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 01 Dec 2004 11:34:54 -0900 To: undisclosed-recipients:; BeC: Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, Scott & Cammy Taylor <staylor@,alaska.net>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, tnnjrl <trmjrl@ao1.com>, jbriddle <jbriddle@marathonoi1.com>, rockhill <rockhill@aoga.org>, shaneg <shaneg@evergreengas.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@.usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p. worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Paul G. Hyatt" <hyattpg@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <Iois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, Collins Mount <collins _ mount@revenue.state.ak.us>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.£fullmer@conocophillips.com>, bocastwf <bocastwf@.bp.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@sheU.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>,jah <jah@dnr.state.ak.us>, Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buonoje@bp.com.>, Mark Hanley <mark _ hanley@anadarko.com>, Ioren _Ieman <loren_Ieman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan_hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, nnclean <nnclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary· Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Bill Miller <Bill_Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <k:ristin _ dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP .com>, Steve Lambe <lambes@unocaLcom>, jack newell <jack.newell@acsalaska.net>, James Scherr <James.Scherr@mms.gov>, david roby 10f2 12/1/2004 11:35 AM Public Notice ) <David.Roby@mms.gov>, Tim Lawlor <Tim _ Lawlor@þak.blm.gov>, Lynnda Kahn <Lynnda _ Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, Jerry Dethlefs <n 161 7@conocophillips.com> ---_..----- ---._- ----- ---- --~---"---------_._------ Content-Type: applicationlmsword multiphase notice.doc . b 64 i Content-Encoding: ase ---_._,-,---"---~--_._-- .---,..- --"._-,"-------------~-~ -.--,.------- 20f2 12/1/2004 11:35 AM Citgo Petroleum Corporation Mary Jones David McCaleb PO Box 3758 XTO Energy, Inc. IHS Energy Group Tulsa, OK 74136 Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Kelly Valadez Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 408 18th Street President Boise, 10 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman Schl um berger David Cusato Halliburton Drilling and Measurements 200 West 34th PMB 411 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Baker Oil Tools Ciri Jill Schneider 4730 Business Park Blvd., #44 Land Department US Geological Survey Anchorage, AK 99503 PO Box 93330 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 Williams Thomas North Slope Borough 1t9/ld Arctic Slope Regional Corporation PO Box 69 Land Department Barrow, AK 99723 PO Box 129 Barrow, AK 99723 a/s)¥ #1 ) ) GUIDELINES For QUALIFICATION OF MUL TIPHASE METERING SYSTEMS FOR WELL TESTING November 30, 2004 Alaska Oil & Gas Conservation Commission www.aoqcc.alaska.gov Prepared by: Parviz Mehdizadeh, Ph.D. Production Technology Inc. Jane Williamson, P.E. Alaska Oil and Gas Conservation Commission AOGCC Guìdelines for) Parviz Nlell(L,__.J'~roductìon Technology Ine Qualification of Multiphase _",,,teríng Systems Jane \Vìlhamson. AOGCC 11-30-04 Guidelines for Qualification of Multiphase Metering Systems for Well Testing Table of Contents 1.0 Purpose................................................................................ ...3 1 .1 Organization of the AOGCC Guidelines...........................4 1.2 "Principles of Multiphase Measurements" ........................4 2.0 AOGCC Administrative Process .......... ............. .............. .......5 2.1 Appl ication Contents-General.......................................... 5 2.2 Review Process............................................................... 5 2.3 AOGCC Decision............................................................. 6 3.0 Qualifying Multiphase Metering Systems for Well Testing..6 3.1 Application Contents...... ...... .... ........................................6 3.2 Accu racy Expectations ....................................................8 4.0 Validation of Meter Peñormance in Field............................ 1 0 4.1 Field Verification... ............ ........... ......... .........................10 4.2 Field Test Plan............................................................... 11 4.3 Reporting the Field Results............................................ 13 2 of 1 5 AOGCC Guidelines for ) Parviz Meh(LC__.J1:roduction Technology lnc Qualification of ?viultiphase, ._<-tering Systems Jane Vvì1harnson, AOG-CC 11-30-04 Guidelines for Qualification of M,ultiphase Metering Systems for Well Testing 1.0 Purpose 1.0.1 The use of multiphase meters for well testing is gaining increased support within petroleum production operations. It is anticipated that Alaskan operators will be pursuing their use in well testing and field production allocation. 1.0.2 Multiphase meters are devices that measure oil, gas, and water flow rates of a well stream with or without partial separation of these components into individual phases. Multiphase metering techniques were developed as an alternative to measurement methods using two and three phase gravity based test separators. 1,0.3 The Alaska Oil and Gas Conservation Commission (AOGCC) is authorized to evaluate and approve methodology and equipment utilized for well testing and allocation of production in Alaska per regulation (20 MC 25.230) and Alaska Statute (Sec 31.05.030( d)(6)). 1.0.4 Industry standards and recommended practices are in place for test separator based single-phase gas or liquid metering. However, there are no standards and few guidelines available for multiphase meters. 1.0.5 Considering that the multiphase metering technology is relatively new and that accurate well test metering has both financial and reservoir management importance, the AOGCC will require approval prior to use of mutiphase meters to satisfy requirements of 20 MC 25.230. These guidelines are provided to train and direct the operator and AOGCC on how to qualify these new measurement techniques. 1.0.6 These guidelines address both wet gas and multiphase metering systems for use in well testing. Custody transfer applications are regulated under 20 MC 25.228 and are outside the scope of these guidelines. 1.0.7 The materials described in the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" were developed to serve the following objectives: .3 of 1 5 AOGCC Guidelines for ) Parviz JVIelK,,_~& <~roductìon Technology lne Quah:J:1earion ofìvlultiphase _ Aeríng Systems Jane \VìlIiamson. AOGCC 11-30-04 1.0.7.1 As a guide for the operator in submitting a request to apply new multiphase metering techniques for well testing and allocation of production, 1.0.7.2 As a guide and process tool for reviewing operators' requests for qualifying a multiphase metering system for well testing, and 1.0.7.3 As a training tool for AOGCC personnel who will be involved in the assessment of the multiphase technology for well testing. 1.1 Organization of the AOGCC Guidelines The remaining sections of this document are organized as follows: Section 2 AOGCC Administrative Process: This section outlines the overall administrative process that will be followed for certification of a multiphase metering system. Section 3 Qualifying Multiphase Metering Systems for Well Testing: AOGCC expectations of documentation to accompany the application for pre-certification or certification of the proposed multiphase metering system are described. Section 4 Validation of Meter Performance in Field: In some instances, the AOGCC may require field verification of meter performance prior to approving use. This section provides recommendations and requirements for conducting these field tests to gather information required by the AOGCC for qualification of the multiphase metering systems and outlines requirements for documentation of the field test results. 1.2 "Principles of Multiphase Measurements" A separate document, "Principles of Multiphase Measurements", is concurrently issued with these guidelines. This document provides basic information on multiphase meters, a list of references for further education on multiphase meters, a list of terms and definitions, and installation suggestions for multiphase meters. It is recommended that the novice review the "Principles of Multiphase Measurements" document in conjunction with these guidelines. -4 c~f 15 AOGCC Guidelines for )teríng S ysterns Parviz Ivleh<.,.____.:1')prOduCtion Technology lne Quahfica tion of ?v1u1tiphasf Jane '/'v'i1liamson, AOGCC 11-30-04 2.0 AOGCC Administrative Process 2.0.1 This section describes the AOGCC review and decision process that will be used in processing requests and summarizes required application contents, Section 3 provides further detail on required application content. 2.0.2 AOGCC approval will be required prior to use of multiphase meters in well rate determination to satisfy requirements of 20 AAC 25.230. 2.0.3 AOGCC approval will not be required for minor changes (such as meter size or minor technical upgrades that will not deteriorate performance) of previously approved meter systems. However, if production characteristics change significantly (such as large changes in GVF and water cut) from the initial approved application, a new application must be submitted. Approval will not be required for use of multiphase meters if the well test results are not used to satisfy monthly production reporting and well test allocation requirements of 20 AAC 25.230. 2.0.4 The AOGCC will only approve use of a multiphase meter system by Commission order adopting or amending pool rules under 20 AAC 25,520 or, in the Commission's discretion, by administrative approval where provided under an existing order. However, in the case of a pool for which pool rules have not been adopted and for which the applicant demonstrates that pool rules are not yet needed, the Commission will consider an ad hoc application for an order under 20 AAC 25.540 approving use of a multiphase meter system. 2.1 Application Contents-General The application must include a cover-letter request with a summary description of the proposed meter system, discussion of how the proposed meter will be used for the determination of well production within the allocation system, reference to the conservation orders which prescribe the rules for development and operation of the pool, requested changes to the conservation order, and other documentation described in Section 3. 2.2 Review Process 2.2.1 It is recommended that the applicant contact the AOGCC early in the evaluation process to decrease the ultimate time to process applications and to reduce the risk of later costly revisions to plans. S ()f 15 AOGCC Guidelines für ) Parviz IvIehü,_ jhrO(h.lc~i,Ol~,T~.~:mo~og~. I.:l~ Qualification of MtlItiphase, ."teríng Systems Jane W Ilham1:ion. AOGCC 11-30-04 2.2.2 If the application is deemed complete, AOGCC will notice the application for public comment and potential hearing, unless handled by administrative approval. By regulation, a minimum of 30 days is required for public comment from the date notice is issued. In some cases an oral hearing may also be held. Applicants should expect the full approval process, from submittal of a complete application to AOGCC decision, to take 30 to 60 days. 2.3 AOGCC Decision 2.3.1 If sufficient information is provided, the AOGCC may approve the system either unconditionally, or conditionally upon field testing and subsequent reporting of meter performance. Any approval is conditioned upon maintenance of the multiphase meter to provide accurate and reliable measurement, and will require periodic calibration of the multiphase meter and records to be kept to verify the calibration of the meter. 2.3.2 An applicant that is dissatisfied with the AOGCC's decision has the option to request reconsideration ("rehearing"). 3.0 Qualifvina Multiphase Meterina Systems for Well Testina The operator shall submit a proposal to the AOGCC for deploying the multiphase meter or meters in a designated application as a well testing system. 3.1 Application Contents A complete application must address the following: 3.1.1 Discuss the intended application, proposed location and projected timing of installation of the meter. 3.1.2 List fields, pools, and wells affected by the proposal. Are multiple pools commingled? If so, provide details. 3.1.3 Outline any differences in working interest, royalty interest, and tax treatment for leases or for commingled pools. 3.1.4 Ensure that all working interest owners, royalty owners (e.g. Alaska Department of Natural Resources), and state revenue department (Alaska Department of Revenue) are notified. 3.1.5 Describe the meter make, model, type and measurement () of 15 AOGCC Guidelines for )teríng Systerns Parviz IvIehck j "ý}roductìon Technology lne Quahtication oflvl'ultiphase Jane Williamson. AOGCC 11-30-04 methodology for the intended applications. 3.1.6 Describe plans for field-testing the meter (see Section 4). If no field-testing is planned, provide justification. 3.1.7 Provide data on the performance of metering systems obtained from laboratory or field tests. Discuss the expected effect of the proposed meter system upon the quality of the well test data measurement accuracy and overall production allocation in the planned application. 3.1.8 Provide information on expected precision, repeatability, and bias over the range of conditions for which the meter is planned for use. Accuracy must be evaluated across the full range of expected production flow rates, water cut 0NC), gas volume fraction (GVF) and process conditions for which the system will be used (see also Section 4.3). 3.1.8.1 Review accuracy for each phase. 3.1.8.2 The method of accuracy description must be clearly defined. It is preferred that the accuracy be expressed as the percentage (+/-) uncertainty in the flow rates for each phase - Le. oil, water, and gas flow rates. Other methods may be accepted by the AOGCC on a case-by-case basis if sufficient justification is provided. 3.1.8.3 A numerical degree of confidence in the accuracy estimate must be provided and method of determining the confidence level must be discussed. In general, accuracy must be evaluated at a 90% or higher level of confidence. Other confidence levels or statistical analysis of confidence may be accepted by the AOGCC on a case- by-case basis if the methodology for determining confidence level is explained and sufficient justification is provided. 3.1.9 Summarize the production allocation methodology currently being used and explain how the meter will be incorporated into the existing methods of well production allocation. 3.1.10 Describe the contingency plan in the event the meter system does not meet the expected performance. Can the meter be changed out if the system does not meet expected performance, or if the well conditions change such that the production is outside the -; of 1 .5 AOGCC Guidelines fOf) Parviz rVleha>_,__;Ylroductìon TechnologyInc Qualification ofYlultiphase _,""tering Systerns Jane \Villiamson. AOGCC 11-30-04 original designed operating envelope of the meter system? How will this be accomplished? 3.1.11 Submit plans for quality assurance of long-term accuracy. 3.1.12 Describe the proposed systematic maintenance of the measurement system, including methods and frequency of periodic calibration. Describe the proposed record keeping and reporting format. 3.2 Accuracv Expectations 3.2.1 Generally, the AOGCC will expect accuracy for the pay fluid (oil or gas) from the multiphase meter to be within ± 5% over the full range of rates, GVF and WC that the meter will measure when in service. It should be noted that this 50/0 is relative to the reference equipment. 3.2.2 When a multiphase meter is tested against a reference test separator in the field, the accuracy of fluid measurement by both the test separator and multiphase meter will affect the accuracy of the data obtained by the process. Using a root mean square (RMS) approach, the total probable error (accuracy) of the process is determined by: TPE = (E2TS + E2MP) % Where: TPE = total probable error in the measurement E TS = error due to the Test Separator measurement E MP = error due to the Multiphase Meter measurements As an example, if the test separator accuracy is 5°1<> and the multiphase meter accuracy is 5%, the total probable error will be 7%. To obtain a meaningful multiphase meter accuracy, it is critical that the error of the reference equipment be less than 5%. (See also 4.2.2) 3.2.3 Some circumstances may warrant the use of multiphase metering for production allocation even if the meter accuracy is outside the ranges noted above. The AOGCC will consider applications on a case-by-case basis if thorough justification is provided with the application to the AOGCC. 8 of 15 AOGCC Guidelines for )ering Systems Parviz ÑIehü"_,Jí:"1,,,troducÜon Technology Inc Qualification ofl\1u1tiphase _ " ane \Vil1iamson. AOGCC 11-30-04 3.2.4 The applicant shall provide justification for use of a meter system that will operate outside the above stated accuracy criteria. The following are examples where the AOGCC may determine it to be appropriate to relax these criteria. 3.2.4.1 If the meter is used solely for reservoir management and there are no significant financial impacts resulting from well test allocation with multiphase meter systems, less accuracy may be acceptable. 3.2.4.2 Relaxation of accuracy criteria may be appropriate if agreed to by all parties that are financially impacted by inaccuracies of the meter system. 3.2.4.3 It may be very difficult to obtain valid, accurate well tests with conventional separator based systems. As an example, some produced fluids may be extremely difficult to separate and lack of adequate separation will cause large errors in readings. In such instances, use of multiphase meters operating outside of the stated accuracy targets may provide better accuracy and may be preferable to use of separator based systems. 3.2.4.4 Multiphase meters often red uce the measurement system footprint and visits by on-site personnel compared to gravity based separation systems. Multiphase meters may therefore provide an environmental advantage in new, remote drillsite developments and may improve chances of development approval from other regulatory agencies with authority over land use and environmental conservation. 3.2.4.5 Multiphase meter systems may facilitate more frequent well tests as compared to a gravity separator based system. The stability of production during the non-test times will greatly affect the overall allocation accuracy. With more frequent testing and the resulting greater certainty in well test production, overall production allocation may be improved even if the absolute accuracy of the multiphase meter is less than that of the gravity based test separator. 9 of 15 AOGCC Guìdelines for }eríng Systerns Parviz f.,/Iehüc .J(>1"tro(:UC:r~0I~ T e~hno~og~, I~lC Qualification of l\tu1tìphase _ ant: \\ Ilhamson, AOtJCC 11-30-04 4.0 Validation of Meter Performance in Field 4,0.1 The AOGCC will generally require field validation of meter performance prior to final approval. This section provides a guide to the operator in planning a field test to verify the performance of the measurement system and required documentation of these tests. It is strongly encouraged that the field test plan be reviewed with the AOGCC prior to actual field-testing to ensure required data is obtained and to help speed the approval process. 4.0.2 In determining whether to waive the requirement of field testing in a particular situation, the AOGCC will consider such factors as other performance validation options, including prior successful field tests for similar types of fluids and flow conditions, the purpose to which the multiphase metering system will be put, and the practicability of field testing. 4.0.3 Situations where the AOGCC may choose to waive requirements of a field test include but are not limited to the following. 4.0.3.1 Field validation may be unnecessary if the meter system has been successfully tested in a field with similar fluids, flow regimes, operating conditions, rates, GVF and WC. Results of the prior testing must be provided. 4.0.3,2 If the meter is used solely for reservoir management purposes and other lab or field tests are available at similar conditions, a field test may be unnecessary. 4.0.3.3 Field validation of multiphase meters may be difficult, logistically impossible or highly impractical in some instances, particularly for new, remote drill sites. In lieu of a field test, the AOGCC may accept other lab or field tests conducted at similar operating conditions 4.0.4 If the AOGCC determines that a field verification of the proposed multiphase metering system is required, the processes described in the remainder of this section must be followed. 4.1 Field Verification 4.1.1 The field tests must be conducted under normal field operating conditions. 4.1.2 Field tests require comparison to reference field measurements. Options used to determine the reference flow are: 1 () G f 15 AOGCC Guidelines for .) Parviz Meho, ..Jr'···'\~roductìon Technologylnc Qualification of?vhI1tiphase l .. 'cring Systems Jane \Vì1liamson. AOGCC 11-30-04 4.1.2.1 Capturing fluids that flow through the system during the test and measuring them with secondary equipment. This option requires extra equipment that must be calibrated per appropriate standards. 4.1.2.2 Indexing the performance of the new system against an established well test measurement system such as a conventional gravity based test separator. 4.1.2.3 A combination of the above. 4.1.3 There may be a large uncertainty in the reference measurements. Pre-calibration and maintenance of the reference measurement system must be performed prior to conducting the field trial. 4.2 Field Test Plan The following is a guide for planning of field tests and may be revised to suit specific conditions. 4.2.1 Establish performance expectations that are within the design and tested constraints of the system. 4.2.1.1 Multiphase metering accuracy degradation typically occurs for wells that have operating liquid rates, gas rates, water cut, or gas volume fractions outside the system's designed accuracy range. 4.2.1.2 The multiphase metering system must be sized and designed to handle the flow ra nge, pressure, and temperature (ambient and production) conditions existing in the field. 4.2.1.3 Multiphase meter performance is also related to the fluid composition such as salt content of the liquids, impurities in the gases etc, which can change over the field life. 4.2.2 In a majority of qualification tests, 2-phase or 3-phase gravity based test separators are used to verify the performance of other multiphase measurement systems. Since these systems are used as the reference, the test plan must document the procedures used to calibrate and establish the accuracy of the liquid and gas measurement devices, the water cut analysis and monitoring, and the data acquisition and recording. 4.2.3 Full separation is rarely achieved and the procedures must make 11 ()f 15 AOGCC Guìdehnes fm )ering Systems Parviz Nrehú. ,jr '~roducrìon Technology Ine Quali:fiea don of M ultiphase Jane \Vilhamson, AOGCC 11-30-04 an allowance for reduced instrumentation accuracy of the reference under field conditions. 4.2.4 Multiphase meters must be calibrated initially to accommodate the properties of the field fluids. The calibration procedures to be used prior to the field tests must be described. The calibration procedures must cover both the multiphase metering system as well as the reference systems. 4.2.5 Quite often the multiphase meter, the reference test separator, and the tanks used for fluid measurements are operating at different pressures and temperatures. Measurements made by these systems must be converted to rates at standard conditions (14.65 psia and 60 OF). Actual test measurements, prior to conversion to standard conditions, must be retained. Procedures used to determine shrinkage and conversion of volumes to standard conditions must be addressed. 4.2.6 Once the initial calibration is done, the field test results must be obtained without further intervention in the settings of the multiphase meter. If repair, resetting, or recalibration is required d u ri ng the field tests, the natu re and frequency of these interventions must be recorded and reported. 4.2.7 One of the major objectives of the field test is to evaluate the performance of the multi phase metering system over the full range of gas volume fraction and water cut since these are the two principal factors in determining the accuracy of the multiphase metering systems. To accomplish this, an outline of the test matrix to be used in the field tests is needed, noting the range of flow rates, GVF, and we to be covered in the field tests. It is recognized that this matrix may be limited by the flow rates of the wells available, however the test matrix must cover a wide enough range to allow for practical evaluation of the performance. 4.2,8 The testing program must cover enough data points to allow a statistical evaluation of the accuracy performance such as the number of points in the tests that can meet the acceptance criteria of Section 3.2. 4.2.9 The proposed method for reporting the field test results must be described (see Section 4.3). 12 ()f 15 AOGCC Guidelines tor }teríng Systems Parviz Mehc, J. <)Production Technology lne Quahtication oflV1ultiphase:: ' Jane \Vìlliamson. AOGCC 11-30-04 4.3 Reporting the Field Results 4.3.1 Thorough documentation will be required if field verification is required by the AOGCC prior to final approval of the multi-phase meter system. A report must be submitted to the AOGCC describing the results of such field trials, including accuracy results. The guidelines described in this section are recommended for formatting the report of the field test results. Alternate formats may be used. Regardless, it is required that evaluation of performance be provided as a function of factors (rates, fluid properties, operating conditions, GVF, WC, etc.) found to significantly affect accuracy. 4.3.2 All flow performance data for the metering system must be described in conventional oilfield units at standard conditions. 4.3.3 Individual well test results as measured by the multi phase meter and the reference measurement system must be provided and include the following: 4.3.3.1 Flowing pressure - measured at the meter in pounds per square inch absolute (psia). 4.3.3.2 Flowing temperature - measured at th e meter in degrees Fahrenheit (OF) 4.3.3.3 Oil rate - Stock Tank Barrels of Oil per Day (STBD) corrected to standard conditions, at 14.65 psia and 60°F. 4.3.3.4 Water rate - barrel per day (BPD). 4.3.3.5 Gas rate - thousand standard cubic feet per day (MSCFD), at 14.65 psia and 60°F. 4.3.3.6 Gas-oil-ratio (GOR) - (SCF/STB) the gas volume flow rate, relative to the oil volume flow rate, both converted to volumes at standard pressure and temperature. 4.3.3.7 Gas Volume Factor (GVF) - gas volume flow rate, relative to the multiphase volume flow rate (oil, gas, water), at the pressure and temperature prevailing at the meter. The GVF is normally expressed as a percentage 4.3.3.8 Water cut (WC) - the water volume flow rate, relative to the total liquid volume flow rate (oil and water), both converted to volumes at standard pressu re and temperature. The WC is normally expressed as a percentage. 13 of 15 AOGCC Guidelines fOt -',~ Parviz Mehe jr'<froductìon Technology Inc QualiJication oflvlultiphase~~{eríng Systems hane \Vilhamson. AOCiCC 11-30-04 4.3.3.9 Water-in-liquid ratio (WLR) (optional) - the water volume flow rate, relative to the total liquid volume flow rate (oil and water) at the pressure and temperature prevailing at the meter. The WLR is normally expressed as a percentage. 4.3.3.10 Fluid properties including: · Oil volume factor (Barrels at meter conditions/STB) · Gas volume factor (Cubic feet at meter conditions/SCF) · Water salinity · Oil gravity (API) · Gas specific gravity 4.3.4 Figure 1 shows an illustrative graphical method that may be used to display accuracy results as a function of oil, water, and gas flow rates, WC, GVF or other important factors. I n this figure the y coordinate represents flow rate error relative to the reference measurements. 4.3.5 Repeatability of the measured data and confidence level (see 3.1, 8.3) must be stated. The repeatability is expressed by the following relationship: . . (max error) - (min error) repeatabzlzty = ~ number of tests 14 ()f 15 AOGCC Guidelines f01 '1 Parviz Nlehc..__....dr -~roductìon Technology Iue Qualification of ?v1u1tiphase ~ ,,,. 'ering Systen.1s Jane \Vìlliamson. AOGCC 11-30-04 Fig. 1 - An illustrative graphical method of reporting the accuracy performance of multi phase metering systems. These plots should be provided for each phase compared to GVF, water cut, and other important parameters. Liquid Flowrate Error V5. GVF 50 ¡ Test Data r ¡r-.~- -1: '- Â 40 - 0- ~ ,6 t: ~ 30 ~~ Å W c: ~ 20 Ai CI)~ À + j~ A ~ À ... Á ...... Q) 1 0 - Á ~. ... J. Eo=: .10 ~ "".,. À ~1 ... A tA Á ~ .9 0 .. :t t t A. A l·, o Q) -10 " å . . .1. A)i.: AI - > Á A ~ Á LL ~ -20 I A ~!. "'C Q) I ~À .- 0=: -30 - Blue Lines, Range of relative flow rate error ¡ À ::::J 0 C'" ~ -40 I I I ! ¡ ::J -50 I tA 20 30 40 50 60 70 80 90 100 Reference GVF (%) 15 ()f 15 ) PRINCIPLES OF MUL TIPHASE MEASUREMENTS November 30, 2004 State of Alaska Alaska Oil & Gas Conservation Commission Prepared by: Parviz Mehdizadeh, Ph.D. Production Technology Inc. Jane Williamson, P.E. Alaska Oil and Gas Conservation Commission Information Document to accompany "Guidelines For Qualification of Multiphase Metering Systems for Well Testing", November 30, 2004 Principles of Multiphase Measurements Table of Contents 1.0 c:>"E!",¡E!\nI..................................................................................~ 2.0 TE!rms, Definitions, and Nomenclature..................................4 ~.o Standards and Publications ........... ................. .......................5 4.0 Performance of Multiphase Meters .......................................5 5.0 Principles of Multiphase Measurements ...............................6 5,1 Phase Velocity and Phase Fraction Measurements ....................... 6 6.0 Classification of Multiphase Meters ....................................10 6,1 Measurement Techniques,..................... ... ...............................,... 11 6.2 Multiphase Metering Installations............. ,.......................... .......... 12 7.0 WE!t Gas Metering Techniques............................................. 1 ~ 7.1 Classification of Wet Gas..........................................................,... 13 7.2 Type 1 Wet Gas Meters ..................................,..................,.......... 15 7.3 Type 2 Wet Gas Meters ................................................................ 16 7.4 Type 3 Wet Gas Meters ................................................................ 17 8.0 Multiphase Meter Performance ............................................17 8.1 Specifying Accuracy and Uncertainty........................................... 17 8.2 Preferred Method to Describe Accuracy....................................... 17 8.3 Performance Data and Field Tests............................................... 18 8.4 Impact of GVF and WC on Performance ...................................... 18 8.5 Graphical Presentation of Multiphase Performance...................... 20 Appendix 1 - RefE!rences ....................................... .......................22 Appendix 2 - Terms and Nomenclatures .....................................25 Appendix ~ - Installation Suggestions ........................................29 2 -30 Principles of Multiphase Measurements 1.0 Overview 1.0.1 Multiphase metering techniques were developed to improve upon certain measurement limitations of conventional two and three- phase metering systems requiring gravity based test separators. Well tests are conducted routinely to monitor the flow rates from wells and forecast production. The well test data are used for reservoir management, production diagnostics and field allocation. To obtain accurate and consistent test results from conventional well testing systems, the equipment requires high maintenance, field personnel intervention, and time to perform tests. 1.0.2 Operators have looked at the multiphase metering technology as a method for reducing the cost of well tests and improving the quality of the well tests. Since multiphase metering systems can operate without the need for phase separation or with partial separation, they can be made into compact and lightweight systems. The small footprints and lightweight advantages can produce significant savings, especially in operational areas such as the North Slope and offshore where size and weight may result in additional installation costs. 1.0.3 A number of operators on the North Slope are looking at multiphase meter technology as an alternative to conventional gravity based test separators. BP Exploration (Alaska), Inc. (BPXA) and ConocoPhillips Alaska, Inc. have conducted field trials of a number of commercially available multiphase meters in Prudhoe Bay Unit and Kuparuk River Unit pools to assess their effectiveness in current operations as well as future asset developments. 1.0.4 The AOGCC, Department of Natural Resources (DNR) and Department of Revenue (DOR) sponsored a multiphase metering workshop, conducted in Anchorage on May 23,2002, to assess the application of this technology to well testing and field allocation operations in Alaska. This seminar and follow up reviews by AOGCC have indicated that the multiphase metering techniques may be acceptable as a means of obtaining improved well testing 3 -30 data. Furthermore the field wide deployment of this technology (1)* has the potential for improved reservoir management and reduction in facility costs required for well testing as noted by the recent Society of Petroleum Engineers papers listed in references 2-4. 1.0.5 Currently, there are few guidelines or standards available to train and direct the operator and AOGCC on how to qualify these new measurement techniques. To bridge this gap for Alaska operations, the AOGCC published "Guidelines for Qualification of Multiphase Metering Systems for Well Testing." Industry and vendors who have potential application of multiphase meter systems were given opportunity to comment on the guidelines, planned for adoption as the process by which the AOGCC will process applications for multiphase meter use, This document, "Principles of Multiphase Measurements" compliments the guidelines by providing a general overview and training document for the applicant and AOGCC personnel 2.0 Terms. Definitions. and Nomenclature 2.0.1 The term "multiphase metering" in its broadest interpretation can be used to refer to both wet gas metering, as well as, the measurement of oil, water, and gas portions of commingled streams, which is commonly referred to as "multiphase metering". Whether one is conducting a "wet gas" or "multiphase" measurement can depend on which product - i.e. oil or gas - is the focus of the measurement, as well as, the type of equipment used.(2) This document addresses both wet gas and multiphase metering systems. 2.0.2 A number of terms and definitions are used in describing the multiphase flow and multiphase measurements within the industry. The terms and definitions listed in Appendix 2 are adopted from the "Handbook of Multiphase Metering", developed by the Norwegian Society of Oil and Gas Measurement. (3) * References are listed in Appendix I 4 -30 3.0 Standards and Publications No U,S. standard is currently available for the users and regulators in the application and qualification of the multiphase meters. (4) However, the following publications address aspects of the multiphase and wet gas metering, and should be reviewed for those pursuing multiphase meter use. 3.0.1 American Petroleum Institute - "Use of Sub-sea Wet-Gas Flowmeters in Allocation Measurement Systems" , API Recommended Practice RP 85, August 28, 2002 (www.apLorg/cat) 3.0.2 International Standards Organization - "Allocation of Gas and Condensate in the Upstream Area", Draft version of Technical Report -ISOTC193-SC3-WG1, May 18,2002. (a. m.scheers@siep.shell.com) 3.0.3 The Norwegian Society for Oil and Gas Measurement - "Handbook of Multiphase Metering", published by NFOGM, September 1995 (www.oilnet.no/nfoqm) 3.0.4 Department of Trade and Industry, UK - "Guideline Notes For Petroleum Measurements Under The Petroleum (Production) Regulations", Oil and Gas Division, UK, Issue 7 - December 2003. (www.og.dtLgov.uk/requlation.) 3.0.5 American Society of Mechanical Engineers- "Wet Gas Metering Guidelines", ASME/MFC publication 19M, (in preparation). RichardS@mccrometer.com 4.0 Performance of Multiphase Meters The use of multiphase meters in field applications is in its relative infancy. There are few generally accepted standards for performance. Three different approaches have been used by industry to verify the performance of multiphase and wet gas meters. These approaches consist of: 4.0.1 Manufacturer sponsored testing either in a third party test loop or at the manufacturer's facility. A number of joint industry studies have been conducted to establish that these meters can perform to the specifications and capabilities claimed by the manufacturers. (7) The National Engineering Laboratory (NEL) in the UK, the K-Lab Wet Gas loop in Norway and the Colorado Engineering Experiment Station (CEESI) in the US have conducted a number of joint 5 -30 industry projects to characterize the performance of multiphase flow meters. The results are not published but released to Joint Industry Project (JIP) participants and the multiphase meter manufacturers, who can share the data with their clients. 4.0.2 Third party testing where vendors and end users are not involved. These tests are generally conducted in a test loop under controlled conditions. 4.0.3 End-user field-testing where the multiphase meter is tested against conventional test separators. Many of these tests compare and index the performance of the multiphase meters to gravity based two or three phase test separators. The owner companies conducting the tests generally release the results to the JIP participants and the multiphase meter manufacturer. Some results have been published. (8-20) 5.0 Principles of Multiphase Measurements The primary information required in the measurement of oil or gas multiphase flow streams includes flow rates of oil, water, and gas. The ideal method to obtain this data is to have a multiphase flow meter that would make direct and independent flow rate measurements of these components. Unfortunately, such a device does not exist as yet. Consequently, much of the extensive development in multi phase metering has been directed toward inferential techniques that use the instantaneous velocity and cross sectional fraction of each component to make these measurements. The following section will examine the application of these techniques as applied to multiphase meters used for oil, water and gas measurements. 5.1 Phase Velocity and Phase Fraction Measurements 5.1.1 For single-phase liquid or gas travelling through a pipe of cross sectional area A at an average velocity V, the volumetric flow rate Q can be calculated by: Q=AV (1 ) 5.1.2 When an oil, water and gas mixture is flowing through the same pipe, the calculations of the volumetric flow rates are complicated. 6 -30 As gas and liquid flow simultaneously in a pipe, the two phases can distribute themselves in a variety of flow regimes, The configuration of the flow regime is affected by gas and liquid flow rates, pipe diameter, and fluid properties. These effects result in a variety of flow patterns as shown in Figure 1. ~. J~~'. ~"...~ .,,-,*<" !~t/ rm~1~lft'lwrf¡y:,"j;i~li~~./ ./' Plug / /' /' ~' ",",': :-<~". .' . .' . P':C::;-'r( ~/ ,~ ¡ / ",;,.'J.~(f "ttt:.!!,:JJt£;."ê ,/ '>(" ' /' /" Slug .-~... Mist Figure 1 - This schematic shows general flow patterns of gas-liquid stream in horizontal and near horizontal pipe (Reference 3). I ,.."" " f\ ......,.'.." GAS -A. ' .' " ": " _ I ,,' ~' ,I III ' f - I , ~ ~ ' . "'lOlL . ' ,'~ ...... Vs i VVATER V ---..-----.--...--.------................-----.--.....--_..~--_._-_._--,.._---._...._.__..._---_._-----_...__..---.-------------.....--.------.----------..---..-.-...-------..-.-.--..--.-----..---.---..--.--..---..-....-...---..-.-.---..-----..---.--.---.-' Figure 2 - An approximate model of the multiphase flow. Each phase is occupying a fraction of the total cross sectional area of the pipe. The superficial phase velocity is defined as the flow velocity of one phase, assuming the phase (gas or liquid) occupies the whole conduit. 7 -30 5.1,3 A simple approach to estimate the volumetric flow rates for each phase is to establish the distribution of each phase (as illustrated in Figure 2) by assuming that each phase is occupying a fraction of the total cross-sectional area at any instant, which is determined by the following relationships: fo = AJA, fw=Aw/A, fg =Ag fA (2) fo+fw+fg = 1 (3) Where fo, fw, and fg are the volume fractions (fraction of cross sectional area A) of the oil, water, and gas phases in the mixture. 5.1.4 The volumetric flow rate Q of each phase and the total (mixture) flow rate are then determined by: Qo = A fo Vo , Qw =A fwVw , Qg = A fg Vg (4) Qt = Qo+Qw+Qg (5) Where Vo, Vw, and Vg are the superficial velocities of the oil, water, and gas phases in the mixture. The task of any multiphase meter is to estimate the volume fractions and the individual phase velocity in the above equations. 5.1.5 A model shown schematically in Figure 3 is used by multiphase metering systems to conduct these processes. The developers of the multiphase meters have employed different technologies and modelling of the multiphase flow (2,6,7) to simplify the process shown in Figure 3. 5.1.6 Multiphase measurement systems that are commercially available today (6) utilize a diverse range of equipment from full three-phase conventional separators to in-line multiphase meters that consist of a spool piece with no separation. From the perspective of users, these systems have one common purpose - i.e. to provide accurate flow rates for oil, water and gas. 8 -30 A ~ ~ . *~ + :, ·,~·:..·,·~~~~~r,¡~f~1íI:~1,c.~'f~~?Iì"î&:"·'~;;: .~~~_' '. " l~M'¡~~;;~~~ "J', -i'~~J:r~f}l1Jifllfg;:~~~;ªc4u",:,,~" ,:~~}U~;:,;, -"~ fl~,e\~ ",~ø. e4S;; e.S;:;'''c~:T;;¡'; . .- 'i~~":!'~-'~;·~j.·h::_~~.j~~~ '-~:~~~L ~'_~:.l'.. I. t'I r~._.,·" __" _r . '~L" ~$''¡'',~.:~~ Inlet.; ':Fli,-'t'''Ð~:~~''~~'~'hIi~ "'~~riR ' ~"'..~._~~.,~.~ Mu~~:~ase -':~}~j~¡~._..ï~ ~ Output - oil, water, gas flow rates Figure 3 - Processes shown schematically in this figure are used in a multiphase metering system to obtain single-phase flow rates from a multiphase stream. 5.1.7 Processes that are shown in Figure 3 consist of some type of fluid conditioning, mixture density determination, mixture rate determination, mixture composition determination, and application of a flow model. These functions can be supplied by an instrument or by an assumption in a model. 5.1.8 A multiphase metering system scans the flow stream at very high frequency, processes the instantaneous flow rates for each phase, and sums up the data for each phase to produce the flow rates for each phase within the multiphase stream. Figure 4 shows the distribution of the oil, water, and gas, at a wellhead, as a function of time, as recorded by a multiphase meter. 9 -30 1000 - 92 900 I - 90 800' I I - J II, 1\] t J, I ~ \f ~ I I' ¡[ , I "~ ,I ~ 700' ,~ . 'If' t ',~ ,I! \'i. " , ' ',: ¡ " ;, t ' - 88 Ii' ,',' . II Å~ I I' . d~ , " .." 600· I k ~¡ 1'1 \~ (t,,] 1'1 \' 11'1 ! , r r '1, \\ f, ,j' !I'lli,' ~I:I !' ., '~\' 'II~ B P 500' I II':' , I ¡ I 't I;' I, ~ ij'~ '11r,' I ~ I "I r ," - 86M D 400 'I) ~II' I' i 'I , 'I I II I ; \ I'~ ,', ì j ~ \ . I q Ii I" ~ ! A i !!~ ~ \ I i \' '" Iii ~ i Ii ¡!., \ I '¡II 1 - 84C 300- ,í~'~îl;~~WI!: ¡~ i\~~n~~~ll 'Þt'~ F 200- - 82 D -QO BPD 100' -QW BPD - 80 0 -OG MACFD 0:00 1:12 2:24 3:36 4:48 6:00 7:12 8:24 9:36 Time, hours Figure 4 - Distribution of oil (green), water (blue), and gas (red) flow rates in real time at a wellhead as recorded by a multiphase flow meter. 6.0 Classification of Multiphase Meters 6.0.1 There is currently no "commonly-accepted" method of classifying multi phase meters. The following classification is proposed for this document until a "standard" classification system becomes available. In this classification, the metering systems are grouped in terms of methods by which the gas and liquid components are handled. 6.0.1.1 In Group I systems, one or more phases are completely separated then measured. The separated streams mayor may not be recombined to form the original stream. This category includes gravity or centrifugal based separation systems. 6.0.1.2 In Group II systems, the main flow stream is divided into "gas rich" and "liquid rich" streams, generally using separation based on a centrifugal process, Each stream is 10 -30 subjected to multiphase measurements then recombined to form the original stream. 6.0.1.3 In Group III systems, all three phases go through a single conduit and are measured at the same time. This category includes all the so-called inline meters. These meters may use some form of flow conditioning - i.e. use of elbow, mixers, etc. 6.1 Measurement Techniaues In each group, different measurement techniques, combination of techniques, and strategies can be used to obtain phase velocity and phase fraction information. Some typical examples of these techniques are shown in Table 1. For a more comprehensive discussion of these techniques, and how they are utilized in commercially available multiphase metering systems, the reader should consult references 2 and 6. Table 1 Measurement Techniques and Devices Used to Obtain Phase Velocity and Phase Composition in Multiphase and Wet Gas Metering Systems Velocity Methods Composition Methods Venturi Device Capacitance Positive Displacement Device Cond u ctivity II nd ucta n ce Coriolis Device Microwavell nfrared Cross Correlation Techniques Dual Venturi Acoustic Attenuation Gamma Ray Absorption 11 -30 6.2 MultitJhase Meterina Installations 6.2.1 The AOGCC "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" focuses on Groups II and III multiphase metering systems. However, it should be noted that Group I systems, which include 3-phase and 2-phase gravity-based test separators, are used in a majority of operations. The number of Group II and III installations (4) is about 1000, while the number of Group I installations is well over 10,000. Also, gravity-based test separators are the current "standard" of field measurement within the industry. All Group II and III installations are performance indexed against these systems in the field. Figure 5 shows four different multiphase metering systems in a field test loop. Figure 5 - A field test loop that includes four different multiphase metering systems. From left to right- Agar MPFM 400, Roxar 1900VI, FMC FlowSys, and Schlumberger Venturi X. (21) 12 -30 7.0 Wet Gas Meterina Techniaues Wet gas metering covers a wide range of measurements, which is necessitated by the specific applications and the definition of "wet gas". The definition of wet gas can vary depending on whether one is looking at the fluids from the perspectives of reservoir engineering, measurement systems, or commercial sales of the products. (7) Wet gas can be simply defined as gas, which contains some liquid. The amount of liquid can vary from a small amount of water to substantial amount of water and hydrocarbon. The amount and nature of the liquid, as well as the flow rate, temperature, and pressure of the flow stream can impact the selection and accuracy of the measurement system. It is therefore important that "wet gas" be characterized properly before one can discuss the wet gas measurement systems. 7.1 CœssificaüonofWetGas 7.1.1 A classification for different types of wet gas is proposed in reference 8. The proposed classifications, shown in Table 2, will be used in this document. This classification is based on superficial velocity (volumetric rate divided by the pipe cross sectional area) for gas and liquid and the Lockhart-Martinelli parameter, which is defined as: X = (Vsl / Vsg) (""pi / ""pg) (1 ) Where X is the Lockhart-Martinelli number, Vsl and Vsg are the superficial velocity, and pi and pg are the density of liquid and gas respectively. The gas volume fraction (GVF) of the stream can be obtained from the following equation: GVF= 1/ [1 + X* C-Jpg/""pl)] (2) The liquid to gas ratio (LGR) can also be calculated from Equation 1. LGR=X*(""pglvlpl) (3) 13 -30 7.1.2 Equations 1-3 can be used to identify three different regions of wet gas and calculate the associated gas volume fraction and liquid load in each region. A summary of different types of wet gas conditions and typical areas of application is shown in Table 2. It should be noted that the boundary for these three types of wet gas conditions is dependent on the composition of the liquid fraction and the pressure and temperature of flow stream, which affects the density of the gas and liquid. TABLE 2 - TYPES OF WET GAS AND TYPICAL APPLICATIONS IN PRODUCTION OPERATIONS Type of Lockhart- Typical Applications Wet Gas Martinelli Number Type 1 Equal or less than Type 1 wet gas measurement represents 0.025 measurement systems at prod uction wellheads, unprocessed gas pipelines, separators, allocation points, and well test facilities. Liquid measurement is necessary to make correction for improved gas measurements. Type 2 0.025 to 0.30 Type 2 wet gas-metering systems cover higher liquid flow ranges so that the users often require more accurate gas and liquid flow rates. Applications include the flow stream at the production wellhead, commingled flow line, or well test applications. Type 3 Above 0.30 Type 3 meter must make an oil, gas and water rate determination at relatively high GVF > 800/0 or X~0.3. Typical application is gas condensate wells and gas lift wells. 14 -30 7.2 Tvpe 1 Wet Gas Meters 7.2.1 Table 3 lists devices that are used for metering Type 1 wet gas conditions. Type 1 metering systems are typically used in fiscal metering. These are single-phase commercial gas meters that require liquid flow rate input to measure gas flow rate calculations. These methods assume a constant liquid flow rate estimate over a time period or until a new liquid flow rate is updated. 7.2.2 Common methods of determining liquid flow rate are periodical well tests, tracer injection, pressure-volume-tem perature (PVT) prediction, and allocation techniques. 7.2.3 The liquid presence in the gas for Type 1 metering systems cause a systematic bias error in gas flow measurement if liquid content is not corrected in the gas flow equation. When utilizing Type 1 system, selection of flow-metering devices for liquid measurement and their correspondent uncertainty must be considered in order to deliver an optimum system. Table 3- Type 1 Wet Gas meters, gas rate over-reading data (reference 7) Metering Devices Volumetric Over-reading range (%) for Lockhart- Martinelli number SO.02 Coriolis o to 6 Inverted Venturi (V-cone) o to 1 .5 Orifice -1 .7 to 2 Turbine o to 0.75 Ultrasonic o to 1 0 Venturi o to 5 Vortex o to 6 15 -30 7.3 TVIJe 2 Wet Gas Meters 7.3.1 Type 2 wet gas metering systems typically measure the flow stream at the production wellhead, commingled flow line, or for well test applications. In some applications direct measurement of produced water in the gas stream can improve process control and reservoir management. (23) 7.3.2 Several commercial metering systems have been developed for Type 2 wet gas. (7) Most Type 2 wet gas meters use a differential pressure device plus another technique to measure gas and liquid flow rates. Sampling and tracer techniques are used in some systems to determine liquid flow rate periodically when liquid flow rates remain constant between sampling intervals. Other systems such as extended Venturi, dual differential, and dual Venturi with vortex offer continuous measurement of gas and liquid flow rates. Other systems offer direct measurement in the gas stream. 7.3.3 Examples of the various techniques and combination of devices (7) used in Type 2 wet gas metering systems are listed in Table 4. Table 4- Various Techniques and Combination of Devices Used in Type 2 Wet Gas Metering Systems · Venturi and Wedge · Dual Venturi with Vortex · Extended Venturi · Orifice with Sampling · Venturi with Tracer Sampling · V -cone with Microwave based Water Cut device 7.3.4 The field proven accuracy of these devices has not yet been fully corroborated by the users. Operational conditions and fluid properties significantly impact the volumetric uncertainty. Type 2 wet gas metering is applicable for higher liquid flow ranges, where the commercial value of the liquid may be significant. 16 -30 7.4 TYlJe 3 Wet Gas Meters 7.4.1 Metering systems used for Type 3 wet gas are multiphase metering systems that were developed to measure flow streams composed of oil, water, and gas mixtures as was discussed in Section 6. 7,4.2 In field tests where the performance of the Type 3 wet gas and Group III multiphase meters have been compared to conventional test separators, uncertainty of 5-10% has been claimed. (21) Even uncertainty values as low as 20/0 have been claimed in some field tests, (7) It should be noted that these accuracy performances are obtained by comparing the gas flow measurements against conventional separators that generally use gas-metering devices described for Type 1 wet gas metering conditions. In many of the field tests these "reference" devices have questionable accuracy. 8.0 Multiphase Meter Performance 8.1 SlJecifvina Accuracy and Uncertainty 8.1.1 Manufacturers and users have utilized different methods of specifying and reporting the uncertainty (accuracy) for multiphase meters. Reference 2 provides a discussion of the various methods of describing the accuracy of a multiphase metering system, their advantages and limitations. 8,1.2 Users generally prefer to specify the accuracy in terms of percentage uncertainty relative to the flow rates of each phase - i.e. oil, water, and gas flow rates. This method is preferred by the AOGCC. 8.1.3 The uncertainty of the metering system can also be specified as a percentage relative to the total multiphase flow rate, which is called the "relative" uncertainty method, In certain measurement applications - e.g. trending or monitoring process changes at low flow rates, this may be an appropriate method for describing the accuracy (performance) of a multiphase metering system. 8.2 Preferred Method to Describe Accuracy 8.2.1 In the document "Guidelines for Qualification of Multiphase Metering Systems for Well Testing", the AOGCC requires that the percentage uncertainty of each phase be used to describe the 17 -30 accuracy of the multiphase measurements, 8.2.2 As an example, if the meter specification calls for relative uncertainty of each phase to be within ±100/0, the anticipated production accuracy for this meter testing a well that is producing 500 BBL/D of liquid at a 200/0 water cut and GaR of 1000 SCF/B is shown in Table 5. Table 5 - DETERMINTA TION OF UNCERTAINTY FOR A WELL PRODUCING 500 BBUD OF LIQUID, WC=20%, GOR = 1000 SCFISTB Well Fluids Flow Rates Absolute Uncertainty Relative ± 10°10 of phase flow Uncertainty I Production rate Accuracy Oil 400 BBL/D ±40 BBL ±100/0 Water 100 BBL/D ±10 BBL ±100/0 Gas 400 MSCF/D ±40 MSCF ±100/0 8.3 Performance Data and Field Tests As described in Section 4, three different approaches have been used by industry to verify the performance of multiphase and wet gas meters. The approaches include manufacturer sponsored testing, third party testing and end user testing, In the AOGCC "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" the focus is on field testing. However, when applicable, data from the other types of testing may be used to support the application with expected performance later verified in actual field conditions. 8.4 Impact of GVF and we on Performance 8.4.1 The performance data available from all the sources described above show that the level of accuracy for all types of the multiphase meters is affected by two major factors as discussed below. 8.4.1.1 As the GVF of the flow stream increases, the level of accuracy for the liquid (oil and water) rate determination is adversely affected. 18 -30 ;~8r\;.lZ 8.4.1.2 As the we in the flow stream increases, it becomes more difficult for a multiphase metering system to achieve high levels of accuracy for the oil phase, which frequently is the major focus of the measurements. 8.4.2 The effects described in item 8.4.1 are to be expected since the gas phase can expand much more than the liquid phase and therefore occupy a larger fraction of the volume. Similarly as the water cut increases, the volumetric fraction occupied by the oil phase decreases, These relationships are shown graphically in Figure 6. 8.4.3 Both GVF and we impact the performance of the devices and modeling assumptions that are used in multiphase metering systems to identify the volume fraction (fo = Ao/A) and calculate phase velocity. The resulting loss of accuracy in volumetric fraction and phase velocity determinations impacts the calculation of the oil, water, and gas flow rates in a multiphase stream. OIL 4% OIL 10/0 WATER 60/0 I / GAS 93% GAS 600/0 Figure 6 - Graphical representations of the impact of GVF and we on the phase distribution for the oil flow rates as would be seen by a multiphase metering system. The actual flow rates for the oil and water is the same for both diagrams, but GVF has increased from 60% in the left diagram to 93% on the right side. 19 -30 8.5 Graphical Presentation of Multiphase Performance 8.5.1 A variety of methods have been used to graphically show the performance of the multiphase meters. Reference 22 describes these graphical methods, their advantages and limitations. The two most commonly used graphical presentations are shown in Figures 7 and 8. 8.5.2 Figure 7 shows the accuracy of liquid flow rate for four different multiphase meters. The dotted lines, in Figure 7, show the ±5%) error band. The liquid (water and oil) flow rate measurements from the multiphase meters are compared with reference flow rate data, in this case obtained from a gravity based test separator. This type of plot is useful in showing if the liquid rate measurements for a certain multiphase meter can satisfy the ±5% accuracy level within the flow range shown in Figure 7. 8.5.3 Figure 8 shows the accuracy of the liquid flow rate for the same four multi phase meters, shown in Figure 7, in the so-called "two phase map". In this type of graphical presentation one can see the impact of another parameter - i.e. GVF, on the accuracy of the four meters. The error bands show the capability of each meter to satisfy the ±5 accuracy requirement for liquid flow rates. This type of presentation is helpful to show not only the compliance of a meter with the accuracy requirement but also the effect upon accuracy as the GVF is increased. This "two phase map" type of graphical presentation can also be prepared to show the impact of other important factors such WC. This approach is especially helpful where the multiphase metering application is being considered for a large number of wells with wide range of GVF and WC values. 20 -30 ? arvi z MFM Liquid Rate 3500 - +/- 5% error · Meter A () Meter B ¡¡¡¡ Meter C ~ Meter D () o o I I o 500 1 000 1500 2000 2500 3000 3500 Reference liquid flowrate Figure 7 - (Reference 21) Graphical presentation of liquid rate accuracy of four different meters as a function of flow rate MPM Liquid Errors 50 - . g 40 - - +1- 5% error <> E!IiI Q) i!I . .! · Meter A ~ ! 30 - 0 M t B m I!!I ~ o e er . 0 ~ .~ ~ 20 - IÐ Meter C + 't · - 0 <> <> !! · Meter D $ I!!I... ,.. ! 10 - .. ~<> ~ ,~. ~\ ... ~ . <> iii .~ o 0 Q .. ð> <> ·0 <> ~ ~ ; t:. è). i\. ~ ~ CD -10 _ · ~$. GIJ <> CD œ.+ fit ~ . <> ... -20 - IÐ ~ ø o ¡¡:: -30 - :2 ::J -40 - <> 5' -50 I 40 60 80 100 Reference GVF Figure 8 - (Reference 21) Graphical presentation of the liquid rate accuracy of four different meters shown in Figure 7, as a function of the GVF in the flow stream. 21 -30 Principles of Multiphase Measurements Appendix 1 - References 1, Mehdizadeh P., "Multiphase Measuring Advances Continue," Oil&Gas Journal, July 9, 2001. 2, State of the Art Multiphase Flow Meterinq, American Petroleum Institute Publication 2566, 1 st Edition, Committee on Petroleum Measurements, May 2004. 3. Dykesteen, Eivind, et aI, Handbook of Multiphase Metering, Norwegian Society for Oil and Gas Measurement, published by NFOGM, September 1995. 4, Mehdizadeh P., "Status of MP and WG Metering," presented at TAMU Multiphase Measurement Users Roundtable, Houston, May 7,2003. 5. Theuvey, B. C. and Mehdizadeh, P., "Multiphase Flowmeters for Well and Fiscal Applications", SPE 76766, presented at SPE Western Regional/AAPG Pacific Section Joint Meeting, Anchorage, May 20-22, 2002. 6. Falcone, G" et aI, "Multiphase Flow Metering- Current Trends and Future Applications," SPE 71474, presented at 2001 SPE-ATCE, New Orleans, September 30 - October, 2001. 7. Mehdizadeh P., Marrelli J" and Ting V,C., "Wet Gas Metering: Trends in Application and Technical Development," SPE paper 77351, presented at SPE Annual Technical Conference and Exhibition, San Antonio, September 29-0ctober 2,2002. 8, Mehdizadeh P., Marrelli J., and Ting V.C., "Meter Designs Provide Wet-Gas Measurement Alternatives," Oil&Gas Journal, March 24, 2003. 9. Stokes, Edward G., et aI, "Application of The First Multiphase Flowmeter in The Gulf of Mexico," SPE 49118, presented at Annual Technology Conference and Exhibition, New Orleans, September 27-30, 1998. 22 -30 10. Kalsaas, Odd-Pedder, et aI, "Operational Experience with Multiphase Meters at Vigdis," presented at Multiphase Metering Workshop 2001 ASME -ETCE Conference, Houston, February 27,2001. 11. Santamaria, G, and Noel, M.I., "Multiphase Flow Metering: the Mexican Experience," presented at TAMU Multiphase Measurement User Roundtable, Houston, May 3, 2000. 12. Shen, Joseph, "Field Operation of a Compact Separation Multiphase Metering System," presented at Multiphase Measurement & Production Testing User Roundtable, Houston, May 3, 2000. 13. Means S. R. and Mehdizadeh P., "New Technology Improves Well Testing Units," Oil&Gas Journal, October 30,2000. 14. Bortolin, Luigi, "Petrozuata's Multiphase Metering Application," presented at T AMU Multiphase Measurement User Roundtable, Houston, May 3, 2000. 15. Humphrey, A. I., et aI, "Application of Multiphase Metering in Machar and Monan Fields," OTC 12018, presented at 2000 Offshore Technology Conference, May 1-4, 2000, Houston. 16. Shen, Joseph, et aI, "Field Evaluation of a Multiphase Meter in Well Testing Operation," SPE 37436, presented at 1997 SPE Production Operations Symposium, Oklahoma City, March 9-11,1997. 17. Ngai,Charles C., et aI, "Performance Test of a High Gas Volume Fraction Multiphase Meter in'a Producing Field," SPE 38784, presented at 1997 SPE Annual Technical Conference and Exhibition, San Antonio, October 5-8, 1997, 18. Okland, 0., et aI, "Applications of Multiphase Meters at the Fullfaks Field in the North Sea", OTC 8551, presented at 1997 Offshore Technology Conference, Houston, May 5-8, 1997. 19. Tuss, Bernie, et aI, "Field Tests of the High Gas Volume Fraction Multiphase Meter," SPE 36594, presented at 1996 SPE Annual Technical Conference and Exhibition, Denver, October 6-9, 1996. 20. Mohamad, P. G., et aI, "Field Evaluation of Different Multiphase Flow Measurement Systems," SPE 56585, presented at 1999 SPE-A TCE, 23 -30 Houston, October 3-6, 1999, 21. Hasebe, B., Hall, A" Smith, B., Brady, J., and Mehdizadeh, P., "Field Qualification of Four Multiphase Flowmeters on North Slope, Alaska," SPE 90037, presented at 2004 SPE-ATCE, Houston, September 27-29,2004. 22. Scheers, Lex, "Multiphase and Wet Gas Flow Measurement", presented at T AMU Multiphase Measurement Users Roundtable, May 8, 2004, Houston. 23. Haddelland, R., et aI, "Online Measurement of Water in Wet Gas Flow," presented at S.E. Asia Flow Measurement Workshop 2003. 24. "Sampling," Manual of Petroleum Measurements Standards, Chapter 8, Section 8.2, American Petroleum Institute. 25. Guideline Notes For Petroleum Measurements Under The Petroleum (Production) Regulations, Issue 7 ed, Department of Trade and Industry, Oil and Gas Division, UK, December 2003, 24 -30 Principles of Multiphase Measurements Appendix 2 - Terms and Nomenclatures The foUoiNing terms definitions are adopted fTorn the "'Handbook of ßI1ultip!'18Se J1Iletering", developed by the Not1/ve,gian SDclety Emulsion: Colloidal mixture of two immiscible fluids, one being dispersed in the other in the form of fine droplets. Flow regime: The physical geometry exhibited by a multiphase flow in a conduit; for example, liquid occupying the bottom of the conduit with the gas phase flowing above, or a liquid phase with bubbles of gas. Fluid: A substance readily assuming the shape of the container in which it is placed; e.g. oil, gas, water or mixtures of these. Gas: Hydrocarbons in the gaseous state at the prevailing temperature and pressure. Gas-liquid-ratio (GLR): The gas volume flow rate, relative to the total liquid volume flow rate (oil and water), all volumes converted to volumes at standard pressure and temperature. Gas-oil-ratio (GOR): The gas volume flow rate, relative to the oil volume flow rate, both converted to volumes at standard pressure and temperature. Gas volume fraction (GVF): The gas volume flow rate, relative to the multiphase volume flow rate, at the pressure and temperature prevailing in that section. The GVF is normally expressed as a percentage. Hold-up: The cross-sectional area locally occupied by one of the liquid phases of a multiphase flow relative to the cross-sectional area of the conduit at the same local position. Homogeneous multiphase flow: A multi phase flow in which all phases are evenly distributed over the cross-section of a closed conduit; i.e. the composition is the same at all points. 25 -30 Liquid-gas-ratio (LGR): The liquid volume flow rate (oil and water) relative to the total liquid volume flow rate (oil and water) at the pressure and temperature prevailing in that section. Mass flow rate: The mass of fluid flowing through the cross-section of a conduit in unit time. Multiphase flow: Two or more phases flowing simultaneously in a conduit. This document deals in particular with multiphase flows of oil, gas and water. Multiphase flow rate: The total amount of the two or three phases of a multiphase flow flowing through the cross-section of a conduit in unit time. The multiphase flow rate should be specified as multiphase volume flow rate or multiphase mass flow rate. Multiphase flow velocity: The flow velocity of a multiphase flow. It may also be defined by the relationship (Multiphase volume flow rate / Pipe cross-section). Multiphase flow rate meter: A device for measuring the flow rate of a multiphase flow through a cross-section of a conduit. It is necessary to specify whether the multiphase flow rate meter measures the multiphase volume or mass flow rate. Multiphase fraction meter: A device for measuring the phase area fractions of oil, gas and water of a multiphase flow through a cross-section of a conduit. Multiphase meter: A device for measuring the .phase area fractions and flow rates of oil, gas and water of a multiphase flow through a cross- section of a conduit. It is necessary to specify whether the multiphase meter measures volume or mass flow rates. Oil: Hydrocarbons in the liquid state at the prevailing temperature and pressure conditions. Oil-continuous multiphase flow: Multiphase flow of oil/gas/water characterized by the water phase distributed as water droplets surrounded by oil. Phase: In reference to multiphase measurement - one constituent in a mixture of several. In particular, the term refers to oil, gas or water in a 26 -30 mixture of any number of the three. Phase area fraction: The cross-sectional area locally occupied by one of the phases of a multiphase flow, relative to the cross-sectional area of the conduit at the same local position. Phase flow rate: The amount of one phase of a multiphase flow flowing through the cross-section of a conduit in unit time. The phase flow rate may be specified as phase volume flow rate or as phase mass flow rate. Phase mass fraction: The phase mass flow rate of one of the phases of a multiphase flow, relative to the multiphase mass flow rate. Phase velocity: The mean velocity of one phase of a multiphase flow at a cross-section of a conduit. It may also be defined by the relationship (Superficial phase velocity * Phase area fraction). Phase volume fraction: The phase volume flow rate of one of the phases of a multiphase flow relative to the multiphase volume flow rate. Slip: Term used to describe the flow conditions that exist when the phases have different velocities at a cross-section of a conduit. The slip may be quantitatively expressed by the phase velocity difference between the phases. Slip ratio: The ratio between two-phase velocities. Slip velocity: The phase velocity différence between two phases. Supeñicial phase velocity: The flow velocity of one phase of a multiphase flow, assuming that the phase occupies the whole conduit by itself. It may also be defined by the relationship (Phase volume flow rate / Pipe cross-section). Velocity profile: The mean velocity distribution of a fluid at a cross- section of a conduit. The velocity profile may be visualized by means of a two- or three-dimensional graph. Void fraction: The cross-sectional area locally occupied by the gas phase of a multiphase flow relative to the cross-sectional area of the conduit at the same local position. Volume flow rate: The volume of fluid flowing through the cross-section 27 -30 of a conduit in unit time at the pressure and temperature prevailing in that section, Water-continuous multiphase flow: A multiphase flow of oil/gas/water characterized by the oil phase being distributed as oil droplets surrounded by water, Electrically, the mixture acts as a conductor. Water cut (WC): The water volume flow rate, relative to the total liquid volume flow rate (oil and water), both converted to volumes at standard pressure and temperature. The we is normally expressed as a percentage. Water-in-liquid ratio (WLR): The water volume flow rate, relative to the total liquid volume flow rate (oil and water) at the pressure and temperature prevailing in that section. Water Volume Fraction (WVF): The water flow rate relative to the total volume flow rate at the local temperature and pressure. WVF is normally expressed as a percentage. 28 -30 Principles of Multiphase Measurements Appendix 3 - Installation Suaaestions Installation of multiphase measurement systems (multiphase and wet gas meters) should consider steps that would not only maximize the performance but also ease the verification and periodic testi ng (calibration) that may be necessary. These systems may require specific piping and fitting arrangements mechanical supports, and electrical equipment installation. Vendors generally provide this type of information to the users. Operators should require documentation from vendors on piping, installation description, electrical and instrument hook-ups, and accurate cabling requirements. For the rest of this section the discussion will focus on Type 2 wet gas and Group" or III multiphase measurement systems. In a majority of field installations Group I multi phase meters - Le. 2-phase and 3- phase gravity based test separators, are used to verify the performance of other multiphase measurement systems. While Group I multiphase meter installations are outside the scope of this document, when appropriate, issues related to their installations and performances are addressed. The following issues should be addressed in field installations for multi phase metering systems: (a) For consistent performance, the metering system should be sized to cover the range (maximum and minimum instantaneous) of fluid rates expected. (b) Complete system documentation including a detailed P&ID showing all instruments and set points and process conditions should be provided. The P&ID is helpful in identifying the location of critical system elements such as pipefitting, pressure and density measurement devices, control valves, and the operating set point. (c) Gas breakout when flowing through single-phase liquid meters, used in Type I multiphase meters, causes inaccuracy. If the Group I system utilizes gravity separation equipment, the liquid discharge piping from this equipment to the liquid meters should be designed to eliminate gas breakout in liquid meters. 29 -30 (d) Another cause for gas breakout in liquid meters is the pressure drop that occurs between the vessel and the meter. This gas breakout occurs if the liquid line pressure is below the last separation pressure (e) If automatic samplers are used as a part of the multiphase metering system, reference 24 can be used to establish the requirements of velocity and flow conditioning that must be included in the sampler design and installation. (f) Instrument wiring should be installed to minimize electrical noise including proper use of shielding, grounds, and electrical and radiation isolation. (g) There are some special requirements if the multiphase meter utilizes a radiation-based source. These requirements include tracking of the radiation source and general worker safety. Tracking the radiation source can be done by the operator or through an approved third party contractor. These sources must be tracked on and off the property, as well as, to and from the property by a trained entity. While on the property, swab tests are performed for radiation leakage with the swab sent off for evaluation. (h) Safety requirements and regulations related to item (g) may dictate the need for an individual on location who is trained in radiation awareness and safety. Workers in the area may require radiation awareness training. (i) If a gamma densitometer is used in the multiphase metering system, field calibration may be necessary using the well water and gas at temperature and pressure. It is imperative that when calibrating the gas phase the meter be absolutely dry internally. The installation must consider ways of providing this capability. U) Wet gas meter accuracies are affected by the degree of insulation of the meter run and pressure taps from the meter body to the process instruments. (25) Pressure taps are especially affected by cooling which causes liquids to condense in the tapping line. 30 -30