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Home My WebLink AboutCO 402 A• INDEX CONSERVATION ORDER NO. 402A Badami Oil Field 1. July 6, 1998 BP Exploration application for waiver to GOR production limitation for Badami Pool 2. July 23, 1998 Notice of hearing, Affidavit of Publication and mailing list 3. August 30, 2006 Application Report for EMS Multiphase Metering System 4. September 15, 2006 e-mail from AOGCC to operator re: application 5. September 22, 2006 Notice of Hearing, affidavit of mailing, e-mail list, bulk mailing list 6. October 17, 2006 emails vacating hearing date 7. November 2, 2006 Letter of DNR regarding "Application Report" 8. November 13, 2006 Dates when the application report from EMS was sent to company/agency 9. November 30, 2006 BPXA submittal of dates served the company/agency 10. November 13, 2006 3M Unit Field Qualification tests -Preliminary 11. March 30, 2007 BPXA application for EMA Multiphase Metering System (CO 402A-001 Amended) 12. April 26, 2007 Notice of Hearing, affidavit of mailing, e-mail list, bulk mailing list 13. August 10, 2007 BPXA Application Report for EMS Multiphase Metering System (C0402A-002) 14. November 14, 2007 BPXA Application Report for EMS Multiphase Metering System (C0402A-003) 15. March 13, 2008 BPXA Application Report for EMS Multiphase Metering System and subsequent withdraw of request 16. July 8, 2008 BPXA Application Report for EMS Multiphase Metering System 17. January 15, 2009 BPXA's long-term quality assurance program for the Weatherford Generation 2.0 Multiphase Metering System 18. February 19, 2009 Copy of BPXA request to DNR for the Weatherford Generation 2.0 Multiphase Metering System 19. March 2009 Various e-mails 20. April 27, 2009 BPXA Application Report for EMS Multiphase Metering System (C0402A-004) 21. September 27, 2013 Not Used — BPXA no longer operator of field PBU Production Metering Plan Dated 8/1/2002 located in Permanent Field File (PBU) Conservation Order 402A .. e,. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for a waiver of the gas-oil ratio limitations of20 AAC 25.240 for the Badami Oil Pool. ) Conservation Order No. 402A ) ) Badami Oil Field ) Badami Oil Pool August 27, 1998 IT APPEARING THAT: 1. By letter dated July 6, 1998, BP Exploration (Alaska) Inc. ("BPXA") submitted an application requesting a waiver to the gas-oil ratio limitations of 20 AAC 25.240 for the Badami Oil Pool. 2. The Commission published notice of an opportunity for public hearing in the Anchorage Daily News on July 23, 1998. 3. The Commission did not receive any protest or a request for public hearing. FINDINGS: 1. BPXA is the operator of the Badami Oil Pool; the working interest owners are BPXA and Petrofma Delaware, Incorporated. 2. Commission regulation, 20 AAC 25.240, prohibits production of an oil well if the gas-oil ratio ("GOR") of the well exceeds the original solution GOR of the reservoir by more than 100%. 3. Exceptions from the GOR limitation are allowed for pools where an additional recovery project is in operation, if the produced gas is being returned to the same pool or if acquisition of pool perfonnance data is necessary to establish an optimum reservoir management program. 4. The Commission issued Conservation Order 402, dated August 22, 1997, to provide initial rules to begin development ofthe Badami Oil Pool on the North Slope of Alaska. 5. At the time the Commission issued Conservation Order 402, BPXA had not yet fully developed plans for enhanced oil recovery ("EOR") operations in the pool. 6. On June 1, 1998, BPXA applied to the Commission for approval ofEOR operations in the Badami Oil Pool. BPXA plans for EOR operations include produced gas reinjection, watertlood and miscible gas injection. 7. The Commission issued Area Injection Order 17, dated August 26, 1998, approving the injection of water, gas and miscible injectant for EOR operations in the Badami Oil Pool. 8. The owners of the Badami Oil Pool have committed to return all gas less that used for fuel to the pool from onset of production and begin a watertlood within four months of production start up. Miscible gas injection is planned to start in early 1999. f Conservation Order NO.~ Badami Oil Pool August 27, 1998 .. Page 2 9. The owners of the Endicott Oil Pool have agreed to sell gas and miscible il1iectant to the Badami Oil Pool owners for EOR operations. The Commission issued Administrative Approval 202.38, dated August 10, 1998, allowing a gas offtake rate of up to 25 MMSCF per day to supply the Badami Oil Pool with fuel gas and source gas for EOR operations. 10. BPXA plans to obtain additional pool performance data to evaluate and optimize EOR operations. CONCLUSIONS: 1. The operator has committed to gas injection and a waterflood project in the Badami Oil Pool. 2. Granting a variance from the GOR limitations of20 AAC 25.240 will not cause waste, jeopardize correlative rights or impair ultimate recovery so long as EOR operations are begun in a timely manner. 3. Conservation Order 402 may be amended and reissued to allow a variance to the GOR limitations of20 AAC 25.240. NOW, THEREFORE, IT IS ORDERED that Conservation Order 402 be amended to include a waiver of the GOR limitations of 20 AAC 25.240 and that the terms and conditions of Conservation Order 402 be reissued as Conservation Order 402A. The findings, conclusions and administrative record for Conservation Orders 402 are adopted by reference and incorporated in this decision. The rules set out below now apply to the affected area as described in Conservation Order 402. Rule 1 Field and Pool Name The field is the Badami Field. Hydrocarbons underlying the affected area and within the herein defined interval ofthe Canning Fonnation constitute a single oil and gas reservoir called the Badami Oil Pool. Rule 2 Pool Definition The Badami Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of9,500 feet and 11,500 feet in the Badami NO.1 well. Rule 3 Well Spacing Nominal 20-acre well spacing is established for the pool within the affected area. No well bore may be open to the pool within 500 feet of the external boundary of the affected area, or within 700 feet of another well capable of producing from the same pool. Rule 4 Administrative Action Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated in this order or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Conservation Order NO'2~ Badami Oil Pool August 27, 1998 Rule 5 Gas-Oil Ratio Limitation .. Page 3 Wells producing from the Badami Oil Pool are exempt from the gas;.oil-ratio limits of20 AAC 25.240(b) so long as the provisions of20 AAC 25.240(c) apply. DONE at Anchorage, Alaska and dated August 27, 19 ~,~~ Camillé Oechsli, Commissioner AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an 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 lO-day period. An affected person has 30 days ITom 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 from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). · ~~ fÃ\ ~ E ]) f fÃ\ ~fÃ\~ ~~fÃ\ e AI~ASKA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Administrative Approval CO 402A.00l Badami Gordon Pospisil GPB Waterflood Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil, On October 10, 2006, BP Exploration (Alaska), Inc. ("BPXA") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to use a portable multiphase metering system for well testing and allocation of production in the Badami Field under BPXA's original application dated August 30, 2006 for the Prudhoe Bay Field, the Endicott Field, the Milne Point Field and the Northstar Field. 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™ ("EMS TM'). BPXA has proposed the use of a portable MPM 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 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 EMSTM 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 EMSTM. 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 EMS TM 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 EMS TM 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 oftest 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 falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. age, Alaska and dated November 14,2006. Co co 402a-001, co559-003, co570-001, co547-001, co548-001, co550-00... . e Subject: co 402a-00l, c0559-003, c0570-001, c0547-001, c0548-001, c0550-001, c0551~001 From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 15 Nov 2006 13:40:41 -0900 To: undisc1osed~recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.okus>, 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.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <markdalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <markp.worcester@conocophillips.com>, Bob <bob@in1etkeeper.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@in1etkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mike1.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@exxonmobi1.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.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 <itbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <rDURKEE@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>, Shannaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>,JohnTower <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 <jacknewell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, n1617@conocophillips.com, Tim Lawlor <rim _ 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 <roddKratz@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 lof2 11/15/2006 1 :44 PM co 402a-001, co559-003, co570-001, co547-001, co548-001, co550-00... . . <Iris _ Matthews@legis.state.ak.us>, 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@kbbLorg>, 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~dmin.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@c1earwire.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 <:iody colombie(aJadmin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: applicationlpdf co402a-Ol.pdf Content-Encoding: base64 Content-Type: applicationlpdf co559-3 and others.pdf Content-Encoding: base64 20f2 11/15/2006 1 :44 PM . . Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 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 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden HOdgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oil Infonnation Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 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 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 vltestmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 SOldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bemie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 '\~ lA ~\\\\vó . ~V~VŒ (ID~ ~~~~[{~ . AI/A~IiA. OIL AlQ) GAS CONSERVATION COMMISSION SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Administrative Approval CO 402A.00l (Amended) Badami Gordon Pospisil GPB Waterflood Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil, The above referenced administrative approval is amended to authorize the use of a Schlumberger Phase Watcher 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 11, 2007. Inserted text is shown in bold and [DELETED TEXT IS SHOWN IN ALL CAPS AND BRACKETED]. On October 10, 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 multi phase metering ("MPM") systems [SYSTEM] for well testing and allocation of production in the Badami Field under BPXA's original application dated August 30, 2006 for the Prudhoe Bay Field, the Endicott Field, the Milne Point Field and the Northstar Field, and the new March 30, 2007, application which covers all BPXA operated fields other than the Liberty Field. BPXA's applications [APPLICATION] are [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™') and the Schlumberger PhaseWatcher TM . TM VX MultI-Phase Flow Meter (Vx ). BPXA has proposed the use of [A] portable MPM systems [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 well work. The use of MPM rather than a gravity 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 . . CO 402-00 I (Amended) July 9, 2007 Page 2 of3 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 [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 TM 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 TM 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 EMS™ system [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 TM meter system for well testing and allocation on the following conditions: 1. 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™ with a CDS-Gasunie separator system . . CO 402-001 (Amended) 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 Court unless rehearing has been requested. chorage, Alaska and dated July 9,2007. [NOVEMBER 14,2006.] eamount, Jr. ommlSSlOner cc: Art Copoulos, DNR, DOG Robynn Wilson, DOR, Tax Div. Jeffrey Walker, MMS . . Page 1 of 1 Colombie, Jody J (DOA) Colombie, Jody J (DOA) Wednesday, July 11, 2007 7:44 AM 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 Rancier 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 From: Sent: To: 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 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, 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 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 ·Ie~ 1 ~ (f\ 111'Ü . . SARAH PALIN, GOVERNOR AI,ASIiA. 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 ADMINISTRA TIVE APPROVAL CO 547.002 All other oil pools within Prudhoe Bay Field ADMINISTRATIVE APPROVAL CO 548.002 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.002 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.002 All Northstar Pools ADMINISTRATIVE 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 multi phase 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 Commisso has received a timely, properly filed application for reconsideration. rage, Alaska, and dated August 24, 2007. ~ ~~ib·~~;¿'.,~, / /V~ \ I "!\.. . >o~ . CommIssIOner ~.. '...... ...... .~.:;-\~, .";:' ~~ f;;: .~'J . ". i...,>~ ':0 : t· "': '''-, "" ¡ '~~,> ¡.i\~/si,';:'·(Z\¡·. , .,>~ . . Page I of I Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, August 24, 2007 2:29 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'; 'trmjrI'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments: Various Multiphase Metering.pdf; 8/27/2007 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 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 ~f\\~~~\ó\ • ~V~ ®~ L,i~i/ `~V CO1~T5ER~"A7[`IOleT CODIIrII55IO1~T SARAH PALIN, GOVERNOR r` r J 1 333 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 54$.003 All 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 Ordert 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 rule 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, 200 i 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 Cowunless the Commission has received a timely, properly filed application for reconsiderat' n. ~ Alaska, and dated November 27, 2007. /i L~_, Daniel T. Seamount, Jr. Cathy P Foers 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 B{vd., #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 Rsverview 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 Arctic Slope Regional Corporation Land Department PO Box 129 ~j Barrow, AK 99723 ~ i ~ ~ n " I ~ ~ ~' i ~ • Page 1 of 1 Co{ombie, 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 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'; '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 Po 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:Various Prudhoe Admin Approvals.pdf;aio4e-O15.pdf; 11/28/2007 r 7[F nlAsEA SARAH PALIN, GOVERNOR LASS OII, AND GAS 333 W 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, 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 550. 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 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 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 Order' for all North Slope fields to help determine if these By original Conservation Orders 547, 548, 449, 550, 551, 552, 559, 570 and by Administrative 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 1 Approvals are unchanged. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further i 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` day following the date of this decision or on the next working day if the 23` day falls on a state holiday or weekend. A person may not appeal a Commission decision to the Superior Court unless the Commission has received a timely, properly filed application for reconsiderati n. •O E •r. _e, Alaska, and dated Nove 1 eer 30, 2007. fl 4i i or an P ie T. Se. ount, Jr. Cathy P. Foerster Chai Commissioner Commissioner e �m OIL .4 li elc.,. 4 t M. T� JIV t :t }N 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= foms @mtaonline.net; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite 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'; 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- 005.pdf; 11/30/2007 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 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 i ce el 1 1 /5% 2 D i Al.__,ASEA SARAH PALIN, GOVERNOR �T ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION 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 utilized for production well testing and allocation. Because no 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 e-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 long, 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: a near 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: http: /www.state.ak.us/ local akpages /ADMIN /ogc/MeterGuide.shtml. 2 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 October 29, 2008 Page 3 of 10 V -Pad field trials liquid dominated regime, high gas volume fraction (GVF) 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 ±7% for the gas rate and ±8% for the liquid rate. The ASRC Unit 1 estimated uncertainties are ±3% 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 ±2 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 ±5 Liquid rates were within ±10% (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. 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 http: /www. state. ak. us local akpages /ADMIN /ogc /MeterGuide.shtml. Gordon Pospisil Technology Resource Manager October 29, 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 ±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 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 ±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 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. s�ftil .11� Daniel T. Seamount, Jr. Cathy P. Foerster o.. 4 0 an Chair Commissioner ommi ner 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 rums until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. M.AS/f O' 7'Cli 4 44 ti >tSSt ill Gordon Pospisil Technology Resource Manager October 29, 2008 Page 7of10 Attachments Figure 1 Comparison All Tests Liquid Rate STB /D vs Unit 1 Liquid Rate, STB /D Gen 2, V -WPS 2500 2000 1 1500 A-7---31 Q -10% 1000 I Gen 2 Sadlerochit IN Gen 2 Kuparuk A Gen 2 Schrader 500 V -WPS 1 Sadlerochit E V -WPS Kuparuk A, V -WPS Schrader 0 r I 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 4000 3000 1 2000 co cc E Gen 2 Sadlerochit cn a Gen 2 Kuparuk 1 000 Gen 2 Schrader V -WPS Sadlerochit O V -WPS Kuparuk 0 W V -PS Schrader 0 1000 2000 3000 4000 Unit 1 Gas Rate, Mscfd STB /D EV Gordon Pospisil Technology Resource Manager October 29, 2008 Page 8 of 10 Figure 3 Comparison All Tests Water Cut vs Unit 1 Water Cut Gen 2, V -WPS 100 F 80% II O 60% 4 is -10% v i Gen 2 Sadlerochit 40% Gen 2 Kuparuk Gen 2 Schrader V -WPS Sadlerochit 20% V -WPS Kuparuk V -WPS Schrader 0% Z y I 0% 20% 40% 60% 80% 100% Unit 1 Water Cut, Figure 4 Comparison All Tests Error Flow Rate vs Unit 1 Water Cut Gen 2, V -WPS .4-1- 10% 60% Gen2 Sadlerochit 40% Gen 2 Kuparuk Gen 2 Schrader —1 ig 20% j II i N 4 -20% -40% -60% 0% 20% 40% 60% 80% 100% 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 -WPS 60% 10% 40% Gen 2 Sadlerochit Gen 2 Kuparuk t 20% Gen 2 Schrader 1 0% N C7 -20% -40% 60% 80% 90% 100% Gas Volume Fraction (GVF) Figure 6 2 Well wet gas meter test vs. pad separator gas rate 50 45 40 tsi 9 0 35 30 25 ry 20 O 15 0 10 5 0 0 5 10 15 2D 25 30 35 40 45 50 Test separator gas flowrate (MMscf /d) G ordon Pospisil Technology Resource Manager October 29, 2008 Page 10 of 10 Figure 7 Well wet gas meter test vs. pad 3 separator liquid rate 1200 1000 a in W O 800 All these points within t10% o 1 cr 600 unreliable low liquid Q rate from test W separator 0 D ..r V -cone transmitter 0 0 U 40- O suspected out of range c O o U 200 V -cone transmitter Liquid rate verged 0 certainly out of with ASRC Unit 1 range 0 0 200 400 600 800 1000 1200 Test separator liquid flowrate (stb /d) Figure 8 Well wet gas meter test vs. pad 4 bP separator GOR to 100000 90000 80000 :s000 a a 70000 m o. 0 60000 V -cone transmitter 0 suspected out of Q 50000 range O cc O a- 5+ 40000 to 0 30000 U 20000 10000 0 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 Test separator GOR (scf /bbl) Yage1of1 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 @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 =foms @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 @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 :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 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 North Slope Borough K &K Recycling Inc. PO Box 69 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 /eye /0 SLialT1 DT SARAH PALIN GOVERNOR ALASKA Ou AND Gi.S 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 CORRECTED 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: 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 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.' 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. 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 e-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 long. 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 cugg' sts the AOGCC 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. Findings The Gen 2 is an in -line MPFM consisting of four principal components: a near 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: http: /www.state.ak.us/ local akpages /ADMIN /ogc/MeterGuide.shtm[. 2 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) 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 ±7% for the gas rate and ±8% for the liquid rate. The ASRC Unit 1 estimated uncertainties are ±3% 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 ±2 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 ±5 Liquid rates were within ±10% (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. 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 http: /www.state.ak.us/ local akpa ges /ADM1N /ogc /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 ±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 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 ±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 of the submission to the Commission, be under this order must, at the time o provided to all p 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. h p:A Ott DONE at Anchorage, Alaska and dated November 3, 2008. 1 p Daniel T eamount, Jr. Cathy Foerster Jo K. Norman 1 'A Chair Commissioner 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), "[tlhe 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 November 3, 2008 Page 7 of 10 Attachments Figure 1 Comparison All Tests Liquid Rate STB /D vs Unit 1 Liquid Rate, STB /D Gen 2, V -WPS 2500 2000 A 1500 1 A -Q B 1000 Fs -1 Gen 2 Sadierochit Gen 2 Kuparuk 4 A Gen 2 Schrader 500 V -WPS Sadlerochit E V -WPS Kuparuk A 1 A V -WPS Schrader 0 I I 7 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 4000 3000 A A 1 A 10% 2000 ft lY Gen 2 Sadlerochit o --1=-. 3 Gen 2 Kuparuk 1000 W Gen 2 Schrader V -PS Sadlerochit 0 V -WPS Kuparuk V -WPS Schrader 0 f 0 1000 2000 3000 4000 Unit 1 Gas Rate, Mscfd STB /D Gordon Pospisil I Technology Resource Manager November 3, 2008 Page 8 of 10 Figure 3 Comparison All Tests Water Cut vs Unit 1 Water Cut Gen 2, V -WPS 100% 80% +1 -10% Gen 2 Sadlerochit "a 40% Gen 2 Kuparuk Gen 2 Schrader V -WPS Sadlerochit 20% V -WPS Kuparuk a V -WPS Schrader 4- 0% 0% 20% 40% 60% 80% 100% Unit 1 Water Cut, Figure 4 Comparison All Tests Error Flow Rate vs Unit 1 Water Cut Gen 2, V-WPS -10% 60% Gent Sadlerochit 40% 40% Gen 2 Kuparuk A Gen 2 Schrader 20% L Ira mounemi -1•1111•1- 4111111111111111111 -20% -40% -60% 0% 20% 40% 60% 80% 100% Unit 1 Water Cut, Gordon Pospisil Technology & Resource Manager November 3, 2008 Page 10 of 10 1200 a 1000 a R 800 0 0 n Cr 600 Q K U 400 0 0 U > 200 0 -L 0 Figure 7 All these points _ within t10% O O' unreliable I low liquid rate from test separator O V-cone transmitter ___ _ O suspected out of 0 range O 100000 a 70000 a 0 60000 L9 50000 o_ U 40000 m 0 30000 U 20000 10000 0 V-cone transmitter Liquid rate veriMd 0 certainly out of wkh ASRC Unit 1 range 200 400 600 800 1000 Test separator liquid flowrate (stb/d) Figure 8 ts000 O V-cone transmitter suspected out of range j 1200 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 Test separator GOR (scf/bbl) Page 1 of 1 4110 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= foms @mtaonline.net; 'Marilyn Crocket; '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 @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 w S 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 North Slope Borough K &K Recycling Inc. PO Box 69 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 /2/al k //4/1/2 #21 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 6*112' opera far or die/c�! P 0 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: 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, y� Katrina Garner, 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$ 20 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. Chairman Alaska Oil Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Re: Supplemental data II for EMS 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 EMS 3/24/09) was prepared to address questions the AOGCC requested for the EMS ASRC Unit #5 and was sent to Jane Williamson of the AOGCC on 3/24/09. The information provided in the 3 reports (EMS Field Trial Results 5/13/2008, Supplemental data for EMS 12/03/08, and this report Supplemental data II for EMS 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 EMS ASRC Unit #5 can reliably conduct production well testing at any BPXA operated North Slope location. BPXA is requesting that the FMC Technologies System (EMS subject to the constraints identified in Report Supplemental data II for EMS 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 Meeting and Request for Hearing 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, 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 Supplemental -2 Data for the AOGCC Report 03/24/09 ASRC Unit 5 Field Qualification 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 for 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 map 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 multiphase 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 measurements. 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 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 TopFlow 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. 0 6. The liquid and gas measurements are within 10% of the ASRC Unit 1 and tank tests in the initial report to AOGCC. However due to lack of good as noted p 9 reference measurements at very low gas rates(Iess 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. Page3of AOGCC Report 03/24 2009 Table 1 ASRC Unit 1 Test Results Sep Liquid Gas Press- Sep Ave Well Date %WC BPD Oil BPD MSCFD PSI Temp 'F GOR %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 -08 2007 -08 -11 66% 1858 632 101 269 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% 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 Est Liquid Gas Sep Press Sep Temp. API Live Oil Reynolds Well Date %WC BPD Oil BPD MSCFD PSI DEG F GOR Gravity Ave %GVF Mix Vis cP Vis 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 MP -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 12/18/07 49% 342 181 143 300 62 791 21 82 179 37 140 MPI -06 12/15/07 57% 324 139 122 298 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 88% 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 1 Page 4of8 1 AOGCC Report 03/24 2009 Table 3 Gas Removal Efficiency of CDS Separator Gas Removal Efficiency CDS Ave.Line Ave. TF Ave Well Date Tested GVF GVF 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% MPS -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% 90 8,0 o '"i 1 80 v o i o o 0 4 70 MP -B t t A x a X x o MP-E X 4i'F x 7 Q t Se 50 XMP -G 44 A 3. 44 r,MP -H 1 A LiX X ♦X X 3 X i< c 4� •MP I i A s X x X )t 5 30 +MP J X t t� r o MP K P k 20 a MP -L 10 oMP MSS az 0 20 40 60 80 100 GVF Figure 1 Map of WC and GVF for all Milne Point wells tested Page 5 of 8 AOGCC Report 03/24 2009 MPC -22, 081128 100 ..s ii i I i.:: iz f 1 4, sr irk 4 7 t its 4 i i 1 iii .1 ill t t: ?1 SSE �4��'':',. i s i i i t eil 20 1 f III 0 7:12 8:24 9:36 10:48 12:00 13:12 14:24 Line GVF TF GVF 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 100 MP -B 90 M 4D-C $0 o MP -E iCb MP x j 70 MP -H A U 60 M P -I k a. P CC t 50 0 MP-K j 40 M P -L to o MP -S 30 E, u) 20 D 10 4 0 P I 1 0 20 40 60 80 100 Sample water cut Figure 3 Water cut uncertainty for all tests at Milne Point Page 6 of 8 AOGCC Report 03/24 2009 50 MP -B MP -C i1 MP -E MP -G 1 MP -H MP -I 40 -i MP -J MP -K MP -L c MP -S 5% 0 u 30 a 20 P h 10 4 U t 3 -10 c a 2 -20 0 CO -30 -40 -50 r Nov -2007 Jan -2008 Mar -2008 May -2008 Jul -2008 Sep -2008 Nov -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 1 AOGCC Report 03/24 2009 Appendix 1 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: 1) 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 X19 RE: Supplemental data II for FMC Enhan ed Multiphase System (EMS) used in ASRC 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 you 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, I'll 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? I'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 work.) Else, give me a call next week (793- 1226). Jane Original Message From: Brady, Jerry L [mailto:Jerry.Brady abp.com] 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 Enhad Multiphase System (EMS) used in ASRC Unit #5 and requ... Page 2 of 2 Jane, «cover leterNote to Jane on Supplemental data for ASRC Unit #5pm (3 lemental Data II for EMS 03- 24- 09.doc) .doc» «Su PP 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. Jerry Brady 5/4/2009 Supplemental data II for FMC Enhanceddultiphase 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 Multiphase System (EMS) used in ASRC Unit #5 and request to use Unit #5 in additional fields Attachments: cover leterNote to Jane on Supplemental data for ASRC Unit #5pm (3).doc; Supplemental Data II for EMS 03- 24-09.doc Jane, «cover leterNote 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 EMS 3/24/09) was prepared to address questions and data you requested for the EMS ASRC Unit #5. The information provided in the 3 reports (EMS Field Trial Results 5/13/2008, Supplemental data for EMS 12/03/08, and this report Supplemental data II for EMS 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 (EMS 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 (EMS subject to the constrains identified in Report Supplemental data II for EMS 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 OiI Pool Amendment to CO 548 Endicott OiI Pool 5/4/2009 Supplemental data II for FMC Enhancedoultiphase System (EMS) used in ASRC Unit #5 and request t... Page 2 of 2 Amendment to CO 550 Milne Point OiI Pool Amendment to CO 551 Northstar OiI Pool Amendment to CO 559 Put River OiI Pool Amendment to CO 570 Raven Oil Pool Amendment to CO 402A Badami OiI Pool If you have any questions, please give me a call. Jerry Brady 5/4/2009 Jane, The attached report (Supplemental data II for EMS 3/24/09) was prepared to address questions and data you requested for the EMS ASRC Unit #5. The information orts ided in the 3 rov reports EMS Field Trial Results p p 5/13/2008, Supplemental data for EMS 12/03/08, and this report Supplemental data II for EMS 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 (EMS 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 (EMS subject to the constrains identified in Report Supplemental data II for EMS 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 OiI Pool Amendment to CO 548 Endicott OiI Pool Amendment to CO 550 Milne Point OiI Pool Amendment to CO 551 Northstar OiI Pool Amendment to CO 559 Put River OiI Pool Amendment to CO 570 Raven OiI Pool Amendment to CO 402A Badami OiI Pool If you have any questions, please give me a call. Jerry Brady x„18 RECEIVED FEB 2 5 2009 bp Alaska OiR f. Co .C1 t. fission A 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 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 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 Bluff) 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 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. BPXA Request for Clarification Meeting and Request for Hearing Page 3 Thank you for your assistance. Sincerely yours, -)„,,,z,;(- Gordon Pospisil Technology Resource Mgr. BP Exploration (Alaska) Inc. 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 Scott Millington, 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 bp Gordon Pospisil Technology Resource Manager BP Exploration (Alaska) Inc. BP Exploration (Alaska), Inc. 900 EpB Boulevard Anchorage, Alaska 99508 Tel: (907) 564 -5769 Fax: (907) 564-5706 Ema)l: gotdon.pospisil ©bp.com July 8, 2008 Dan Seamount, Jr. Chairman Alaska Oil Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 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 a 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, 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 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, 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, ExxonMobii 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 Division 40 BP Alaska AOGCC "Application Report" for the Weatherford Gen 2 Multiphase Metering System 7/15/2008 070808 AOGCC Gcn2 .1pp Rpt.doc 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 5. Factory Acceptance Tests (FAT) 10 6. Field Maintenance and Periodic Calibration 10 7. List of References 11 8. List of Appendices 11 2 of 1 1 }P ,(I 4..!1 1d ;ii 1{i)F.(teii AOGCC 'Application Report" for Gen 2 Multiphase Measurement System 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 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 1A 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 3 of 11 4) 0808 ;10G( C ;en2 .1pp Rpt.doc 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. 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 used 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 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 0 ?O8o8 NO( ;CC (;4.112 app Rpt.dL,u 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 0 0 Absolute t Line) Pressure Differential Pressure Encapsulated Temperature s o Sonar Sensors ai 0 RedEye Watercut Probe Photomultipller 3 0 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. 5 of 11 070808 .tOGCC (A:112 :%pp 104.a1pI. 1 1( 1 11014 111 t 1 �t s t e� Aipir 1 Ill iiihh, 2 ii ti p` i .,''!br s. 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 11 070808 AOC( C Gcn2 App R t.doc PP P Table 1- Summary of wells tested, time, and duration Well Test date I Test times I Test dsration Pruratoe Bay V .Pad lfvishde V -01 Well not available V -02 01 -31 -2008 03:00 11:00 8 hours V--0;3 02.03 -2008 14:03 22:00 8 hours V-04 01.2.2008 15:03 23:00 8 hours Prudhoe Bay V .Pad p(uawkl V -101 02-05 -20013 21:03 05:00 8 hours V -102 01 -29 -2008 11:00 19:03 8 hours Of -29- 2008 03:03 0353 Test abandoned V -103 by lint 5 operator 01 -31 -2008 1 6:00 03:00 8 hours 01- 30.2008 00:00 0890 Urst 1 and Unit 5 V -105 bypassed 01 -30 -2008 13:03 2190 8 hours V -107 Wer not tested V- 108 02.04 -2008 1 04:00 12:03 1 8 hours V -109 Wel not tested V -111 02 -04 -2009 18:00 02:00 8 hers 01.25 -2008 16:00 19:15 FOS trip test V -113 abandoned 01- 27.20013 12:03 2090 8 hours V -117 Wei net avat1 bie V- 122 02- 05.2008 08:03 1890 8 hours Prudhoe Bay V?ad (Schrader mutt) V- 202 02 -01 -2008 05:03 13:03 8 hours V -203 01-28 -2008 02:00 -1090 8 hours 02- 02.2008 12:00 2090 8 hours V- 204 02 -01 -2008 20:00 04:00 8 hours V- 205 02- 03.2008 01:00 09:00 8 hours 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 Uncertainty Relative to ASRC Unit 1- Gas Rate Liquid Rate Water Cut Gen 2 ±7 ±8 ±5 V -Pad Separator ±9 ±14 ±9 Estimated Reference Uncertainty ASRC Unit 1 ±3 1 ±5 ±2 7of11 070808 AOGCC' Gen2 App Rpt.doc 5000 ks FT;an;0 p1s:NfnM( to FT Gte p[S:kupl IJ; NFT Oen.Opta:tx tfaexs.5& 4030 g 3500 l n 4 3000 a 2500 2000 d 1500 a al a a t7 1 00D 500 0 o soo loco 1500 2000 2500 3000 3500 4000 4600 s0e Unit 1 gas flowrate (Mead) Figure 4 Gas flow rates from Gen 2 X019. EtB +N FT Gm .9 pas ;NNW*: 5t 5 0•1 Om :kKwu: 30% E1.5 6o, 1:D pas ;km Et ...ear; S 213% ".Tom t03; a■ 5 N 20%• S -30%. .ION -50% 50 SS 60 fib 70 75 50 55 50 55 100 Unit 1 GVF fit) Figure 5 Gas flow rate accuracy as a function of GVF 3500 OFT 'ue n;<i Iwo 146no: x00 /l FT tit rck i(0e/;KY K luk; a OFT Curt 1'J pills &nemo.eun .0 .i IDs. 7: 0 1500 L woo a a 500 I 0 0 500 1000 1500 2000 2500 3000 3500 Unit 1 liquid flowrafe (scald) Figure 6 liquid flow rates from Gen 2 8of11 070808 AOGCC Gcnl App Rpt.doc 50% 40% 51EuMFT6tP D Nan :t.orfac E M Ft GM: OktYU161.441144; 6t6•■FT Gtr: 6 yW;9epnpet.8art, 2O% tom 1045 .s e3 -204. (9 -40% -50% 50 5d 60 66 70 75 50 !6 AD 96 100 Unit 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. 100% s go% FT GH, nak4 SJ;fttf.; OFT Ger,:: wtltllJ ;ki{c tot,: lDic /OFT Gen:. war W1 70% —x. 5w 7 60% Y 50% arnn e S 32% 20% 10% a et. o• 04; 10% 20% 30% 10% 50% 60% 70% W% 100% Unit 1 water cut Figure 8 WC measurements from Gen 2 9of11 070808 AOGCC Gent App Rpt.due 50'8+ F 10%• -----------------------;—•--•---I--- 076 w cyFT Gen 1Y/A■ cut:1•Ste Y, Q an: 7 ••N aut {n414u1.1 {01 !le n:Jwa• ta4&nteffi7•tH; -SOYi 50 60 65 70 75 a3 e6 90 96 103 Unit 1 OW 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. 10 of 11 070808 AOGCC Gent 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),O. H. Unalmis, D. J. Rodriguez, A. Vera, V. Ramakrishnan (Weatherford Intl.) ,25 International 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 meter solves old problem impacting well test accuracy," Ward, E., SPE paper 100893, 2006 SPE Western Regional/AAPG 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" 25 International 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 meter solves old problem impacting well test accuracy," 11 ofll 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 (Elder) 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 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 36.402687 100 LPC Tract Operations 640147 GPMA Ivisfiak -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 26.380567 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 Lisbume 640144 Usbume 12.5% Separate 26.360567 1.16 36.076746 36.402687 100 Milne Point MPU Kuparuk 525100 Milne Point Kuparuk 12.5% 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 99.269596 0.730404 100 Milne Point Tract Operations 525160 Milne Point Ugnu, undefined 12.5% Separate 100 100 Northstar Northstar 590100 Northstar 20% plus supplemental Separate 98.5772 1.4228 100 LPC Prudhoe GC-1 Point McIntyre 640180 Point McIntyre 12.5% to 16.67% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402687 100 Prudhoe All GC FS Prudhoe IPAs (OR/GC) 640150 Sadleroch8 12.5% Consolidated Prudhoe 26.360567 1.16 36.076746 36.402887 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 26.380567 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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Inc. 20.1]2]% d. �f I 2 02NOn0oWI 10.4325% KUPARUK RIVER UNIT Malmo 3.0045% r J I MM.. PA•PA... U I 1.]742% t s 8PXA Cartography/Im15O98_2038.dgn 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. IJnalmis, 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 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 ±0.5 m in Type I wet gas,' and better than ±20% 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 ±5% water cut uncertainty in high GVF multiphase 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 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. -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. 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. 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 processing electronics 1 111 LA !ham e r A d axial location of Venturi nozzle Sonar array 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 5% NEL -Brine 4% NEL Oseberg NEL Nitrogen 3% 0 Weatherford Water Weatherford -Air 2% A CEESI Natural Gas t t 1% Ili 1% A 8 B a 0% A A o A A u 1% m d -2% rt -3% -4% -5% 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. Venturi The extended throat Venturi- nozzle performance was verified with the same dataset and was found to measure single -phase flow rates within ±1.4 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 V 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 I 100 e t 5% absolute error 90 o Red Eye 2G, NEL, Aug 2005, Horizontal 80 A Red Eye 2G, NEL, Aug 2005, Vertical R 70 9 60 c 50 a; o, 3 40 E 30 0 g 20 10 0 I I 1 i 1 F i i 1 0 10 20 30 40 50 60 70 80 90 100 Reference Water Liquid Ratio, Figure 3 Performance of water cut measurement 2 15 e t 5% absolute error o Red Eye 2G, NEL, Aug 2005, Horizontal wz 10 a Red Eye 2G, NEL, Aug 2005, Vertical E e e a e 5 e e e P G e o° e !g ui e CO e o 0 e A., `o s.. 0 e e e '141, A a Bo W e e e e Ne A° Dotal e o o C o A 0 1:1 ce -5- o n •p 0 o 0 0 c 0 -10 d 3 -15 1 i I I 4 I i I I 0 1 0 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. Even those points at the highest GVF do not constitute wet -gas flows with Lockhart- Martinelli 1 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 NEL 10 CI p o CEESI CP O ale 1 B 1 GVF 1 u 800 G q GVF 50% a a e 0 �o GVF 90.9% A e ct 0.01 a e A a A B GVF 99.0% A c N a 0.001 GVF 99.9% GVF 99.99% 0.0001 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, Fr and a relatively high Lockhart- Martinelli parameter, XLM. The CEESI test envelope, on the other hand, covered Fr and XLM within the regions defined by API as Type I and Type II wet -gas flow. CEESI NEL Pressure 14, 28, 55 bara 2 7.5 bara Temperature 28 -35 °C 22 -42 °C WLR 0 —100% 1, 40, 75, 100% GVF (no slip) 97.5 -100% 0 100% Total Volume Flow Rate 85 -655 m 14 460 m Liquid/Gas Density Ratio 16 at 55 bara 106 at 7.5 bara 40 at 28 bara 485 at 2 bara 98 at 14 tiara Frg Sonar 1.5 20 0.07 -2.6 Frg Nozzle 0.5 -5.5 0.02. -0.7 XLM 0 0.26 0.3 -167 LMQ 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. N CIRCU_ATION HEAT (COALESCING TURBINE ULTRASONIC COMPRESSORS EXCHANGER EI_TER l METER METER GAS CHROMATOGRAPH 2" 0.5" TRIPLEX PUMPS FOR CORIOLIS CORIOLIS METER METER N HYDROCARBON GAS LIQUID LIQUID E3 SEPARATOR _E LIQUID-LIQUID N SEPARATOR 1.• TRIPLEX 2" 0.5" ►1 PUMPS CORIOLIS CORIOLIS PUM UM METER METER N FOR WATER TEST TEST TEST TEST TEST _OCATION 5 LOCATION 4 LOCATION 3 LOCATION 2 LOCATION I 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 1 „ow .„--7 1 r 4 ..r t Ma, I/ ti v r. 1 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 AP. 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 ORV Qg,apparent (1) Qg,ref with ORV f,(X,Fg), (2) where the Lockhart- Martinelli parameter is defined herein, as: x= m l ip g (3) m 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 Qt apparent (4) Qt,rej Qt,apparent =V m A ORS f, (LMQ, Fr (6) LMQ 1 m 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 rP 1.3 0 0 1.25 1.2 A 0 a 1.15 m 1.1 0. A A O 1.05 is 1 0.95 0 Nozzle A Sonar 0.9 0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 Lockhart- Martinelli, 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% o 14 bare e 27 bare 55 bare t5% re 5% 3 O 1:::1; O c 0% m re -10% 1 1 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% o 14 bare A 28 bare 55 bare w 5% t5% C u co 0 5. 0% $4 444 I c t +4. w d -5% -10% 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 flow rate relative error for wet gas. 10 40% 14 bare 30% a 28 bare 01 55 bare m t 20% 3 20% o T. A -4 o- g o w -10% A -20% re -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 e Liquid flow rate relative error for API Type II wet g q YP gas. g 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 ±20% 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 ±0.5 m 1.0 1 14 bare F 4 28 bare 55 bare 1 0.5 t 0.5 m /h CC o f' en Q 0.0 -1- m c t 8 W y -0.5 z o N .0 -1.0 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 97 <GVF <99% A 99%<GVF <99.6% 1.0 99.6 %<GVF <100% f0.5m'Ih n+ 0.5 LL Q 4, A D e Q A q. 7 a- ir 0.0 J A o o 6 w` -0.5 2 o 1 0 Q 1.0 -1.5 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 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. 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 it 4 x /a} l 11 111 'W. UP„ a 1 eT 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 250 to 200 ai ih+ 3 _p 150 t 0 <GVF <60% To e n 60 <GVF <80% I- 100 f:: 80 <GVF <100% Reference 50 t 20% 0 I I 1 I 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 ±20% for GVF <80 however, at higher GVF the measurement is erratic. The velocity reported by Sonar at these 13 0 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 0 100 E 80 0' 3 60 _o 0 0 %<GVF <60% J 40 0 n 60 %<GVF <80% p 80% <GVF <100% 20 Reference -±10% 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. 400 350 300 E 250 0 r2 200 3 o o 0 0 <GVF <60% 1 150 .r R -A a 60 <GVF <80% 0 of t 100 80 <GVF <100% A, Reference 50 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 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 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 ±20% in API Type II wet gas and ±0.5 m in API Type I wet gas. In multiphase flows, liquid and total rates are predicted to better than ±20% 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 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, [m 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 MR Near Infrared ORS Over Reading Sonar, ORV Over Reading Venturi, Q Volumetric Flow Rate, [m /s], [m V Velocity, [m/s] WLR Water Liquid Ratio, 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 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, 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 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 Production John Lievois, eProduction Solutions Babajide Adejuyigbe, eProduction Solutions 1 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 0-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 0-H bond stretch, so there exists the potential for water to be distinguished from other molecules, such as methanol, containing 0-H bonds. The Red Eye 2G water cut meter extends the performance of the earlier 1G 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 —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). 1 6th 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. 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 9 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 11/2-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 11/2-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 %Z -inch, 1 -inch or 3- inch depending on the flowrate required. The '/z -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 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 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 t1% 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 gas, temperature and of the as is measured at the flowmeters. The volumetric P pressure 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 (MgSO 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 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 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 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 ±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 measurq, 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 0 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 f l 12 c g a 0118 o a m 6 ell 3i 1 Condene 0 800 1000 1200 1400 1600 1800 2000 wavelength (nm) Figure 1: Near infrared absorption spectrum "I V soft i 1 .f r Fiber Optic Bundle sous water r Collector Optics TIEVIt status r I I Probe Assembly Sapphire Window Sapphire Windowr 4 MR Emitter i 1 t Figure 2: Red Eye water cut meter cross section 6 6` South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 I 41' 0 .,..MMq fir! 7 e b 111111 R m 1 1 i Ill :A. Figure 3: Red Eye meter installation (August 2005 horizontal test) I ,z,.. 4 4: vs X t J V 7 r j t :Ire ^I 'fi" x- Figure 4: Red Eye meter installation (August 2005 vertical test) 7 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 1 lie w r M II ..rrrllrllr. M r 0 I1 1. e r 4- w 0 't !P a tit 4 K` A iik Figure 5: Red Eye meter installation (February 2006 test) all el Vie j J 4 i t F Figure 6: Red Eye meter installation (November 2006 test) 8 1 0 0 6th South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9 March 2007 5% water cut 25% water cut 1" r 0 r i 6111.00 2006 Au nos 40 I 1 eve 1-- m. sa i o a 2 0 A Hewn. S13 1 as se.: .0680 2005 r 1 40 .2 ma. Feb 2006 o r% .3 MI... 1.2006 0 6.0.3061 Nov 2006 000 A 0 006 0 00 0 A o al• 0 4. 4 01 .ao• oa 0 m 4 1 C 0 0 0 203 SO 1 i S 0 A v. i 4 0 1-0----11 10 0 a- --s, g V 5 o o 0 1 12 0 27 00 000 14 C, 16 0 16 0 0 0 o o 8 a• a 18 0 .0 0 20 30 0 50 60 70 80 90 100 0 10 0 30 40 50 60 70 80 90 100 GVF (IC) GVF (V.) 40% water cut 50% water cut I ....a 802006 I 0' I ..ma mre soos I s 1 2 0 4 0 .........20.6 1-- II 23 0 sr. 11 05.080, Nov 2008 i 6, e SI I 1.20.. Nov 005 6 to A a to go I, Ss st 4 n 06 4 0 ss 3 6 c 60 a i B 0 0 0 1 8 0 10 0 1 140 1 g 14 0 .0 16 0 .0 18 0 18 0 0 10 2G 30 /V 50 60 70 80 90 100 0 10 20 30 40 70 60 90 100 400 (64) 600 60% water cut 75% water cut g 1 i a•maa• Seb M. 1 60 08.0..• 2005 I a 2 0 •I 2 0 3350.00 is. 2006 I L ....la. Nov2006 j 0 So OW.. Nov 2006 1 s 6 A a 0 4 0 0 e A 00 06 0. ol A o 'SF 6 0 0 1 1 0 1 10 0 IGO 120 g 020 0 1-1 0 16 0 16 0 18 0 18 0 0 10 20 30 40 60 70 60 90 100 0 10 20 30 50 80 70 110 90 100 090 (64) 060 (64) 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 90 I .1100.3 1F..2006 1 2.0 I .XUbmYI. FC AO! It 10 g ES '0 B ao 8 e° I a e ua 4 12.0 0.0+ 160- 0 10 A 30 M 60 W 1O 90 90 100 0 ,0 20 00 a 50 60 N 10 90 100 GVF OK 90% water cut 92.5% water cut 2005 I 0— •1010.01.1.F.5.X0 .MU1.e11.1.xv.300F a a.. O. as I 10.0 14 0 14 a 16 0 3 0 10 20 b w SO b 70 So 1b tan 9 10 °o n a 50 >o 00 90 100 aK GK I 95% water cut 97.5% water cut 30 I NO 2006 I 100 .1 100 3 12.0. 100 1.0 1.0 100 1w 100 12.0 0 10 30 A 10 60 w N !O 90 100 0 10 A 00 •0 50 00 M 00 00 100 OK GK 100% water cut :a O1xm..9..5 .....9 .�M1 Fab BOOS .000.1.1.010. 8 20 0 I co a c c a 10.0 o- 0 120 C 0 0 0 1.A 1F0' 0 a a a 160 0 t0 20 30 40 50 90 A FO 90 100 GK 10 IP 11 6th South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 1 nap I. A „..........„.„,,.....4,„ ,.......„..i.,..„....._,.„.......,„ 4.1.8.› om Figure 8: Location of multiphase flow meter test facility Pressure and Three phase separ4or r f low cont rol 1 1 rii Liquid Test meter vats Qii nitrogen II Reference metering WWI 11.11111.11111111L Pump Pump Test meter ii 0 -;t Gas 14 R-- Figure 9: Schematic of TUV NEL multiphase flow test facility i 11 6th South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 100 ro 5% absolute error 90 Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical J 80 70 e 60 u d 50 m 40 30 o 20 10 0 l i I I 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 +1 5% absolute error 20 a Red Eye 2G, NEL, Aug 2005, Horizontal u i X Red Eye 2G, NEL, Aug 2005, Vertical C 15 m w m 10 x x x x x x 5 X x aX `x x x x x xBE x o x x o a 0 3 o o a o p o 0 ltr -10 U u d -15 m 3 -20 -25 r 1 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 25 «1 5% absolute error 20 O Red Eye 26, NEL, Aug 2005, Horizontal d O X Red Eye 2G, NEL, Aug 2005, Vertical m 15- at w E.' 1° o x 7 x cb A a O 5. d -10 U u d -15- Cs 3 -20 26 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 «4. 5% absolute error 90 1 Red Eye 2G, NEL, Feb 2006, Horizontals' 80 70 e 60 v 50- m 40 30 20 10 0 l l 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 6`" South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 25 r i a 5% absolute error 4 20 U I Red Eye 2G, NEL, Feb 2006, Horizontal 15 d m E 10 2 O 5 F 7 e 4 In 0 •Ili f. s e 4.1. fr• r m -10 u d -15 To -20 -25 I l 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) 25 I *1- 5% absolute error 20 J I Red Eye 2G, NEL, Feb 2006, Horizontal C 15 w w E 10 2 Nit 5 i I 14 4 c t d -10 er u y m -15 ea -zo -25+ I l t 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 South East Asia Hydrocarbon Flow Measurement Workshop 7th h March 2007 100 +l 5% absolute error 90 I Red Eye 2G, NEL, Nov 2006, Horizontal 80 70 40' s m 50 •r.- 3 ,•5 d 40 d Ito' 30 20 10 m 0 I I F I i I 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 5% absolute error 20 V 1 Red Eye 2G, NEL, Nov 2006, Horizontal d 15 w d E 10 e. m e 5 G Q K, CO O �j• e 0 CO e e e 4) 40' ..4 o` d -10 U U m -15 3 -20 -25 I I I F 4 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 tn 9th March 2007 25 0/ 5% absolute error 20 o Red Eye 2G, NEL, Nov 2006, Horizontal al 15 2 E 10 0 7 i ♦S i• N Q IS to rr t S. 0 d -10- 7 o ti -15 3 -20 -25 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 +1- 5% absolute error I W 90 0 Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical y t' 80 Red Eye 2G, NEL, Feb 2006, Horizontal •Irt� Red Eye 2G, NEL, Nov 2006, Horizontal 70 Z, 7 60 u r 50 R 3 m 40 o 30 0 20 10 0 1 1 I 1 1 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 0 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9th March 2007 25 •1 5% absolute error 20 0 Red Eye 2G, NEL, Aug 2005, Horizontal u X Red Eye 2G, NEL, Aug 2005, Vertical al 15 Red Eye 2G, NEL, Feb 2006, Horizontal d Red Eye 2G, NEL, Nov 2006, Horizontal E 10 2 x X x X X x d 5- x atx a 4 X y x -x j( o x a d f Ca wiz •vim 0 1 vim, fir. x x x x 03 t 0 r it •aar7 o 5 a v o a t b •i o ••b• m -10- v d -15 a -20 zs I I 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 •I 5% absolute error 20 0 Red Eye 2G, NEL, Aug 2005, Horizontal u x Red Eye 2G, NEL, Aug 2005, Vertical 15 Red Eye 2G, NEL, Fab 2006, Horizontal d Red Eye 2G, NEL, Nov 2006, Horizontal E 1° 2 x 5- a L. AI I. W p i�c 1 I Z` i 01; _5 r -10 y V m -15 -20 I I h I 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9th March 2007 25 .l 5% absolute error 20 0 Red Eye 2G, NEL, Aug 2005, Horizontal Tli 0 X Red Eye 2G, NEL, Aug 2005, Vertical u 15 Red Eye 2G, NEL, Feb 2006, Horizontal w Red Eye 2G, NEL, Nov 2006, Horizontal P.! 10 2 x x m 5- xxxx 7 xK x w CO d +xX b O X X X X co CO et' v 0 0 0 m -10- 7 U Ili -15 to -20- -25 I I f I 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) 25 vi. 5% absolute error 20 1 0 Red Eye 2G, NEL, Aug 2005, Horizontal 1 d 15 _I Red Eye 2G, NEL, Feb 2006, Horizontal d Red Eye 2G, NEL, Nov 2006, Horizontal 10 0 y 5 7 17 0 in 0 A 0 0 0 0 b o m -10 7 U y -15 to -20- -25 I 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 25 -s/- 5% absolute error 20 Red Eye 2G, NEL, Feb 2006, Horizontal Red Eye 2G, NEL, Nov 2006, Horizontal e 15- CO CO E 10 m 5 o 1• O 0 s .0 1. e m -10- 7 u y -15 A -20 -25 O 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 -5% absolute error 20 H Red Eye 2G, NEL, Aug 2005, Horizontal u c 15 I Red Eye 2G, NEL, Feb 2006, Horizontal E. Red Eye 2G, NEL, Nov 2006, Horizontal E 10 0 so 5 w 0 .0 CO 2 4 •b d -10 7 u 11 -15 is -20 -25 I I O 10 20 30 40 50 60 70 80 90 100 Reference GVF (e/.) Figure 25: Red Eye water cut error vs. reference GVF (2005 and 2006 multiphase flow tests at 50% water cut) 19 6 South East Asia Hydrocarbon Flow Measurement Workshop 7th 9th March 2007 25 r H- 5% absolute error 20 i Red Eye 2G, NEL, Feb 2006, Horizontal C L e Red Eye 2G, NEL, Nov 2006, Horizontal e 15 d E 10 0 d 5 0 p. a lo e 5 j 0 w -15 m 3 -20 -25 I I i I i 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 JI of- 5% absolute error 20 x Red Eye 2G, NEL, Aug 2005. Vertical 6 C 15 Red Eye 2G, NEL, Feb 2006, Horizontal w 1 Red Eye 2G, NEL, Nov 2006, Horizontal 0 e. 5- Z H 0 xx *r x is x 7t x at x• x -5 r 0 O d -10 0 a at -15 1 TO -20 -25 i 4 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7th 9 March 2007 25 1 5% absolute error 20 e Red Eye 2G, NEL, Feb 2006, Horizontal 15- E 10 5 H 0 ®e .C2 ot 10 et -5 O s m -10 7 V `m -15 A -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 r 5% absolute error 20- V e Red Eye 2G, NEL, Feb 2006, Horizontal a a r 15 E 10 2 0) m 5 vi 0 0 .0 -5 a A� t O a s� at -10- 3 V -15 m -20 -25 I 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 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9th March 2007 25 .4 absolute error 20 X Red Eye 2G, NEL, Aug 2005, Vertical E 15 a Red Eye 20, NEL, Feb 2006, Horizontal Red Eye 2G, NEL, Nov 2006, Horizontal d -J 10 2 x x x F xx x m 5 x x x c c o e a 0 e o a1 9 o F a d -10- U u -15 m -20 -25 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 *1. 5% absolute error 20 m e Red Eye 2G, NEL, Feb 2006, Horizontal m 15 a m 10 2 as 5 -tee 0 a 0 A 0 -10- s u `t -15 m -20- -25 1 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 5% absolute error 20 V Red Eye 2G, NEL, Feb 2006, Horizontal 15 m w m E 10 0 r- m 5- 7 m 0 w e m -10 '5 u m 15 ta -20 -25 I l 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 .4 absolute error 20 n Red Eye 2G, NEL, Aug 2005, Horizontal 0 Red Eye 2G, NEL, Feb 2006, Horizontal 15 E 10 0 m 5 0 0 0 to e a -5 O m -t0 u m -15 -20 -25 I I 1 I 1 I 0 1 0 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 25 5% absolute error 20 Red Eye 2G, NEL, Aug 2005, Horizontal i O 15 x Red Eye 2G, NEL, Aug 2005, Vertical ED. Red Eye 2G, NEL, Nov 2006, Horizontal 10 O s 0 0 x x x m os o ®0 0 o -10 U v m -15 ro -20 -25 0 10 20 30 40 50 60 70 80 90 100 Reference GVF (a /o) Figure 34: Red Eye water cut error vs. reference GVF (2005 multiphase flow tests at 100% water cut) 24 I 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 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 r sonar ar array processing techniques to perform two independent measurements to characterize Y P 9 q Pe P 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 applications 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 I 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 problem 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 century 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 -vASIONOWiimimmiim rate within a pipe. For turbulent flows, the time averaged axial velocity varies with radial position, from zero the wall to a maximum at the centerline of the pipe. The flow cost fw nOYi1CVS W.ffihCSAUEt near the wall is characterized by ice, 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 ^4° W I, 0 i 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 similar Empirical studies have shown that velocity profiles in turbulent pipe flows are well represented by the 1 over n power law: =(1 U 90% with n ranging from 6 to 10 as a weak function of Reynolds number. From a measurement perspective, the 85% volumetrically averaged flow velocity V (mean ty) flow divided veloci by the or pipe's volume internal rate cross- of sectional area is of interest. The relation 80% between the ratio V /Uo and the Reynolds number is shown in Figure 2, 75 which is based upon the power law (1). Apparently the ratio of the mean flow velocity to the maximum velocity slightly 70% increases from a little below 80% just above the critical Reynolds number for 1.E +03 1.E +04 1.E +05 1.E +06 1.E +07 turbulent flow to greater than 85% at Reynolds number Reynolds numbers over one million. It Figure 2: Mean velocity normalized by Maximum must be stressed that, given the velocity velocity vs. Reynolds number. profile (1), very little fluid is actually flowing at the mean flow velocity. 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 S Flomeko 2005 6 9 June 2005 algorithms determine the distributed along the pipe outer circumference. The sonar based al g 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 =2Tr /A (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 40 -50 temporal frequency content of time 3 stationary sound fields are often 30 .35 displayed using "k -w plots k -w plots E are essentially two dimensional I' 25 power spectra in which the power of m -60 a pressure field is decomposed into 15 bins corresponding to specific spatial wave numbers and temporal 10 frequencies. On a k -w plot, the power 5 4 associated with a pressure field o 5 10 15 20 convecting with the flow is distributed Weverwrnbe.(11R1 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. A low -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 A is, in terms of the Reynolds number Re and a set of three coefficients C1, C2 and C3, unique to each sonar meter size given by (3). C c (3). Re BI0197 RevB 4 s 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% ProductlonSONARtrac Row Meter Dee M-0 accuracy. It is important to 9s %mM0 laud= 042% 8; &1;oTAT note that this flow 1.00% 5080590005- 1158eh 10 T 100 B2 97030030055.1158c010 T5082 metering approach has no 6080030005- 11788010 T 10002 0.75X. 608089000•118 Sell 10T5D82 fundamental size 51080510005 1095th 10 T 100 E1 S1060610005•111SoS 10T 5D B1 limitations and should be 0.50% 91 applicable to turbulent 8.25% 1 i• pipe flows of all diameters 'C and Reynolds numbers. 0.00% 6 Furthermore, similarity .025% a laws suggest, and data m n o from Figure 4 support, 440% that the relationship OJS% between convection velocity and flow rate from -1 .00 geometrically similar 0.00E00 5.00E05 100E.00 150E00 250000 2.50E00 3.00E40 R. 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 sand Thick stock flow in paper and pulp Air conveyed transport of particulate material. Two phase flow of water and oil 11 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 /dm and low (1.65 kg /dm density magnetite suspensions in the feed flow to a BI0197 RevB 5 Flomeko 2005 6 9 June 2005 30000 1009 10000 100% HIGH LOW 24000 80% 8000 80% m C 18000 60% 6000 60% C /0 0 0 7 V 12000 40% U 4000 40% 6000 20% 2000 20% 0 0 °k 0 0% 0% 5% 10% 15% 20% 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 rule known as Wood's equation 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 W 1 rp Pc t Pgc MC (4). P= VP 0P1 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 BI0197 RevB 6 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 N -1 bar irrespective of the type of gas, which can be t;. 2 bar either air, carbon- 3 bar dioxide, hydrogen or •a 100 4 bar any mixture thereof. c to 5bar For mixtures confined 7_7 to a pipe, a correction to above formulae (4) is necessary in order to account for the relative 10 change of pipe cross 0% 5% 10% 15% 20% sectional area upon internal pressure Gas volume fraction variation. This so called distensibility Figure 6: Mixture sound speed vs. gas volume fraction. D, is an additive term to the first equation of (4). The distensibility for thin walled, untethered pipe is given by: D Et (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 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 =21t/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 shows a k- w plot generated for acoustic sound field soo recorded from still water containing 450 —3% entrained air by volume in an 8 in, schedule 80, vertically oriented Plexiglas pipe The k -w 35o plot was constructed u sing data from an array of strain based sensors clamped to the outside of th e T ri are measured sound speed for this for 47 25° clearly evident. Based on the •ss s lopes pipe. of the wo acoustic acoustic ridges dges the loo this mixture was 70 m /s, consistent with that predicted by the Wood -15 -10 -5 0 5 10 15 -70 equation. Note that adding 3% air Wavenu (1 /ft) by volume reduces the sound speed of the bubbly mixture to less Figure 7: k w plot for 3% entrained air in water. 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 headbox 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 8 Flomeko 2005 6 9 June 2005 Errors in consistency measurement of paper stock. Errors in the determination of net oil using watercut meters Errors in Coriolis determined volume flow as a result of product aeration 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 7 stock just before and just after the 7 6 dosing of a commercially available e_. defoamer chemical. Given the 0 5 continuous character of the 4 measurement and given the fact vii* that this full bore measurement is, E 3 unlike a sampling system, representative of the true air 2 content the ability to control co defoamer dosing presents itself. Such dosing control will not only o help reduce defoamer volume it -120 -60 0 60 120 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 9 S 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- 8n P g, 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 g ty gl pe #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, April 2000, 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 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 10 j SP rnational t inte 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 Introduction 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. The PBU has been in production since 1977. Over the life This paper was selected for presentation by an SPE Program Committee following review of of the field several different Test Separator configurations 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 have been utilized. Approximately 16 years ago, PBU started 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 to use the density water cut method on 2 -Phase Mini Test SPE meetings are subject to publication review by Editorial Committees of the Society of Separators to overcome problems that were encountered on 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 the conventional 3 -Phase Units. In general these units operated prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous successfully; success was measured by repeatable water cut acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. en results that enabled the petroleum engineers to improve Box 833836, Richardson, TX 75083 -3836, U.S.A., fax 01- 972 952 -9435. P g P management of the wells and have more confidence in Abstract 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 For the first time in a BP- operated asset, the impact of entrained free gas (not solution gas) in the liquid outlet line of from 22 to 32 API now down to 17 API. This brought a whole a well test separator is quantified for the purpose of correcting new set of problems. As part of this project two new mini 2 gross fluid volumes and density measurement. This paper Phase Test Separators were installed. describes the results of deploying a sonar based, clamp -on gas void fraction (GVF) meter at a test facility in the Prudhoe Bay A review of the liquid leg densities of the units handling Unit (PBU) on Alaska's North Slope. 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 This paper is a brief report of the findings of a preliminary was confirmed that discrepancies in allocation factors and test and a more extensive pilot project of a strap -on sonar individual net oil measurements, especially for cold high based GVF meter on both `non viscous' crude oil and satellite viscous crude oil, was due in part to unrecognized gas carry- field viscous oil. The preliminary test was a quick check to under in the liquid outlet. Measured GVF associated with determine if the GVF meter could measure a meaningful GVF wells flowing `non- viscous' oil, the less viscous crude (22 to on the two crudes. With a favorable result to the preliminary 32 API) ranged from 0 2.0 whereas the GVF of wells test the pilot project was instigated and the unit was installed flowing viscous crude (17 to 22 API) was between 0 8% at and fully integrated into the well testing system. Since being normal vessel liquid levels increasing to >20% at reduced installed in October 2005, the unit has been used for on -line separator levels. 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 The additional secondary phase measurement enables PBU to now report real time corrected densities and volumes using Zero GVF measurement is a critical issue especially when the an in -house method to calculate water cut. In addition to unit is used for all types of crude oil and on many wells having viscous crude, we believe that application of this technology little to no GVF. to smaller, somewhat under -sized separators with less stable operations will provide value across the industry. To quantify the impact of GVF on the Test Separator operations in PBU, a 1% GVF equates to an understatement of Well testing importance is increasing on the maturing water cut (WC) by 5% and a direct 1% over statement of gross fields of the North Slope of Alaska as it is not only used for fluid flow. the critical function of field management that ensures optimum production from a field; it also is a regulatory As the title of this paper indicates this meter provides a re q uirement set b the State of Alaska and ma be used for solution to a long standing problem. This is the final piece of a Y Y Production Volume Accounting on fields with co- mingled puzzle that has taken many years to solve. In order to have a production facilities. better understanding of how our approach has developed the first few sections of this paper will provide a brief overview of 2 SPE 100893 the PBU and a history of Well Testing, Oil Allocation and produced through the PBU facilities. Well testing is again Test Separator improvements in the PBU. mainly for field management but more importantly for regulatory purposes to prove the field is being operated and Overview of Greater Prudhoe Bay (GPB) 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 Oil Allocation Methodology largest and has been the main driving force in the development of the Test Separator Systems described in this paper. The As the PBU evolved over time, so has the Oil Allocation most recent business need has been the introduction of small Process changed to meet the new challenges. WOA has three satellite fields to the IPA facilities and the problems of cold production facilities known as Gathering Centers (GC) where viscous oil. The PBU was from concept split into two oil, gas and water are separated, the gas is dehydrated before operating areas by the owners with the agreement of the State shipment to the Gas Plants and re- injection into the field. The of Alaska; the Western Operating Area (WOA) operated by EOA also has three production facilities known as Flow BP and the Eastern Operating Area (EOA) operated by Stations (FS). Oil is shipped to Pump Station 1 (PS 1) of the Atlantic Richfield Company (ARCO). In addition there was a Trans Alaska Pipeline System (TAPS) for metering to custody different ownership split between the Gas Cap and the Oil transfer standards. Alyeska Pipeline Service Company Rim Participating Areas. After the BP /ARCO merger, BP is (ALPS), the company operating TAPS, operated two metering now the sole Operator of PBU and the field has been unitized systems, one each for EOA and WOA. As production has with aligned working interest ownerships in Gas Cap and Oil declined ALPS reduced metering to one combined meter set Rim Participating Areas. for EOA and WOA. Also GC 3 passes partially processed oil to FS 3 so only five production facilities are now producing The Test Separator operations described in this paper are from directly to TAPS. All of these changes have had an impact on the WOA. the allocation process. Impacts of Well Testing The following simplistic statistical model demonstrates the impact of metering accuracy on the allocation process. Taking As with all oil and gas fields, PBU well testing is used for the WOA as a model there are three levels at which oil field management. A very critical function used to optimize metering is made; Fiscally at PS 1, Production Metering at the production rates and total hydrocarbon recovery from the outlet of the GC and individual well production (Well field. Testing). In order to measure a total volume of 300 MBPD to an accuracy of 1% the choice is to either measure with one With the early ownership differences between the Gas Cap 300 MBPD meter with an accuracy of 1 or three 100 and the Oil Rim, well testing was critical in the determination MBPD meters with an accuracy of 1.75% or three hundred 1 of the Gas Oil Ratio (GOR), one of the parameters used to MBPD meters with an accuracy of 17 select a well for inclusion in the Gas Cap or Oil Rim. As gas production increased beyond the agreed associated gas volume The WOA has gone from initial allocating process of (determined at a 1000 GOR) the importance of well testing in allocating from PS 1 to the GCs and then to the associated this area reduced and the gas condensate allocation was then wells to allocating directly from PS 1 to the all wells and back by an agreed liquid volume factor in the gas and simply to the intermediate GC step process. The reason for the determined by measuring the overall gas volume. 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 The introduction of satellite field production into the IPA areas. Processing Facilities created the problem of production allocation to the correct field. There was a different tax Brief History of Test Separators royalty regime for IPA and the PBU satellite fields. By prior agreement with the State of Alaska well allocation was the The following describes the fixed in place Test Separators. selected method for individual field production. The overall If at any time these units were having operational problems volume of crude oil was measured to custody transfer Portable Separators were utilized to ensure the required well standards; allocation and well testing determines the testing was performed and the overall allocation process was production split between the IPA and the individual satellite accurately maintained. fields. This obviously increased the importance of well testing and PBU in collaboration with the State of Alaska undertook a The initial test separators were Test Banks (3 Stages of major program to upgrade and improve oil allocation and well Separation) in the GCs. This ensured the oil volume testing operations. measurement was of sales quality crude corrected to Stock Tank Barrels (STB). As the field developed Test Separators With the merger of ARCO and BP the PBU Gas Cap Oil were installed at the Well Pads operating at elevated pressures. Rim ownership difference has been eliminated. Also the State This introduced the problem of "Oil Shrinkage the change in of Alaska has recently equalized the taxation rate for all oil volume of live crude at test separator conditions to STB. SPE 100893 3 To overcome this problem PBU carried out a large project count the existing methods of calibration became virtually of correlating test results from the Well Pad Separators to the impossible to maintain. In addition the laboratory analyzer same well tested in the Test Bank. From this large data base an proved not to be satisfactory and was taken out of service. All algorithm were developed that provided two factors, Oil of these problems lead to a fundamental reevaluation of the Shrinkage and Solution Gas (SCF per unit volume) to be calibration methods and even the density method itself. applied to the Test Separator results. Recently PBU updated this data base utilizing a customized equation of state to New Approach to the Water Cut Density Method improve the accuracy of these factors. The following is only a brief outline of the in -house The initial Well Pad Test Separators were large 150 Barrel developed method that will assist with understanding the main 3 -Phase units. Turbine meters were used for oil, water and gas. topic of this paper; GVF measurement and the application to Master Water and Oil Meters were installed to check the test separators. The basic intent of the method was to reduce accuracy of the on -line meters. A capacitance probe was sampling requirements while not impacting metering installed in the oil leg to detect the water cut up to 20 In accuracy. general these systems worked well but problems started to The method is based on mass which does not change for appear when the water cut and GOR started to increase. This pressure and temperature variations or for mixing two fluids was especially true when PBU came off the production together even if they are in different phases. Live crude is just plateau. Several improvements were made including replacing stock tank barrel crude oil with gas in solution. Therefore the the liquid turbine meters with vortex units and modifying density of live crude can be predicted by simply adding the internals of the separators. The significant problem with the mass of the oil and the mass of the solution gas together. capacitance probe system was that it could only be customized The key to understanding this system is oil shrinkage and on a per well pad basis and individual wells on the same well solution gas. These parameters are fundamental to well testing pad were exhibiting significant different physical properties at elevated pressures and temperatures. Typically a well test which impacted the water cut accuracy. determines the volume of live oil at separator conditions; the oil volume is then shrunk to provide the daily production PBU had installed three mini (40 Barrel) 3 -Phase Test volume in STB terms. Separators that were experiencing significant problems. The The density of stabilized crude and dry gas can be results made any field management of the wells in that area determined at both base and line conditions (Pressure and very difficult. In 1989 PBU decided to install a direct mass Temperature compensated) using API and AGA Standards. flow meter using the density water cut method on the liquid The density of water can be determined by well established leg of the separator which was converted to a 2 -Phase unit. and internationally accepted algorithms at both line and base conditions. This method proved so successful that it was installed on The hydrocarbon (Oil plus Gas) density at line conditions eight of the 3 -Phase Units. In addition the three GC Test Bank is the sum of the oil line density with oil shrinkage applied Separators have been reduced to a single stage unit using the plus the mass of solution gas on a per unit basis. The water cut density water cut method. The two new satellite field Mini is determined using the standard equation for the mixture of (30 Barrel) 2 -Phase Separators are all based on this method. two fluids of known densities from the measurement of the These units did have a microwave water cut meter installed in line fluid density of the combined fluids. the liquid leg, but they have never been used on -line. The unique part of the method is that the actual oil, gas and water volumes at line conditions can be determined. Therefore Water Cut Calibration Methods for Density Based Water it is possible to mass balance the liquid leg by comparing this Cut Measurement calculated mass to the measured mass flow from the direct mass flow meter. The method adjusts the solution gas in the All water cut analyzers need to be customized to specific density model until 100% mass balance is achieved. This has well fluids. This may even be on a per well basis. been demonstrated to improve the water cut accuracy. The proprietary system installed required a `pseudo' oil density that would be temperature compensated using API Benefits of the New Approach Volume Correction Tables to give the oil density at line conditions. The first calibration method implemented simply The oil shrinkage and solution gas factors are based on fixed the water density and adjusted the oil density until the pressure, temperature and GOR. Therefore the metering on the water cut matched spinout tests of the crude oil for each well. Test Separator is now fully integrated as the off gas flow This was later improved by taking live samples to the impacts the liquid leg measurement for oil and water. More laboratory where an analyzer measured the oil and water specifically the hydrocarbon fluid density in the liquid leg is densities at line conditions and the' pseudo' density was fully compensated to all pressure, temperature and GOR calculated. Both methods were satisfactory but required conditions. The only parameters to be input to the method are careful co- ordination of the well in the Test Separator during the base specific gravities of dry oil and water. This sampling and were very man -hour intensive. significantly reduces the sampling complexity as only the well With the updating of the eight 3 -Phase Test Separators to fluids at STB conditions are required and not at the line 2 -Phase Units, the addition of the two new 2 -Phase Units for conditions. the viscous oil and the associated significant increase in well 4 SPE 100893 As the method provides on a real time basis the STB water enough to sweep the buildup of free gas. See Figures 1 and 2 cut, it can be compared directly to the laboratory determined for the GVF plots of these tests water cut which is made at 0 PSIG. There is a significant difference between the on -line water cut and the STB water 07 cut especially with oil shrinkages of up to 30 0.e Problems on the Viscous Oil Test Separators 0.5 Most of the early problems were associated with the fact E 0 4 LL the units were open to the Artie environment and meters were not installed in the most advantageous way. These difficulties 0'3 were slowly overcome and the new density method was 3 0.2 installed on the separators. A review of the measured density in the liquid leg of the separators indicated a significant 01 quantity of gas in the liquid leg which had a detrimental 5 impact on both the total fluid volume and the water cut 5/20120051715M 5Y10/2005172212 MORON 17:6.20 WO/2005113535 5/2021005 1722.1A 522022005 1731.00 determination. The addition of GVF in the liquid leg means Figure 1 Downstream GVF Meter on a Typical PBU Well (26°API there are three unknowns but the calculation method only and 98 °F) provides two equations. The third unknown, GVF had to be quantified for the density method to work. 35 Selection of the GVF Meter 95 Upstream BP was performing wet gas meter tests and during a 25 Downstream presentation of this test a sonar based strap -on unit was presented that was claimed to measure GVF in the 0 -20 20 range. The unit is passive; it listens to audio frequency noise 15 signals in the fluid and using sonar techniques determines the speed of sound (SOS) of the fluid in the pipe. In this frequency 15 range the wavelengths are several feet, therefore the transducer is measuring the physical properties e.g. free gas 5 that is present a significant volume of the fluid and not just a 5 slice across the pipe. The relationship between the SOS and 51TL1005 512X2005 7.42 51222505 5:55 5/22/20051036 52172200511.10 5122/20051235 gas in a liquid (GVF) is very well established and documented. Figure 2 Comparison of Upstream and Downstream GVF Meters on a Cold Viscous Well (18 °API and 54 °F) Preliminary Tests Extended Pilot Test It was decided to perform a preliminary test on the liquid leg of a Test Separator that tested both PBU and satellite crude As a result of the favorable preliminary test it was decided wells. The objective of these very simple tests was to to install a unit into the well testing system and to monitor its determine if the unit would measure a GVF and whether it performance. The new in -house density approach is would track expected GVF values when the level in the vessel programmed into a stand alone flow computer that has fully was raised or lowered. Two units were installed; one upstream flexible customer programming capability. The program was of the mass meter (horizontal) and a second downstream of the updated to include the GVF function in both the density mass meter (vertical down). The intent of the preliminary tests calculation and the gross volume calculation. In addition the free gas was added to the off gas and the free gas was included was not only to confirm satisfactory g g g y sa sfactory operation of the GVF in the mass balance of the liquid leg. meter but also to try and select the best position for a more q g extensive test. To enable the operation to be monitored closely an extensive data gathering system was also configured into the The results of two days of trials were very favorable. A flow computer and the Supervisory Control and Data GVF was measured in both crudes in the range of 0 30 Acquisition (SCADA) System. The SCADA System performs The GVF measurement performed as expected; it increased in the well test function and the following parameters were value for a lowering vessel liquid level and decreased in value retrieved in addition to the standard data for well testing. for an increasing vessel liquid level. Typically both units tracked; however on high GVF values 15 the Gas Void Fraction downstream meter indicated up to twice the upstream unit. On -line Measured Density This was believed to be a piping issue with gas trapped in an GVF Corrected Density inverted U section of pipe and the flow of fluid was not great Calculated On -line Hydrocarbon Density Calculated On -Line Water Density r SPE 100893 5 Mass Flow testing cold heavy viscous crude the results presented and STB Oil Flow discussed in this paper are for a viscous well. STB Water Flow On -line GOR The initial tests on one particular well showed little to no STB GOR GVF but as time progressed tests started to have large GVF Mass Balance swings and plateaus on the GVF data plot. The status of the Solution Gas Correction Factor unit was low signal quality and invalid SOS data. The first reaction was to question whether there was enough noise to Data was gathered approximately every 20 seconds. enable the meter to function. After all the unit in use had the greatest distance to the liquid control valve, the expected This real time data has enabled PBU for the first time to source of the noise. A data "snap shot" was submitted to the monitor very closely how the density method operates on a 2- manufacturer who stated the signal strength was good but the Phase Separator. unit was not able to successfully analyze the SOS data. It was noted that when the wells are tested with the portable Review of Preliminary Results of the Pilot Test separator unit chemicals are injected into the crude, in particular anti -foam. The water cut methodology is based on fluid densities so Anti -foam was injected into the well flow -line. Figure 3 tracking how the hydrocarbon and water densities vary on -line shows the response of the GVF Meter and the density water and how the measured liquid leg fluid density compares to cut methodology to this anti -foam. The plot is for 8 hours with these densities is critical. For example the GVF values we the anti -foam injected at approximately 5 hours into the plot. have witnessed on these tests can take the measured density The well test was for 4 hours and this plot shows the first 3 from less than the hydrocarbon density to higher than the hours of this test. There was an immediate improvement to the water density. That is from 0% water to 100% water. whole system. Parameters no longer had wild variations and The test separator is at an unmanned site and the only the GVF corrected density was now solidly in between the monitoring is restricted to measured calculated variables; it hydrocarbon and water densities and steady. For the well in was not feasible to bring back the status of the sonar unit. The question the measured on -line density was significantly below dilemma is to know when an accurate GVF is being measured. the calculated on -line hydrocarbon density. 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. Line Density GVF Oar Density HC Celc Density Water Ceta Density —GVF Reviewing the GVF transmitter status when this happens reveals two basic reasons; either poor signal quality or invalid ss 20 speed of sound data. 84 t8 16 62 so ��1 III 14 The downstream unit was selected as the primary meter for 58 +ir d l 12 the test. Initial results looked promising; however we 10 0 witnessed excessive swings in the indicated GVF (0 to 20 0 8, ill 6 with the associated large variations in water cut. This was a 52 Minn 1 ill 4 repeat of the high GVF measured during the preliminary test u• �II�I�iI` 2 caused by a buildup of free gas in the inverted U section. The 0 so 120 180 240 300 380 420 0 upstream unit was now selected and all tests were made using Minutes this unit. The first criterion for success was to determine if the GVF corrected line density lies between the hydrocarbon and the Figure 3 the impact of Anti Foam on the performance of the GVF water densities. If this is satisfied the metering methodology Meter on Viscous Crude Oil will be able mass balance the liquid leg of the separator. The The following well test result using the fixed separator and method will not be able to mass balance the liquid leg if this the new methodology including the GVF Meter and the criteria is not met. standard SCADA well testing system was obtained and A Portable Test Separator is used to check well tests compared to the last Portable Test Separator test especially if the results are questionable. This portable separator is manned on a 24/7 basis and it is customized for Portable Fixed each well test. This is considered the best well test we can Separator Separator achieve. Oil BPD 366 498 Therefore the second criterion was to compare the well test Water BPD 29 42 result from the on -line separator to the last test using the GOR 1142 1272 portable separator. Water Cut 7.3 7.8 In general the unit operated satisfactorily on PBU crude. Table 1 Well Test Comparison of Portable to Fixed Test However as the main reason for using the GVF meter was Separator 6 SPE 100893 Conclusions Nomenclature The preliminary results of the pilot test to date look very GVF Gas Void Fraction promising; the objectives of the test are being met, i.e. to API American Petroleum Institute check the long term stability and performance of the GVF AGA American Gas Association Meter under differing conditions. The presence of free gas in PBU Prudhoe Bay Unit (Oil Field on the North Slope) the liquid leg of the mini Test Separator when testing cold IPA Initial Participating Areas viscous wells was postulated; the GVF Meter has provided a GPB Greater Prudhoe Bay (PBU plus Greater Point quantitative measurement of this free gas. The secondary Macintyre and other satellite fields) objective was to try and determine limitations of GVF Meter WOA Western Operating Area of the PBU which we have achieved. When testing viscous wells with EOA Eastern Operating Area of the PBU water present it is important to inject anti -foam to make the GOR Gas Oil Ration SCF Barrel system operate correctly. Please note these wells have gas GC Gathering Center (Production Facilities in the WOA) artificial lift. FS Flow Station (Production Facilities in the EOA) TAPS Trans Alaska Pipeline System Only the results of one well are provided here because ALPS Alyeska Pipeline Service Company. formal review all the data from all wells needs to be collected PS 1 Pump Station 1 of TAPS before it can be disseminated. Preliminary reviews indicate MBPD Thousand Barrels per Day that a GVF is present in all well testing even on the PBU STB Stock Tank Barrels (Base Conditions 0 PSIG 60 °F) wells. However three of these GVF Meters will be installed on SCF Standard Cubic Feet (Base Conditions 14.65 PSIA three mini 2 -Phase Test Separators working on viscous and 60 °F) PBU crude oil. PSIG Pounds per Square Inch Gauge PSIA Pounds per Square Inch Absolute Several years of work has gone into perfecting the SOS Speed of Sound approach to the density method water cut. The addition of the WC Water Cut 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. -17 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 Alpha 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: 1. 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. The densitometer will be calibrated on a single phase liquid of known composition (e.g. water, diesel or methanol) after installation. 3. The Flow Station and/or Gathering Centers' crude oil shipping meter allocation factors will be monitored for any significant changes in oil allocation factors. 4. Production Engineers and Operators will monitor individual well test rates for repeatability and unexpected changes. 5. 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. Piggy back tests using existing well test facilities or portable well tests may be used to verify unexpected performance by the meters. 7. Known volumes and rates may be pumped through the meters to verify performance in situ. 8. 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. 9. 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. 10. 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 Sensor 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) .16 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: gotdon.pospisil@bp.com July 8, 2008 RECEIVED Dan Seamount, Jr. Chairman t 6 s a Alaska Oil Gas Conservation Commission ,;Y._ rc3, 333 West 7 Avenue, Suite 100 `t Anchorage, AK 99501 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 a 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, 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 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, 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 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 070808 A()(:(( (_,en2 .kpp Rptdoe 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 5. Factory Acceptance Tests (FAT) 10 6. Field Maintenance and Periodic Calibration 10 7. List of References 11 8. List of Appendices 11 2 of 11 070808 -MG( 'C Gent App Rpt.doe AOGCC "Application Report" for Gen 2 Multiphase Measurement System 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 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 3 of 11 970808 .k0G( Gent -tpp Rpt.doc 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. 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 used 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 content3' 4 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 070808 AOGCC Gen2 App Rpt.doc 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 ❑E 0 Absolute Line) Pressure Differential Pressure Encapsulated Temperature Sonar Sensors 01_1 o Red Eye Watercut Probe Photomultipller 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. 5 of 11 .01.. 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 11 070808 AOGCC Gen2 App Rpt.doc Table 1- Summary of wells tested, time, and duration Well Tat data Tat Pima 1 Tat duration Prudhoe Bay V?ad p.kl V-01 Wet not avadatie V-02 01 -31 -2008 03:00 11:03 8 hoes V-03 02-03 -2008 14:00 22:00 8 hoes V-04 01 -28 -2003 15:00 23:00 8 hours Prudhoe Ow VP.d OCi iak) V- 101 02-05 -2008 21:00 05:00 8 hoes V -102 01 -29 -2008 11:00 19:00 8 hogs 01 -29- 2008 00:00 0353 Test abandoned V -103 by Unit 5 operator I 01 -31 -2008 16:00 -0300 8hours 01-30 -2008 00:00 0800 U nrt 1 and Unit 5 V -106 bypassed 01 -30 -2008 13:00 2100 8 hoes V -107 Wel not tested V -108 02-04 -2008 1 04:00 12:00 1 8 hoes V -109 WeI not tested V- 111 02-04 -2008 18:00 02:00 8 hours 01 -26 -2008 16:00 19:15 1-r2S trip test V -113 abandoned 01 -27 -2008 1 2:00 2000 8 hours V -117 Wet not available V- 122 02-05-2008 08:00 1600 8 hous Prudhoe Bey V-P.d (Schroder Elute V- 202 02 -01 -2008 05:00 13:00 8 hous V -203 01 -28 -2008 0200 1000 8 hous 02-02 -2008 12:00 2000 8 hours V- 204 02 -01 -2008 20:00 04:00 8 hour s V- 205 02-03 -2008 01:00 09:00 8 hours Table 2 Well Fluid Pro erties for Gen 2 Tests P 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 Uncertainty Relative to ASRC Unit 1- Gas Rate Liquid Rate Water Cut Gen 2 ±7 ±8 15 V -Pad Separator 19 114 19 Estimated Reference Uncertainty ASRC Unit 1 13 1 15 12 I 7 of 11 070808 AOGCC Gent App Rpt.doc 6030 45C0 i Fr Con 201♦ilhMi� a FT WI 20¢1KUpny ¢00 FT n 200911,011•0-01111 W F Con a 3633 r xx 3mo 7500 CO 2033 y p 04 1533 8 1000 500 4� 1111 0 0 500 1033 1503 7000 2933 3003 3933 4033 1503 5003 Uni 1 gas flovwate (Msctid) Figure 4 Gas flow rates from Gen 2 50% &9nMFT 02020 gas 11.11061 10%. BUMF? 20 ass /«0033! BLBMIFTgn20 Vi 1B F BNR -W- B% b 70% 10% 10% Y i i 0 -109: CD o N -20% C 8 -X0% -60% 50 55 93 es 70 75 BO as 90 133 Uni 1 GVF Figure 5 Gas flow rate accuracy as a function of GVF 3530 riFTO•n 20%W4/MY► 3000 IYFTG.n20%WMpirill WI Wn 20 awe 40th was MOT 3 u 2500 /0% V 2033 0 0 7 v 1633 et g C 1330 v 5133 0 0 533 1033 1633 2033 2500 3® 3600 Unit 1 liquid flowrate (Mid) Figure 6 liquid flow rates from Gen 2 8 of 11 070808 AOGCC Gent App Rpt.doc 50# 409. B1B' iFTOn 20 4m1r.041) e BL9+NFTOw 20 lour lKuprul) BIHMIFTOn 2 0 N ul1BrbIMr.B111) _a 5% I 20% 2 10% .2 Q# -10 Q G -70# -30% -50% 50 56 SD 55 70 75 !D 95 90 95 1W Unit 1 OVF IS) 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. 1 90% wFTOn2thriller su WNW WFT On 20w•red 1K*ONJ au% riFT On 20war eu lBelw•cBlup r 70i 5% EC% r f r 409 A e 44 310, 20% 10% r 0%•i 1 0% 10% 70% 3177: 40% 507+ W% 70% ■Ji 90% 1W% Unit 1 water cut Figure 8 WC measurements from Gen 2 9 of 11 070808 AOGCC Gent App Rpt.d(h S 50% 40% ai :ov, lc% -1a1,. C _212% riFT dn20•4481 [ut1ryW1} YFT C•n 2ouw art 114pru• riFT Con 20 1[r[ut4Behl[o•FBUt} IOt# -at516 50 55 !D 85 70 75 m BS 57 $5 100 Una 1 OVF 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. 10 of 11 070808 .A()GC( Gent 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),O. H. Onalmis, D. J. Rodriguez, A. Vera, V. Ramakrishnan (Weatherford Intl.) ,25 International North Sea Flow Measurement Workshop 16th 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 meter solves old problem impacting well test accuracy," Ward, E., SPE paper 100893, 2006 SPE Western Regional/AAPG 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" 25 International 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 meter solves old problem impacting w pp p p g ell test accuracy," Y 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 lvishak Undefined (Eider) 12.50% Separate 100 100 Endicott Endicott 220100 Endicott 12.5% to 20% Separate 67.9221 0.0234 21.0206 0.1291 0.3874 10.5174 100 Endicott Sag Delta North 220150 Sag Delta 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 36.402687 100 LPC Tract 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 Point MPU Kuparuk 525100 Milne Point Kuparuk 12.5% 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 99.269596 0.730404 100 Milne Point Tract Operations 525160 Milne Point Ugnu, undefined 12.5% Separate 100 100 Northstar Northstar 590100 Northstar 20% plus supplemental Separate 98.5772 1.4228 100 LPC Prudhoe GC -1 Point McIntyre 640180 Point McIntyre 12.5% to 16.67% Consolidated 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 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 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. Benson a b p BPXA!PERATING UNITS NORTH ?LOPE ALASKA Map Location i BEAUFORT SEA h Leaven „IX I island t /s; 0 ..4:.„.a 400, s 1 rW Simpson Lagoon Ili Pad 1. Topographic and hydrographic Milne Point Cottle Island Northstar Island Shoal Pp_- I% A NORTHSTAR NORTHSTAR UNIT Seal C r or l s l eM B Unit 1:6,000 Mapping C based on 1973 aerial M o J Point HI Island I photography with periodic updates Mine nslte� A B Long Island Reindeer Island 3. Unit boundaries shown effective April 2006 CFP J 1 E Argo Mend a. BPXA Cartography does not warrant that the data is 'N Milne P t 1 la t r 11M 0 2 4 6 Kilometers accurate or fat for any particular use. User hereby IP G Mine Site G .S'T indemnifies and holds harmles BPXA Cartography ITt. E 4 Miles for an claims and /or liabilities which ma arise DS 3K MILNE Ps MIT 4 B Qy `4 N SS'� N 0 2 from users use of this data. y K Egg Mang I Stump Island s 0 U LiTM6/NAD27 ND S WEST I DOCK I DS 9C y r Point Mclnryr:4 PM2 DS 1R 0 g PM Narwhal Island .y I +'T PRUDHOE BAYdJNIT Resolution ��oa DS 1p Island Jeanette Island '5 West WDSP west 4,5 6 Endeavor DS 1 DS 1H S Dead Arm Beach Gus Island NIAKUK ISLANDS Island L 3 Mine Site y T S tate Heald Point 1 MPI t KUPARUK E AGI DS NK CAMP KIC LGI Prudhoe Kartuk Island m K DS 1 II. �'y N F I.. WG I D SL/ Bay DSL' Q DS 1C V SI 0 SPINE ROAD J Put 23 Mine e NGI S C D3 C PF NS B CG CCP FAST Stockton Islands Howe Island l� M ine 1 Land Fill DOCK Site I D C DS1E Pole Is Duck Island Pole D DS 1F iS 1D Alli GC2 DS7 1 DSL2 DS 1M U DI DSL4 Point Brower 1 GC3 i`• IPC CPS C` roi c"'-' V DS7' DS11 O P9 DS 1L I SIP DS F r Q O Foggy Island i P A 5 1 PSI I D S`t� BeNedere IS DS 1J F S3 �t �il� v EXXON DUCK IS. p V Y 08..„/ L4 i' i ____,,--1. FS `tn OS9 MINE SITE Lion Point 9, X �pl DS6 DS7 'I IMI risk Island r Tigva D sa ti Foggy Is an Bay 1 -,_.1 psi.. DS f e 4 OS13 �7 D318 �q canoes lelarld J DS77' Reliance Point BUMn DE ry 3 Point i AIRSTRIP c' NP' 0 w n BADAMI UNIT t C v iUpHOE BAY UNIT? Mikkelsen Bay i "t, SULLEN 2 ff t' Q OQ 2' BADAMI 1 1 T I .ci-3 fr 0 DT a r c, 1 BPXA Gartagrephy /02-06/ pe14920.dgn 1 0 b p R TH SLOPE OILFIt AND POOL OWNERSHIP Ju ne 2008 000GURUK UNIT NIKAITCHUO UNIT Map Location Pioneer 70.0% E NI Petro 100% ENI Petro 30.0% MILNE POINT UNIT" I All PAs BP Exploration 99.20% `a '11".". Kerr-McGee 0.80% PRUDHOE BAY UNIT' Is CC I All PAs including OIL RIM and GAS CAP 1 B E A U F O R T SEA Z I --J MILNE PT KUPARUK PA" ExxonMobil 36.402687% NORTHSTAR U II I CPAI 36.076746% NORTHSTAR PA 61111r" r BP Exploration 26.360567 BP Exploration 98.5772 ti...N• Spy Island Chevron 1.160000% Murphy AK 1.4228% f •I -y,}� Pin 0 1 2 2 4 6 Kilometers Thettlsland ,1� 9o k/sian d SAG RIVER PA" p 1 4 Miles I 1 1 UTM6 /NAD27 I I COLVILLE RIVER UNIT 7 r'� ALPINE, FIORD- NECHELIK, II- 1 L 1 FIORD•KU I Olikt°k L NANUO- NANUO, AND Milne Point L NANUO•KUPARUKPAs F 1 ,ISCHRADER BLUFF PA" 011kto nt as Approx. 10 Miles West DS 3R j I NORTH CPAI 78 tl .00% L NORHSTAR nadarko 22.00 A ay 4.4,,,,,, DS 30 Mine S' j t 1 I Argo Island I SAG DE LTA NO RTH P L L DUCK ISLAND UNIT L DS 3M �w PT. MCINTYRE PA' BP Exploration 98.1327 ENDICOTT PA DS 3N Nana 1.4005% BP Exploration 67.9221% G I E Sea 'MIDNIGHT SUN PA 1 COMBINED NIAKUK PA' +Doyon Ltd. 0.4668% ExxonMobil 21.0206 1 •f 1 I N Unocal 10.5174% DS 31 DS 3K m AURORA PA' L 1 s (WEST BEACH PA' I RAVEN PA' Nana 0.3874% Doyon Ltd. 0.1291 J DS 3J r l K POLARIS PA' Implsland CPAI 0.0234% 1 EIDER PA STP 1 C IS I (BP Exploration 100.0% I I r D83S J 1 DS 3A 1 Dock s. OB 3C PAA2 4 1 1 DS 3G DS 3B 1 -7 I r te- L `I t r 1 1 L 1 1 1 R e so i L DS 3F D 1D j. J L Island i r z I 1 ,1 Ir. 4� 'Sp kuk Endeavor Island LIBERTY UNIT L- 1 DS 2U DS 2W DS 1G DS 1H .11 L I T Island 4, tkIPI (BP Exploration 100.0 1 Kuparuk S R F 1 L G I I SAG DELTA 5 H Point I TABASCO PA"' DS 1v Ise 1 IO 1 1 DS 2X DS to Came Y M K DSL1 DS 1C I WGI t DS LS M Duck Island 3 KUPARUK RIVER UNIT"' 1 r DS 2N CF 1 ROgp 1 1 I 1 HowoIa$dI L SDI Ds 2Z P SPINE N o �F DSL4 Eas A 11 ll PAs Dock Duck CPAI 55.41% 1 DS 2A 4 DS 2C DS 1E 1 Z G C2 C DSL2 D F DS 1D Point Br• S 1 him DSI5 DS18 ower BP Exploration 39.28% W I U H 'y'i DS3 1 DS 28 C PF 2 DS 2D L LPC 1 Unocal 4.95 a r M ExxonMobil 0.36% r DS 2M DS11 D DS 2H DS 2F DS 1L Y e 1 DS7 DSS FS2 1 e. I ej DS 2E West Sak l i 1 L P A PS S2 IP P OC L DS 2G Pibt P r 1 1 FS11• i DS9 1 Alp e DS 2K 1 I I I I B OREALIS PA' I x D S6 DSt tea_ TARN PA 1 1 1 1 1 Li 1 1 1 DS14 DS3 1 -�1 I I ORION PA' L 1 DS13 DS1 1 tint ea J L J I D317 1 I LISBURNE PA R,,00 1 DEADHORSE 1 \ne KUPARUK RIVER 1 I 1 1 KUPARUK PA" JACOBS LADDER UNIT WEST SAK PA Anadarko 50.0% ROCK FLOUR UNIT BG Alaska 40.0% BADAMI UNIT GREATER MOOSES TOOTH UNIT f' ASRC 10.0 BADAMI SANDS PA Approx. 20 Miles West ENI Petro 100.0% Approx. 7 Miles East la r, CPAI 78.00 I ARCTIC FORTITUDE UNIT J.A. BP Exploration 100.0 Anadarko 22.00% White 100.0% i TAPS o i BP Pipelines Inc. 46.8765% c 1 CPAI 28.2323% I f r Ex 20.4325% KUPARUK RIVER UNIT I Williams 3.0845 2W I ri Me PA Unocal 1.3742 c 1 DS 2P \y S 1 I 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 and /or liabilities which may arise from users use the data. 1 BPXA Cartography /Im15098_2008.dgn 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. Onalmis, 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 g g g 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 10.5 m /hr in Type I wet gas,' and better than 120% 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 ±5% water cut uncertainty in high GVF multiphase 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 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. -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. 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. 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 1 multivariable transmitter Sonar data acquisition and processing electronics NI/ r ms l 0- MP' 0 i 1 A I a xial location of Venturi nozzle 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. 3 5% NEL -Brine 4% NEL Oseberg NEL- Nitrogen 3% 0 Weatherford -Water Weatherford -Air 2% A CEESI- Natural Gas t 1% W 1% D IX 0% O el A A Qi C rTl A A u- -1% d -2% re -3% -4% -5% 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. Venturi The extended throat Venturi- nozzle performance was verified with the same dataset and was found to measure single -phase flow rates within 11.4 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 AP is proportional to V 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 I.- a 5% absolute error 90 Red Eye 2G, NEL, Aug 2005, Horizontal 80 Red Eye 2G, NEL, Aug 2005, Vertical m 70 7 60 a 50 L r (5 40 3 30 g 20 10— 0 I I I I I I I I 0 10 20 30 40 50 60 70 80 90 100 Reference Water Liquid Ratio, Figure 3 Performance of water cut measurement 2 15 0 5% absolute error Red Eye 2G, NEL, Aug 2005, Horizontal w 10- L Red Eye 2G, NEL, Aug 2005, Vertical A 2 R d° L 0 0 0 4 it a gj 8❑ W tE° ❑OA 5 'C 0 0 0' It -10 ca i -15 I 1 I I I 1 I 1 I 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. 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. 100 NEL 10 a CEESI i H BR' O❑ ODr 7,0 aro El p 1 GVF 9.1% ❑M O CVIZILUP V Bun o d ir A GVF 50% 0 0.1 e J 0 A iv GVF 90.9% A 0 0.01 0 0 A CD 3 GVF 99.0% e e 0 A 0.001 GVF 99.9% GVF 99.99% 0.0001 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, Fr and a relatively high Lockhart- Martinelli parameter, XLM. The CEESI test envelope, on the other hand, covered Fr and XLM within the regions defined by API as Type I and Type II wet -gas flow. CEESI NEL Pressure 14, 28, 55 bara 2 7.5 bara Temperature 28 -35 °C 22 -42 °C WLR 0 100% 1, 40, 75, 100% GVF (no slip) 97.5 -100% 0 100% Total Volume Flow Rate 85 -655 m /hr 14 460 m Liquid/Gas Density Ratio 16 at 55 bara 106 at 7.5 bara 40 at 28 bara 485 at 2 bara 98 at 14 bara Frg Sonar 1.5 20 0.07 -2.6 Frg Nozzle 0.5 -5.5 0.02. -0.7 XLM 0 0.26 0.3 -167 LMQ 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. N N CIRCULATION HEAT COALESCING TURBINE ULTRASONIC COMPRESSORS EXCHANGER FILTER METER METER GAS CHRSMATOGRAPH TRIPLEX 2" 0.5" N CORIOLIS CORI❑LIS PUMPS FOR METER METER HYDROCARBON GAS LIQUID LIQUID SEPARATOR C _C LIQUID- LIQUID N 10.4 SEPARATOR 2" 05" TRIPLEX PUMPS C❑RIOLIS CORIOLIS P UM METER METER IPA FOR WATER TEST TEST TEST TEST TEST L ❑CATION 5 LOCATI ❑N 4 LOCATION 3 LOCATION 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 10 1 ai ....kii.4.4 I, ,t woo hip' ;_l r ._.r.::_--4 ii I 1 1 1 .,r 4 V y�.. v ter 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 AP. 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 ORV Qg,apparent Qg,ref with ORV f (X,Fr (2) where the Lockhart- Martinelli parameter is defined herein, as: X m lip (3) m g p 8 1 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) Qt,ref Q t,apparent Y inA, (5) ORS f (LMQ, Fr (6) LMQ m m t 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 1.3 0 1.25 1.2 o I a 1.15 132 1.1 to 0. A A 0 1.05 G n 1 0.95 o Nozzle A Sonar 0.9 0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 Lockhart- Martinelli, 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 1 1 0% 14 bare A 27 bara 55 bara w 5% 5% 3 o o c 0% o d -5% -10% 1 0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2 Lockhart- Martinelli, Figure gu e 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% 14 bara O 28 bara 55 bara CO 5% 5% O LL q4 2 -5% cc -10% 1 1 I 1 1 I 1 1 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 flow rate relative error for wet gas. 10 i 40% 14 bars 30% A 28 bara 55 bara ±20% 3 20% o y1O A 0% w -10% co-20% m -30% -40% 1 I 1 1 1 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 ±20% 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 ±0.5 m 1.0 14 bara 0 28 bara E 55 bara 0.5 m /h R 0.5 tY 3 o T t-+ 4+ Er +A aD I C lL A 2 -0.5 "5 N 4 -1.0 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 1.5 97 <GVF <99% A 99 <GVF <99.6% 1.0 99.6 <GVF<100% ±0.5m /h v A ❑D 3 0.5 AA A A A A Q A t +A s 0.0 #A Af J t C t o O A 6 ii -0.5 A 0 0 .0 -1.0 -1.5 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 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 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 i 4 4 1 L fit. •rew� 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 O<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 E 250 /13 w200- o 150 e 0 <GVF <60% 60 <GVF <80% 100 Reference 50 t20% 0 I 1 1 0 50 100 150 200 250 300 350 400 Reference Total Flow Rate, [m' /h1 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 ±20% 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 I 80 o r 60 p" O 0 <GVF <60% 0 40 A 60 <GVF <80% J C' 80 <GVF <100% 20 Reference T ±10% 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 1 350 300 E 250 CC 200 o y 150 0 <G <60% 16 "A A 60 <GVF <80% n 100 80 <GVF <100% b Reference 50 1 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 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 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 ±20% in API Type II wet gas and 10.5 m in API Type I wet gas. In multiphase flows, liquid and total rates are predicted to better than ±20% 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 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, [m 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, [m /s], [m /hr] V Velocity, [m/s] WLR Water Liquid Ratio, 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 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 P g g Injectors 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9 th 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 1 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 Tight 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 1G 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 —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). 1 6th South East Asia Hydrocarbon Flow Measurement Workshop 7 9 th 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 6th South East Asia Hydrocarbon Flow Measurement Workshop 7 9 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'% -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 '/z -inch, 1 -inch or 3- inch depending on the flowrate required. The '/z -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 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 ±1 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 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 (MgSO 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 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9th 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7cn 9 cn March 2007 411 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 P 9 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 6 South East Asia Hydrocarbon Flow Measurement Workshop III 7th 9 th March 2007 15 12 MP i c 9 4 Oil B a o N .O m 6 IIIIIIIIIIII 3 141111111%%W di L Conden 0 I 800 1000 1200 1400 1600 1800 2000 wavelength (nm) Figure 1: Near infrared absorption spectrum —xis I Will !Kt a •iJ9 kr Fiber Optic Bundle sous water- j Collector Optics -nen status t 4 Ili Probe Assembly Sapphire Window Sapphire Window ti 4--+— NIR Emitter Ili 1 1 J f" I Figure 2: Red Eye water cut meter cross section 6 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9th March 2007 r 0 11111 r I i k i a1 -4 41x1 A 1 il .4. .....m 0 1 1, IIIII. =no s ..4,.... n i 11 1\,, Figure 3: Red Eye meter installation (August 2005 horizontal test) a? I C i jp Ark f l iria. I O 4 1 1 47 4 1 i V "4 i i t:::1, NO i 4 ,;04 44 !,►a a 'v� y Figure 4: Red Eye meter installation (August 2005 vertical test) 7 Gtr, South East Asia Hydrocarbon Flow Measurement Workshop 7tn 9 tn March 2007 ,Astlii, .I F IIII r WI um II i Ili 0 w 0 'ter c r ,..w.a '4 '.4-' A 1 „„fik Figure 5: Red Eye meter installation (February 2006 test) iii 1I 1. l 4 ,,i er op s. '..1 1 li. .0. A V 44 1LAtal lip H t i '4 Figure 6: Red Eye meter installation (November 2006 test) 8 6th South East Asia Hydrocarbon Flow Measurement Workshop 7 9 March 2007 5% water cut 25% water cut 00 00 y °Hoomal Aug 2005 9 nz [(Honz)mal Aug 2005 20- *Veg 000452005 ND f E 20— Honzonlel. Feb 2008 a a• 40 •UH222mal, Feb 2006 0 01 00 •Q• 40 •5222mal. Nov2006 t 522200al, N222006 •00 •00y 010 0• 00 0 .4 O •a0 b• t 60, G •00•• 6 60 0 0 0 0a•G AO F 60 e II:: 1 too n n n n 7 12 0 3 120 93 00 0 0• 140 140 16o 0 o o 0 Ge o 160 100 180 0 10 20 30 40 SD 80 70 80 e0 100 0 10 20 30 40 50 fio 70 80 90 100 GVF( GVF 40% water cut 50% water cut 0. 60 I •Hanzamal, Feb 2006 9 nn• Oa Aug 205 2 20— A 4 20— •HOnromel, Feb 2006 •HOnzomal, 6202006 a •HOnromal, Nov 2006 S a• 40 40 •40 b s6 r .4 gp6 s 0 '0 0 0 0 C 100 166 n 0 3 120 j 120 140 140 160 160 180 18 0 0 10 20 30 40 50 60 70 80 90 100 0 10 20 30 40 50 60 70 e0 90 100 GVF( GVF 60% water cut 75% water cut 0 00 Hanzamal, Feb 2006 00 a ma, Aug 2005 g 20— ••r 2 20— Honromal, Feb 2006 ♦Honroma 5222006 522220al, Nov 2006 40 40 •o a M 06 5_ 60 60 S 100 10 0 0 0• 0 E 120 3 120 140 140 16 0 16 0 18 0 180 0 10 20 30 40 50 60 70 80 90 100 0 10 20 30 40 50 60 70 80 90 100 GVF GVF Figure 7: Test matrices for TUV NEL test (August 2005, February 2006, November 2006) 9 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9th March 2007 III 82.5% water cut 87.5% water cut 00 rI 00 g 20 I •00 1%00IF, Feb 2006 1 20 •Henzonlal, Feb 2006 -Y I 40 40 60 60 i 80 2 80 to C 100 I 100 4 j 120 120 14 0 14 0 160 160 100 18 0 0 10 20 30 40 50 60 70 80 90 100 0 10 20 30 40 50 60 70 80 90 100 GVF( GVF( 90% water cut 92.5% water cut 1 00 00 0 VeNtml, Aug 2005 1 1 •Honzonlal, Feb 2006 1 2 20 •IonzaMS., Feb 2006 A 20 •Nonmetal,Nov2906 00 4a• •M •O of 6 0 60 0• bo 3 tea I 1 120 g 120 +4 0 14 0 +6 0 +6 0 18 0 180 0 10 20 30 40 50 BO 70 80 90 100 0 10 20 30 40 50 60 70 eo 90 100 SW GVF 95% water cut 97.5% water cut 00 00 1 •Han0•nml, Feb 2006 1 11 •H0000!2�, Feb 20O6 1 20 2 20 40 60 a 60 i 80 Ty 80 a 100 +00— 7 120 g 12 0 14 0 14 0 160 160 180 18 0 0 10 20 30 40 50 60 70 00 90 100 0 to 20 30 40 50 60 70 ee 90 100 GVF(%) GVF 100% water cut 00 y O HOnzonial, Aug 2095 g 20 OVerlral, Aug 2005 40 Nonmetal, Feb2096 N000004l, N002008 e a •0 0 S 60 A G a O I 100 0 O 0 O 0 j 120 160 O O O O O 0 0 10 20 30 40 50 60 70 80 90 100 GVF 10 6 South East Asia Hydrocarbon Flow Measurement Workshop 7th 9 March 20 y j` t: r COL s a 0 P"..“ r is ID fad t II JIM Y III Ass. Figure 8: Location of multiphase flow meter test facility Pressure and Three phase separator flowcontrol 0 II I 0 Liquid Test meter Oil Liquid nitrogen Lio Rderence metering 0 ■I NMI PI' Pump} Pump Test meter _F -4.4= tg 1::: -01 tal G as Figure 9: Schematic of TUV NEL multiphase flow test facility 11 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9 th March 2007 100 +4 5% absolute error 90 0 Red Eye 2G, NEL, Aug 2005, Horizontal X Red Eye 2G, NEL, Aug 2005, Vertical 80 70 0 w 60 V 50 3 d 40 30 20 10 0 I I I I I I I 1 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 5% absolute error 20 Red Eye 2G, NEL, Aug 2005, Horizontal d 0 X Red Eye 2G, NEL, Aug 2005, Vertical m 15 a, m w CD 10 2 x x X x X x CD 5 X -X- X xx )0< X x 8E 3 X X x XX x Z 0 x x x x ir, ;(7 o to x x x x Wx x° t� X x "d q x o x do -0- 5 0 o at -10 7 0 -15- to -20 I I 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 6th South East Asia Hydrocarbon Flow Measurement Workshop 0 7th _ 91h March 2007 • 25 20 at 5 3 O 0 0 '-- -5 0 m -10 e - - - +/- 5% absolute error O Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical --------------------------------------------------------- x Ib ---------------------------------------------------- Cbb -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 60 3 V 50 3 40 d 30 20 10 0 - - - +1- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal i� SOW 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 6" South East Asia Hydrocarbon Flow Measurement Workshop • 7" _ 9th March 2007 is O 25 20 99 25 20 y 5 O 25 - - - +/- 5 % absolute error • Red Eye 2G, NEL, Feb 2006, Horizontal • • • ------------------------------------------ • • ------------0•--. -- --- of •• •• • • •• • 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) +;- 59b absolute error Red Eye 2G, NEL, Feb 2006, Horizontal •S +• •gi • •• .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 9 7`h — 91 1 March 2007 0 100 90 80 70 0 60 U U 50 is 3 m 40 d 30 20 10 0 25 20 - - - +/- 5% absolute error • Red Eye 2G, NEL, Nov 2006, Horizontal r• N' ",; "•ems' 11V 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) - - - +�- 5 % absolute error • Red Eye 2G, NEL, Nov 2006, Horizontal ---- ------- - - - - --- - - - - - -• • -1--- • •� �••► • 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 0 7`h - 911 March 2007 is 25 20 d U 15 d w d E 10 2 y 5 3 0 -5 0 -10 U m -15 R -20 25 100 90 80 70 60 3 U 50 rc 3 ry 40 d 30 20 10 0 -----y-------------- --- • ---- ----------- ��---�----- to--------�---------------- 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) - - - +/- 5% absolute error 0 Red Eye 2G, NEL, Aug 2005, Horizontal x Red Eye 2G, NEL, Aug 2005, Vertical •fAi' • Red Eye 2G, NEL, Feb 2006, Horizontal •, • Red Eye 2G, NEL, Nov 2006, Horizontal • h �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 0 7th _ 9th March 2007 0 25 20 O m -10 3 u cD -15 -20 SW 25 20 d U 4) 15 w N 10 0 w ry 5 0 a 0 m -5 -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 XX X •X » X _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __:i__�,�: r__♦i_X X x ❑ �o: 7 •K• w �••� • • x x x x OPXC4 ° o • r� •• •• • • • • 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) — — — +/- 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 -------- ------------- - ❑ • �• • Cb Z-• -- • ••-------- • '� • s. ago 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 0 7`h _ 9th March 2007 0 25 20 m U 15 w d 10 0 w y 5 0 0 �o -5 0 - - - +/- 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 x x -- - - - ------------—---- - -xX)f x-'--�--- xx xx i •• *ease xx#x • x • e • w • • __ x x x x xx •• • •Q o� ao a no 6 1 ❑g❑ o ■ o • ------------------------------v-----o ----------------- 0 -25 I I i i 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) 25 20 d U 15 d E 10 0 w y 5 0 0 -5 O - - - +/- 5% absolute error ❑ Red Eye 2G, NEL, Aug 2005, Horizontal • Red Eye 2G, NEL, Feb 2006, Horizontal • Red Eye 2G, NEL, Nov 2006, Horizontal - ----------------------------------------------------------- ❑ oWo ❑ • Ir a • ---------------------------------------------- -25 I 1 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 7th 9 `h March 2007 25 5% absolute error 20 Red Eye 2G, NEL, Feb 2006, Horizontal d U Red Eye 2G, NEL, Nov 2006, Horizontal aa) 15 4, m 0 0 w y 5 N 0 2 o 5 0 -10 15 CZ -20 -25 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 5% absolute error 20 0 Red Eye 2G, NEL, Aug 2005, Horizontal d 2 15 Red Eye 2G, NEL, Feb 2006, Horizontal Red Eye 2G, NEL, Nov 2006, Horizontal 10 0 y 5— ti) 0 da B j• o o •1 -10 0 U y -15 m -20 25 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 South East Asia Hydrocarbon Flow Measurement Workshop 7 9 th March 2007 25 +1- 5% absolute error 20 Red Eye 2G, NEL, Feb 2006, Horizontal d Red Eye 2G, NEL, Nov 2006, Horizontal at 15 w d 10 O 0 7 6 0 N co o -5 :(2.2 f 41 -10 I; -15 lC -20 -25 I 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 +1- 5% absolute error 20 x Red Eye 2G, NEL, Aug 2005, Vertical 15 Red Eye 2G, NEL, Feb 2006, Horizontal Red Eye 2G, NEL, Nov 2006, Horizontal 10 0 w O 5 to 0 X ��t x -5 9 d -10 0 6 -15– m -20 -25 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 9 th March 2007 25 +1 5% absolute error 20 u Red Eye 2G, NEL, Feb 2006, Horizontal a 15 0 m m E 10 2 w y 5- 3 rn 0 o m -10 U 3 -15 -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 5% absolute error 20 O Red Eye 2G, NEL, Feb 2006, Horizontal aw 15 d at 10 2 5 5 Z• +s• i 0 -10 `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 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9th March 2007 25 5% absolute error 20 x Red Eye 2G, NEL, Aug 2005, Vertical w 15 Red Eye 2G, NEL, Feb 2006, Horizontal Red Eye 2G, NEL, Nov 2006, Horizontal 10 2 x x x x x x x y 5 x is x _3 x x O Q 0 (0 -5 2" m -10 v d -15 -20 -25 1 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 +1 5% absolute error 20 tOi Red Eye 2G, NEL, Feb 2006, Horizontal y 15 a, a> 10 0 d 5 t S o co -5 C D -10 U U y -15 co 20 -25 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 th 9 th March 2007 25 +1- 5% absolute error 20 Z.) Red Eye 2G, NEL, Feb 2006, Horizontal w 1 5 t tZ 5 Q' -10 3 v -15 -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 +1 5% absolute error 20 Red Eye 2G, NEL, Aug 2005, Horizontal d U Red Eye 2G, NEL, Feb 2006, Horizontal a a i 15 m 10 2 a, 5 3 0 m -10 U -15 R -20 25 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 6 South East Asia Hydrocarbon Flow Measurement Workshop 7 th 9 th March 2007 25 +1 5% absolute error 20 o Red Eye 2G, NEL, Aug 2005, Horizontal V x Red Eye 2G, NEL, Aug 2005, Vertical E) 15 Red Eye 2G, NEL, Nov 2006, Horizontal 10 2 y 5 O Q 0 3E x m 0 0 0 O 00 t6 ma 0 1] p O O °I. -5 _0 2 `5 -10 V m -15 ia -20 -25 I 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 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. 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 applications 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 problem 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 century 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 e flows, the time averaged axial r z velocity varies with radial position, >5 i from zero the wall to a maximum at the centerline of the pipe. The flow C011116501.1.119411.1011 ILLSOCS MSS near the wall is characterized by steep velocity gradients and n 1 transitions to relatively uniform core w s x a flow near the center of the pipe. N;: Figure 1 shows a representative ill I schematic of a velocity profile and "OFY .r1N 4 or *KV I, 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 similar Empirical studies have shown that velocity profiles in turbulent pipe flows are well represented by the 1 over n power law: U R) 0 90% with n ranging from 6 to 10 as a weak function of Reynolds number. From a measurement perspective, the 85% 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 800/0 between the ratio V /Uo and the Reynolds number is shown in Figure 2, 75% 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 70% I I I 111111 above the critical Reynolds number for 1.E+03 1.E+04 1.E+05 1.E+06 1.E+07 turbulent flow to greater than 85% at Reynolds number Reynolds numbers over one million. It Figure 2: Mean velocity normalized by Maximum must be stressed that, given the velocity velocity vs. Reynolds number. profile (1), very little fluid is actually flowing at the mean flow velocity. 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 e i e. These structures remain coherent for several pipe PP 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 structure sonar flow metering methodology uses the convection velocity of coherent struc ure 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: co =kv (2). Here is the wave number, defined as k =2n /A (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 40 temporal frequency content of time 35 stationary sound fields are often _55 displayed using "k -w plots k -w plots F are essentially two dimensional power spectra in which the power of 20 -60 a pressure field is decomposed into bins corresponding to specific spatial 15 p 9 P P wave numbers and temporal frequencies. On a k -w plot, the power 5 associated with a pressure field .70 convecting with the flow is distributed 0 5 10 15 20 zs in regions which satisfy the w.venumb« 11 Mc) 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. A low -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 A is, in terms of the Reynolds number Re and a set of three coefficients C1, C2 and C3, unique to each sonar meter size given by (3). 0 C, C c (3). Re' BI0197 RevB 4 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% 5 -0.5% accuracy. It is important to Production SONARtrac Flow Meter Data 95% ence Level 0 42% 511360830085-109 01 Sch 10T 5DDB22 note that this flow 1.00% 50560830085 -115 Sch 10 T 10D B2 SND65830085 -116 Soh 10T5D B2 metering approach has no S0560830085 -117 Bch 10 T 10D B2 0.75% S1060830085-118 Soh 10 T 5D B2 fundamental size SN060830085 -109 Bch 10 T 10D B1 C SW60830085-111 Sch 10 T 5D B1 limitations and should be 0.50% applicable to turbulent 0.25 11.• pipe flows of all diameters and Reynolds numbers. Is 0.00% 106 o Furthermore, similarity .0.25% 3—g-0-0 laws suggest, and data from Figure 4 support, -0.50% that the relationship -0.75% between convection velocity and flow rate from -1.00% geometrically similar 0.00E+00 5.00E+05 1.00E+06 1.50E+06 2.00E+06 2.50E+06 3.00E+06 R 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 sand Thick stock flow in paper and pulp Air conveyed transport of particulate material. Two phase flow of water and oil 11 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 /dm and low (1.65 kg /dm density magnetite suspensions in the feed flow to a BI0197 RevB 5 Flomeko 2005 6 9 June 2005 30000 100 10000 100% HIGH LOW 24000 80% 8000 80% O 6 18000 60% c 6000 60% a O O O O 0 12000 40% C) 4000 40% 6000 20% 2000 20% 0 0% 0% 5% 10% 15% 20% 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 rule known as Wood's equation 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 q, 1 P' 2 Pg C g PI C T (4). P= 0P +(l OP/ Here, cp is the volume fraction of gas at line conditions, c is the speed of sound, p the density and the subscripts and I refer to the gas and liquid phase respectively. Fi ure 6 illustrates P g 9 q P Figure 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 6 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 irrespective of the type -1 bar of gas, which can be 2 bar either air, carbon a 3 bar dioxide, hydrogen or 0 any mixture thereof. c 100? Z.."; 4 bar 5 b For mixtures confined ci) to a pipe, a correction 2 to above formulae (4) is necessary in order to account for the relative 10 change of pipe cross 0% 5% 10% 15% 20% sectional area upon internal pressure Gas volume fraction variation. This so called distensibility Figure 6: Mixture sound speed vs. gas volume fraction. D, is an additive term to the first equation of (4). The distensibility for thin walled, untethered pipe is given by: D Et (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 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 =2t (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 shows a k- w plot gene acoustic sound fi recorded rated from for still water containing eld 450 —3% entrained air by volume in an -55 8 in schedule 80, vertically oriented Plexiglas pipe. The k -w I 3 plot was constructed using data from an array of strain based sensors clamped to the outside of LL the pipe. Two acoustic ridges are 200 clearly evident. Based on the -65 slopes of the acoustic ridges, the 150 measured sound speed for this for 1% this mixture was 70 m /s, consistent with that predicted by the Wood 15 10 -5 0 5 10 15 equation. Note that adding 3% air w«ttiti by volume reduces the sound speed of the bubbly mixture to less Figure 7: k plot for 3% entrained air in water. 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 headbox 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 8 Flomeko 2005 110 6 -9 June 2005 Errors in consistency measurement of paper stock. Errors in the determination of net oil using watercut meters Errors in Coriolis determined volume flow as a result of product aeration 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 7 stock just before and just after the 6 dosing of a commercially available e_ defoamer chemical. Given the 0 5 continuous character of the 4 measurement and given the fact it that this full bore measurement is, E 3 unlike a sampling system, representative of the true air 2 content the ability to control co defoamer dosing presents itself. Such dosing control will not only o help reduce defoamer volume it -120 -60 0 60 120 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 9 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, April 2000, 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 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 10 •i 'SPE international 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 Introduction This paper was prepared for presentation at the 2006 SPE Westem Regional /AAPG Pacific Section /GSA Cordilleran Section Joint Meeting held in Anchorage, Alaska, U.S.A., 8-10 May 2006. The PBU has been in production since 1977. Over the life This paper was selected for presentation by an SPE Program Committee following review of of the field several different Test Separator configurations 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 have been utilized. Approximately 16 years ago, PBU started 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 to use the density water cut method on 2 -Phase Mini Test SPE meetings are subject to publication review by Editorial Committees of the Society of Separators to overcome problems that were encountered on 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 the conventional 3 -Phase Units. In general these units operated prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous successfully; success was measured by repeatable water cut acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. results that enabled the p engineers ineers to improve Box 833836, Richardson, TX 75083 -3836, U.S.A., fax 01- 972 952 -9435. I� g management of the wells and have more confidence in Abstract 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 For the first time in a BP- operated asset, the impact of entrained free gas (not solution gas) in the liquid outlet line of from 22 to 32 API now down to 17 API. This brought a whole a well test separator is quantified for the purpose of correcting new set of problems. As part of this project two new mini 2- gross fluid volumes and density measurement. This paper Phase Test Separators were installed. describes the results of deploying a sonar based, clamp -on gas void fraction (GVF) meter at a test facility in the Prudhoe Bay A review of the liquid leg densities of the units handling Unit (PBU) on Alaska's North Slope. 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 This paper is a brief report of the findings of a preliminary was confirmed that discrepancies in allocation factors and test and a more extensive pilot project of a strap -on sonar individual net oil measurements, especially for cold high based GVF meter on both `non- viscous' crude oil and satellite field viscous oil. The preliminary test was a uick check to viscous crude oil, was due in part to unrecognized gas carry- p ry q under in the liquid outlet. Measured GVF associated with determine if the GVF meter could measure a meaningful GVF wells flowing `non- viscous' oil, the less viscous crude (22 to on the two crudes. With a favorable result to the preliminary 32 API) ranged from 0 2.0 whereas the GVF of wells test the pilot project was instigated and the unit was installed flowing viscous crude (17 to 22 API) was between 0 8% at and fully integrated into the well testing system. Since being normal vessel liquid levels increasing to >20% at reduced installed in October 2005, the unit has been used for on -line separator levels. well testing. The objective was not only accurate GVF measurement to improve water cut and gross fluid volume The additional secondary phase measurement enables PBU accuracy but also to check for long term stability. A stable to now report real time corrected densities and volumes using Zero GVF measurement is a critical issue especially when the an in -house method to calculate water cut. In addition to unit is used for all types of crude oil and on many wells having viscous crude, we believe that application of this technology little to no GVF. to smaller, somewhat under -sized separators with less stable operations will provide value across the industry. To quantify the impact of GVF on the Test Separator operations in PBU, a 1% GVF equates to an understatement of Well testing importance is increasing on the maturing water cut (WC) by 5% and a direct 1% over statement of gross fields of the North Slope of Alaska as it is not only used for fluid flow. the critical function of field management that ensures optimum production from a field; it also is a regulatory As the title of this paper indicates this meter provides a requirement set by the State of Alaska and may be used for solution to a long standing problem. This is the final piece of a Production Volume Accounting on fields with co- mingled puzzle that has taken many years to solve. In order to have a production facilities. better understanding of how our approach has developed the first few sections of this paper will provide a brief overview of 2 SPE 100893 the PBU and a history of Well Testing, Oil Allocation and produced through the PBU facilities. Well testing is again Test Separator improvements in the PBU. mainly for field management but more importantly for regulatory purposes to prove the field is being operated and Overview of Greater Prudhoe Bay (GPB) 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 Oil Allocation Methodology largest and has been the main driving force in the development of the Test Separator Systems described in this paper. The As the PBU evolved over time, so has the Oil Allocation most recent business need has been the introduction of small Process changed to meet the new challenges. WOA has three satellite fields to the IPA facilities and the problems of cold production facilities known as Gathering Centers (GC) where viscous oil. The PBU was from concept split into two oil, gas and water are separated, the gas is dehydrated before operating areas by the owners with the agreement of the State shipment to the Gas Plants and re- injection into the field. The of Alaska; the Western Operating Area (WOA) operated by EOA also has three production facilities known as Flow BP and the Eastern Operating Area (EOA) operated by Stations (FS). Oil is shipped to Pump Station 1 (PS 1) of the Atlantic Richfield Company (ARCO). In addition there was a Trans Alaska Pipeline System (TAPS) for metering to custody different ownership split between the Gas Cap and the Oil transfer standards. Alyeska Pipeline Service Company Rim Participating Areas. After the BP /ARCO merger, BP is (ALPS), the company operating TAPS, operated two metering now the sole Operator of PBU and the field has been unitized systems, one each for EOA and WOA. As production has with aligned working interest ownerships in Gas Cap and Oil declined ALPS reduced metering to one combined meter set Rim Participating Areas. for EOA and WOA. Also GC 3 passes partially processed oil p g P Yp P to FS 3 so only five production facilities are now producing The Test Separator operations described in this paper are from directly to TAPS. All of these changes have had an impact on the WOA. the allocation process. Impacts of Well Testing The following simplistic statistical model demonstrates the impact of metering accuracy on the allocation process. Taking As with all oil and gas fields, PBU well testing is used for the WOA as a model there are three levels at which oil field management. A very critical function used to optimize metering is made; Fiscally at PS 1, Production Metering at the production rates and total hydrocarbon recovery from the outlet of the GC and individual well production (Well field. Testing). In order to measure a total volume of 300 MBPD to an accuracy of 1% the choice is to either measure with one With the early ownership differences between the Gas Cap 300 MBPD meter with an accuracy of 1 or three 100 and the Oil Rim, well testing was critical in the determination MBPD meters with an accuracy of 1.75% or three hundred 1 of the Gas Oil Ratio (GOR), one of the parameters used to MBPD meters with an accuracy of 17 select a well for inclusion in the Gas Cap or Oil Rim. As gas production increased beyond the agreed associated gas volume The WOA has gone from initial allocating process of (determined at a 1000 GOR) the importance of well testing in allocating from PS 1 to the GCs and then to the associated this area reduced and the gas condensate allocation was then wells to allocating directly from PS 1 to the all wells and back by an agreed liquid volume factor in the gas and simply to the intermediate GC step process. The reason for the determined by measuring the overall gas volume. 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 The introduction of satellite field production into the IPA areas. Processing Facilities created the problem of production allocation to the correct field. There was a different tax Brief History of Test Separators royalty regime for IPA and the PBU satellite fields. By prior agreement with the State of Alaska well allocation was the The following describes the fixed in place Test Separators. selected method for individual field production. The overall If at any time these units were having operational problems volume of crude oil was measured to custody transfer Portable Separators were utilized to ensure the required well standards; allocation and well testing determines the testing was performed and the overall allocation process was production split between the IPA and the individual satellite accurately maintained. fields. This obviously increased the importance of well testing and PBU in collaboration with the State of Alaska undertook a The initial test separators were Test Banks (3 Stages of major program to upgrade and improve oil allocation and well Separation) in the GCs. This ensured the oil volume testing operations. measurement was of sales quality crude corrected to Stock Tank Barrels (STB). As the field developed Test Separators With the merger of ARCO and BP the PBU Gas Cap Oil were installed at the Well Pads operating at elevated pressures. Rim ownership difference has been eliminated. Also the State This introduced the problem of "Oil Shrinkage the change in of Alaska has recently equalized the taxation rate for all oil volume of live crude at test separator conditions to STB. SPE 100893 3 To overcome this problem PBU carried out a large project count the existing methods of calibration became virtually of correlating test results from the Well Pad Separators to the impossible to maintain. In addition the laboratory analyzer same well tested in the Test Bank. From this large data base an proved not to be satisfactory and was taken out of service. All algorithm were developed that provided two factors, Oil of these problems lead to a fundamental reevaluation of the Shrinkage and Solution Gas (SCF per unit volume) to be calibration methods and even the density method itself. applied to the Test Separator results. Recently PBU updated this data base utilizing a customized equation of state to New Approach to the Water Cut Density Method improve the accuracy of these factors. The following is only a brief outline of the in -house The initial Well Pad Test Separators were large 150 Barrel developed method that will assist with understanding the main 3 -Phase units. Turbine meters were used for oil, water and gas. topic of this paper; GVF measurement and the application to Master Water and Oil Meters were installed to check the test separators. The basic intent of the method was to reduce accuracy of the on -line meters. A capacitance probe was sampling requirements while not impacting metering installed in the oil leg to detect the water cut up to 20 In accuracy. general these systems worked well but problems started to The method is based on mass which does not change for appear when the water cut and GOR started to increase. This pressure and temperature variations or for mixing two fluids was especially true when PBU came off the production together even if they are in different phases. Live crude is just plateau. Several improvements were made including replacing stock tank barrel crude oil with gas in solution. Therefore the the liquid turbine meters with vortex units and modifying density of live crude can be predicted by simply adding the internals of the separators. The significant problem with the mass of the oil and the mass of the solution gas together. capacitance probe system was that it could only be customized The key to understanding this system is oil shrinkage and on a per well pad basis and individual wells on the same well solution gas. These parameters are fundamental to well testing pad were exhibiting significant different physical properties at elevated pressures and temperatures. Typically a well test which impacted the water cut accuracy. determines the volume of live oil at separator conditions; the oil volume is then shrunk to provide the daily production PBU had installed three mini (40 Barrel) 3 -Phase Test volume in STB terms. Separators that were experiencing significant problems. The The density of stabilized crude and dry gas can be results made any field management of the wells in that area determined at both base and line conditions (Pressure and very difficult. In 1989 PBU decided to install a direct mass Temperature compensated) using API and AGA Standards. flow meter using the density water cut method on the liquid The density of water can be determined by well established leg of the separator which was converted to a 2 -Phase unit, and internationally accepted algorithms at both line and base conditions. This method proved so successful that it was installed on The hydrocarbon (Oil plus Gas) density at line conditions eight of the 3 -Phase Units. In addition the three GC Test Bank is the sum of the oil line density with oil shrinkage applied Separators have been reduced to a single stage unit using the plus the mass of solution gas on a per unit basis. The water cut density water cut method. The two new satellite field Mini is determined using the standard equation for the mixture of (30 Barrel) 2 -Phase Separators are all based on this method. two fluids of known densities from the measurement of the These units did have a microwave water cut meter installed in line fluid density of the combined fluids. the liquid leg, but they have never been used on -line. The unique part of the method is that the actual oil, gas and water volumes at line conditions can be determined. Therefore Water Cut Calibration Methods for Density Based Water it is possible to mass balance the liquid leg by comparing this Cut Measurement calculated mass to the measured mass flow from the direct mass flow meter. The method adjusts the solution gas in the All water cut analyzers need to be customized to specific density model until 100% mass balance is achieved. This has well fluids. This may even be on a per well basis, been demonstrated to improve the water cut accuracy. The proprietary system installed required a `pseudo' oil density that would be temperature compensated using API Benefits of the New Approach Volume Correction Tables to give the oil density at line conditions. The first calibration method implemented simply The oil shrinkage and solution gas factors are based on fixed the water density and adjusted the oil density until the pressure, temperature and GOR. Therefore the metering on the water cut matched spinout tests of the crude oil for each well. Test Separator is now fully integrated as the off gas flow This was later improved by taking live samples to the impacts the liquid leg measurement for oil and water. More laboratory where an analyzer measured the oil and water specifically the hydrocarbon fluid density in the liquid leg is densities at line conditions and the' pseudo' density was fully compensated to all pressure, temperature and GOR calculated. Both methods were satisfactory but required conditions. The only parameters to be input to the method are careful co- ordination of the well in the Test Separator during the base specific gravities of dry oil and water. This sampling and were very man -hour intensive. significantly reduces the sampling complexity as only the well With the updating of the eight 3 -Phase Test Separators to fluids at STB conditions are required and not at the line 2 -Phase Units, the addition of the two new 2 -Phase Units for conditions. the viscous oil and the associated significant increase in well 4 S SPE 100893 As the method provides on a real time basis the STB water enough to sweep the buildup of free gas. See Figures 1 and 2 cut, it can be compared directly to the laboratory determined for the GVF plots of these tests water cut which is made at 0 PSIG. There is a significant difference between the on -line water cut and the STB water 0 cut especially with oil shrinkages of up to 30 0.6 Problems on the Viscous Oil Test Separators 0.5 Most of the early problems were associated with the fact 0.4 the units were open to the Artie environment and meters were not installed in the most advantageous way. These difficulties 0'3 were slowly overcome and the new density method was G 0.2 installed on the separators. A review of the measured density in the liquid leg of the separators indicated a significant 0 1 q y quantity of gas in the liquid leg which had a detrimental YY 0 4 'I.,,An impact on both the total fluid volume and the water cut 5/20/200517:1500 5/20/2005 17:22:12 5/20/2005 17:29:24 5/20/2005 17:36:36 5/20/200517:43:48 5/20/200517:51.00 determination. The addition of GVF in the liquid leg means Figure 1 Downstream GVF Meter on a Typical PBU Well (26 °API there are three unknowns but the calculation method only and 98 °F) provides two equations. The third unknown, GVF had to be quantified for the density method to work. 35 Selection of the GVF Meter 30 Upstream BP was performing wet gas meter tests and during a 25 Downstream presentation of this test a sonar based strap -on unit was p 1 /4, resented that was claimed to measure GVF in the 0 -20 20 range. The unit is passive; it listens to audio frequency noise 15 signals in the fluid and using sonar techniques determines the speed of sound (SOS) of the fluid in the pipe. In this frequency 0 10 range the wavelengths are several feet, therefore the :040.0 transducer is measuring the physical properties e.g. free gas 5 that is present a significant volume of the fluid and not just a 0 slice across the pipe. The relationship between the SOS and 5/22/20056:30 5/22/20057:42 5/22/2005 8:54 5/22/ 200510:06 5/2'/200511:16 5/22/2045 32:30 gas in a liquid (GVF) is very well established and documented. Figure 2 Comparison of Upstream and Downstream GVF Meters on a Cold Viscous Well (18 °API and 54 °F) Preliminary Tests Extended Pilot Test It was decided to erform a preliminary test on the liquid p P rY q leg of a Test Separator that tested both PBU and satellite crude As a result of the favorable preliminary test it was decided wells. The objective of these very simple tests was to to install a unit into the well testing system and to monitor its determine if the unit would measure a GVF and whether it performance. The new in -house density approach is would track expected GVF values when the level in the vessel programmed into a stand alone flow computer that has fully was raised or lowered. Two units were installed; one upstream flexible customer programming capability. The program was of the mass meter (horizontal) and a second downstream of the updated to include the GVF function in both the density mass meter (vertical down). The intent of the preliminary tests calculation and the gross volume calculation. In addition the was not only to confirm satisfactory operation of the GVF free gas was added to the off gas and the free gas was included meter but also to try and select the best position for a more in the mass balance of the liquid leg. extensive test. To enable the operation to be monitored closely an extensive data gathering system was also configured into the The results of two days of trials were very favorable. A flow computer and the Supervisory Control and Data GVF was measured in both crudes in the range of 0 30 Acquisition (SCADA) System. The SCADA System performs The GVF measurement performed as expected; it increased in the well test function and the following parameters were value for a lowering vessel liquid level and decreased in value retrieved in addition to the standard data for well testing. for an increasing vessel liquid level. Typically both units tracked; however on high GVF values 15 the Gas Void Fraction downstream meter indicated up to twice the upstream unit. On-line Measured Density This was believed to be a piping issue with gas trapped in an GVF Corrected Density inverted U section of pipe and the flow of fluid was not great Calculated On -line Hydrocarbon Density Calculated On -Line Water Density SPE 100893 5 Mass Flow testing cold heavy viscous crude the results presented and STB Oil Flow discussed in this paper are for a viscous well. STB Water Flow On -line GOR The initial tests on one particular well showed little to no STB GOR GVF but as time progressed tests started to have large GVF Mass Balance swings and plateaus on the GVF data plot. The status of the Solution Gas Correction Factor unit was low signal quality and invalid SOS data. The first reaction was to question whether there was enough noise to Data was gathered approximately every 20 seconds. enable the meter to function. After all the unit in use had the greatest distance to the liquid control valve, the expected This real time data has enabled PBU for the first time to source of the noise. A data "snap shot" was submitted to the monitor very closely how the density method operates on a 2- manufacturer who stated the signal strength was good but the Phase Separator. unit was not able to successfully analyze the SOS data. It was noted that when the wells are tested with the portable Review of Preliminary Results of the Pilot Test separator unit chemicals are injected into the crude, in particular anti -foam. The water cut methodology is based on fluid densities so Anti foam was injected into the well flow line. Figure 3 tracking how the hydrocarbon and water densities vary on -line shows the response of the GVF Meter and the density water cut methodology to this anti -foam. The plot is for 8 hours with and how the measured liquid leg fluid density compares to these densities is critical. For example the GVF values we the anti -foam injected at approximately 5 hours into the plot. have witnessed on these tests can take the measured density The well test was for 4 hours and this plot shows the first 3 from less than the hydrocarbon density to higher than the hours of this test. There was an immediate improvement to the water density. That is from 0% water to 100% water. whole system. Parameters no longer had wild variations and The test separator is at an unmanned site and the only the GVF corrected density was now solidly in between the monitoring is restricted to measured calculated variables; it hydrocarbon and water densities and steady. For the well in was not feasible to bring back the status of the sonar unit. The question the measured on-line density was significantly below dilemma is to know when an accurate GVF is being measured. the calculated on -line hydrocarbon density. 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. Line Density GVFCor Density HC Cale Density Water Calc Density GVF Reviewing the GVF transmitter status when this happens reveals two basic reasons; either poor signal quality or invalid 66 20 speed of sound data. 64 18 sz LN111111'!11"6 14 The downstream unit was selected as the primary meter for 58 r�i�l�wl�J�j� 12 e the test. Initial results looked promising; however we y ss 10 EmEEEE witnessed excessive swings in the indicated GVF (0 to 20 d 54 8 with the associated large variations in water cut. This was a 52 6 repeat of the high GVF measured during the preliminary test 50 ��,�1 2 caused by a buildup of free gas in the inverted U section. The 48 0 upstream unit was now selected and all tests were made using 0 60 120 180 240 300 360 420 this unit. Minutes The first criterion for success was to determine if the GVF corrected line density lies between the hydrocarbon and the Figure 3 the impact of Anti -Foam on the performance of the GVF Meter on Viscous Crude Oil water densities. If this is satisfied the metering methodology will be able mass balance the liquid leg of the separator. The The following well test result using the fixed separator and method will not be able to mass balance the liquid leg if this the new methodology including the GVF Meter and the criteria is not met. standard SCADA well testing system was obtained and A Portable Test Separator is used to check well tests compared to the last Portable Test Separator test especially if the results are questionable. This portable separator is manned on a 24/7 basis and it is customized for Portable Fixed each well test. This is considered the best well test we can Separator Separator achieve. Oil BPD 366 498 Therefore the second criterion was to compare the well test Water BPD 29 42 result from the on -line separator to the last test using the GOR 1142 1272 portable separator. Water Cut 7.3 7.8 In general the unit operated satisfactorily on PBU crude. Table 1 Well Test Comparison of Portable to Fixed Test However as the main reason for using the GVF meter was Separator 6 SPE 100893 Conclusions Nomenclature The preliminary results of the pilot test to date look very GVF Gas Void Fraction promising; the objectives of the test are being met, i.e. to API American Petroleum Institute check the long term stability and performance of the GVF AGA American Gas Association Meter under differing conditions. The presence of free gas in PBU Prudhoe Bay Unit (Oil Field on the North Slope) the liquid leg of the mini Test Separator when testing cold IPA Initial Participating Areas viscous wells was postulated; the GVF Meter has provided a GPB Greater Prudhoe Bay (PBU plus Greater Point quantitative measurement of this free gas. The secondary Macintyre and other satellite fields) objective was to try and determine limitations of GVF Meter WOA Western Operating Area of the PBU which we have achieved. When testing viscous wells with EOA Eastern Operating Area of the PBU water present it is important to inject anti -foam to make the GOR Gas Oil Ration SCF Barrel system operate correctly. Please note these wells have gas GC Gathering Center (Production Facilities in the WOA) artificial lift. FS Flow Station (Production Facilities in the EOA) TAPS Trans Alaska Pipeline System Only the results of one well are provided here because ALPS Alyeska Pipeline Service Company. formal review all the data from all wells needs to be collected PS 1 Pump Station 1 of TAPS before it can be disseminated. Preliminary reviews indicate MBPD Thousand Barrels per Day that a GVF is present in all well testing even on the PBU STB Stock Tank Barrels (Base Conditions 0 PSIG 60 °F) wells. However three of these GVF Meters will be installed on SCF Standard Cubic Feet (Base Conditions 14.65 PSIA three mini 2 -Phase Test Separators working on viscous and 60 °F) PBU crude oil. PSIG Pounds per Square Inch Gauge PSIA Pounds per Square Inch Absolute Several years of work has gone into perfecting the SOS Speed of Sound approach to the density method water cut. The addition of the WC Water Cut 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. X15 • • 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 31st 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 (Alaskal, Inc. March 13, 2008 BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 Tel: (907) 5645769 Fax: (907) 564-5706 Email: gordon.pospisil~bp.com ~~, . ~,~' 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: • x,a. s ;~ ~~ ~~3r ~, ~ ~~ ;ii78~®~s a~ a'']~~ 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 ~ in accordance with plans outlined in their a-mail correspondence to Jane Williarrsc. ~ 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. 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; BPXA Request for Clarification Meeting and Request for Hearing Page 2 21 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 VxTM 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 VxTM and the EMSTM 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, *._., // ~ ~/ /C 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 x-14 by Gordon Pospisii Technology & Resource Manager BP Exploration (Alaska), Inc. November 14, 2007 John K. Norman Chairman A{aska 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) 5645706 Email: gotdon.pospisi4@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 EMST"' meter system for well testing and allocation on the following conditions: 1) The EMST"' 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: 11 The VxT"" meter system is operated in accordance with BPXA's application; 2) BPXA conducts field testing of the VxT"' with a CDS-Gasunie separator system in a manner consistent with the agreed upon testing protocols referenced in condition 2 above for the EMST"' meter system; BPXA Request for Clarification IVI~f ng and Request for Hearing Page 2 • 3) The Commission may revoke the field testing requirement for the VxT"' 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"' rY'°te~' to begin in i ~ ir1 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, `j ~ . ~~, .., t-: 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, ExxonMobi{ Dan Kruse, CPAI 1t-13 bp . e.. c: ~b' August 10, 2007 BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 John K. Norman Chairman Alaska Oil & Gas Conservation Commission 333 West th Avenue, Suite 100 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 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,fWificant 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, ~ /)/7 ---,' .'ð -G=~C~ 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 PO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561,5111 2 4*12 STATE 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 ATTACHED COPY OF ORDER 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 Jodv Colombie ADril 25 2007 0 Anchorage, AK 99501 PHONE PCN M 907 -793-1238 · (907) 793 -1221 DATES ADVERTISEMENT REQUIRED: T Anchorage Daily News April 26, 2007 0 PO Box 149001 Anchorage, AK 99514 THE MATERIAL BE1WEEN 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¡:g 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 9950 I 2 PAGES REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 FIN AMOUNT SV CC PGM LC ACCT FY NMR OIST UQ 1 05 02140100 73451 2 -" Î" /~\ ¡ REQUIS~ON; ¿Bt l' fAll) / /DIVISION APPROVAL: ~ / \:I¿/V- ..., 02-902 (Rev:.1/94 Publisher/O . 'oal Co ies: De artmeot Fisca De artmeo Receivin . . ) ngI p p I, p t, ~ . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: BPExploration (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 7th 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. ) ~ A / . . Anchorage Daily News Affidavit of Publication 4/26/2007 1001 Northway Dnve. 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 50.00 $0.00 $0.00 $000 $0.00 $242.36 Notice of Public Hearing Si STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: BP Exploration (Aloska) Inc. ("BPXA") has requested outhorization to "use multi phase meters for well testing ond allocation of production for 01'1 pools within the Bodami, Endicott, Milne Point, Northstar, and Prudhoe Bay Fields. BY applicdtion dated Morch 30, 2007, and received April'll, 2007, BPXA requested au~horization. fr?m the Alaska Oil and Gos Conservatu:mCommlss,on (" CommiSsion"), to· use a portoblemultiphase.meo," surement device for well testing ion BPXA operated fields in accordance with th~:Commis~ion'sdocu,~ ment, "Guidelines for Qualificationof"M~ltiphase Meters for Well Testing" dated November 30,2004 as'allowed by the following Conservation Orders: P.rudhoeBav Field: co 559: pyt~iverOil Pobl : CO:·570:Raven'Ç>ilF1001 co 547: AI Fbttier oil pools within , Prudhoe Bay Field Endicott Field: Mrí;f~df~it!:êTd~diCOtl pools :CO. 550': jAil Milne Point pools Northstar Field: CO 551 :.NorthstarOil Pool Badami Fiero: C0402A:Badami Oil PoOl 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 Third Judicial Court, Anchorage, Alaska, and it now and has been pubiished in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during 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 form) 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 4fUÁJ / I sworn to me before this date: { '_>:"-_.,:;-,.'::>:;)1;<,;;< The Commisslon has tentativelY scheduled a public hearing on thls application.for May 31,'2007 at 9:00 am at the offiéesof the Alaska Oil and Gas Conser- v'atlon 'Commission at '333 West 7th Avenue, S.uite 100, Anéhorage; Alaska 99501. A per.son may re- quest that the tentativelY scheduled hearing b!! held bY filing a written request with the. Commission no later \han. May 15, 2007. If a· request for a hearing' is not timely filed, th" CommIssionmovconsider the issuance of anprder without a hearing. To learn if the Commission will hold the. public hearing, please call 793-1221 after May 29; 2007. J7 9JJO? ... .." .,., ~ . .' ,. ,. "'.. > In -09dinpn" a~erson' mOY_ submit -written cornme~ts regdrdins t~lsqpplicalion to the<A,las~qpilqGd..q,I'S Conservat.ion Commis.slon 0.1,333 VV~~t7thAy:e~~,~, Suite 100, Anchorage, Alaska.9950L.Written com- mentsmystbe received no l.ater than May 29, 2007 except thdtiftheCommission decíde~t.qÞPI~ a pub- lic hearing, written. protest orc9rnJ~'~pts::I:D~~t be received no later thpn the conclusíqrofll1~MPX,31, 2007 hearing; '. .' .o.. If YOU are a person witti a disabilitywho",av n.eed a special' r:ryo~ification'; n _ orderjo:cOTrnen~ or t~ at- tend'tne public h!!aring, please Qontact the Commission's Special Assistant JodyColombie at 793-1221 before May 29, 2007. Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska . MY OMMISSION EXPIRES, 07fr Wl I \\\((!((({((/r. 1IJ'f.,~';~ .~. -t~'l .~. "=-a... * .,;~~ Cf~··~O..~~i?~:~~ ~~: ÞüB~}C : ~ ~'.I/I · :to..:::: -0Z:;.\. "'.... -,"?".';;:>:-' -;:. .-~ ~. &¡-::: -:;.. ... ~ OF Þ.\J'i. .~. . <)":V ........, '. '. ¡ .:.' . , .~ ..~. "I."" ... ./,; :'" k~)f¡:¡¡ïaf,·. ?P'f~ ..... 1 /}j)jjJ}j!jÌ\ /s/: John K. Norman Chai,man AO# 02714029 ¡ l·_~u:~.Hsh:APrH26,}~~ì,n ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS "",,1ST" '" "'OUCATE '""""NG ADVERTIS'NG ORDER .RT"'''' AO 02714029 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATIACHED COpy OF - ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC 333 West 7th Avenue. Suite 100 Anchor:::¡p"e_ AK QQS01 907-793-1238 AGENCY CONTACT J onv C( - L.' PHONE (907) 7Q1 -1 221 DATES ADVERTISEMENT REQUIRED: DATE OF A.O. R o M Annl ì'i J007 PCN T o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 April 26, 2007 THE MA TERJAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SROWN. 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 ~.~y 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@a~~in.state.ak.us] Sent: Wednesday, April 25, 2007 12:54 PM To: Ads, Legal Subject: Public Notice Thank you I of 1 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 <¡ od},' colorûbie(C~adrûiTI.state.al(. LiS> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content- Type: applicationlmsword Ad Order ADN form.doc Content-Encoding: base64 Content-Type: applicationlmsword MPM Notice 2.doc - - Content-Encoding: base64 I of I 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 14:11:26 -0800 . To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@adrnin.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra StewÍnan <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, trmjrl <trmjrl@aol.com>,jdarlington <jdarlington@forestoi1.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@rkindustrial.com>, ghammons <ghammons@ao1.com>, rmclean <rmclean@pobox.alaska.net>, m.km7200 <m.km7200@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>, Sharrnaine 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 <BilCFowler@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>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Gary Rogers <gary_rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur_Copoulos@dnr.state.ak.us>, Ken <klyons@otsintl.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa(â)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 <rnike@kbbi.org>, Garland Robinson <gbrobinson@marathonoi1.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 Silliphant <laura _ silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobil.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>, John Spain <jps@stateside.com>, Cody Rice <Cody _ Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Wine garner <jimwinegarner@brooksrangepetro.com>, Matt Rader <matt_rader@dnr.state.ak.us>, carol smyth <carol.smyth@shell.com>, Arthur C Saltmarsh <art_saltmarsh@adrnin.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 <Michael.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, "Alan Birnbaum <\"\"Alan J Birnbaum \">" <alan _ birnbaum\"@law.state.ak.us>, Randall Kanady <Randall.B.Kanady@conocophillips.com>, MJ Loveland <N 1878@conocophillips.com> Jody Colombie <jcdy colombie0J,admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf Multiphase meters notice.pdf b 64 Content-Encoding: ase 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 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 \ð~ \~\Ú\\ D 7 ~ \ð 11 #11 March 30 Multimetering This section is scanned separately and can be found under the parent folder for this file. 4f:1D Ll V\'U. II VVU. ...HVll l""lU ,<UUUU,",(.U.1VU.1 lUU.UV'"'JJ . . Subject: [Fwd: [Fwd: 3MField QualificationPlan.doc]] From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: rue, 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 <j ane williamson@acl,Ün. state. ak. us> Organization: State of Alaska To: Jody J Colombie <j 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 .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 corne up and tour the test setup when we are operational. Jerry «3MField QualificationPlan.doc» Jane Williamson, PE <:jane \villiamson(a¿admin.state.a..1ç.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission Content-Type: application/msword 3MField QualificationPlan.doc Content-Encoding: base64 of 1 11/14120063:16 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: o Various reservoirs and fluid conditions. · Prudhoe (Sadlerochit) · Kuparuk · Schrader Bluff o Gas Volume Fractions. · Low as practical « 60%) - 1 00% o Watercuts. · 0 - 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 44:q [Fwd: RE: Additional items] . . Subject: [Fwd: RE: Additional items] From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Man, 13 Nov 2006 11 :35:26 -0900 To: J odyJE)Ôlómbie<jÖdy _ colombie@admin.stafe.ak.us> This one goes into Badami for the MPM. -------- Original Message -------- RE: Additional items Tue, 10 Oct 2006 12:50:25 -0800 Brady, Jerry L <Jerry.Brady@bp.com> Jane Williamson <jane williamson@admin.state.ak.us> Subject: Date: From: To: Jane, Yes, please unless that is going to cause significant delays or other problems. Jerry ------------------------------------------------------------------------ *From:* Jane Williamson [mailto:jane williamson@admin.state.ak.us] *Sent:* Tuesday, October 10, 2006 12:07 PM *To:* Jane Williamson *Cc:* Brady, Jerry L *Subject:* Re: Additional items Jerry, You don't have Badami included in your application and I did not include it in the notice. If you want Badami included please let me know. Jane Jane Williamson, PE <iane williamson~admin.state.ak.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission 1 of 1 11/13/20062:49 PM [Fwd: RE: Notice] . . Subject: [Fwd: RE: Notice] From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: Mon, 13 Nov 2006 11 :36:43 -0900 To: Jody J Colombie <jody_colombi¢@adl1"J.iri.~tate.ak.u.s> This goes into all the MPM files -------- Original Message -------- RE: Notice Thu, 12 Oct 2006 17:21:27 -0800 Brady, Jerry L <Jerry.Brady@bp.com> Jane Williamson <jane williamson@admin.state.ak.us> Subject: Date: From: To: 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 10f3 11/13/20063:32 PM [Fwd: RE: Notice] . . 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 20f3 11/13/20063:32 PM [Fwd: RE: Notice] . . 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 <¡ane williamson@admin.state.ak.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission 30f3 11/13/20063:32 PM ~8 I.'WU. l\-L. ¡'<UllCt:J . . Subject: [Fwd: RE: Notice] From: Jane Williamson ~ane_ williamson@admin.state.ak.us> Date: Mon, 13 Nov 2006 11 :36:43 -0900 To: Jody J Colombie ~ody_co10mbie@admin.state.ak.us> This goes into all the MPM files -------- Original Message -------- RE: Notice Thu, 12 Oct 2006 17:21:27 -0800 Brady, Jerry L <Jerry.3rady@bp.com> Jane Williamson <jane wllliamson@admin.state.ak.us> Subject: Date: FraIn.: To: 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 l.VJailed AOGCC Jane Williamson 8/30/06 DNR - DOG Art Copoulos 8/30/06 DOR Robynn ('Elson 8/30/06 of3 11/13/20063:32 PM lJ yvu. i~. ;',\Vll\..\.,;J . . Subject: [Fwd: RE: Notice] From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: Man, 13 Nov 2006 11 :36:43 -0900 To: Jody J Colombie <jody _ colombie@admin.state.ak.us> This goes into all the MPM files -------- Original Message -------- RE: Notice Thu, 12 Oct 2006 lì:21:27 -0800 Brady, Jerry L <Jerry.Braay@bp.com> Jane Williamson ~jane williamson@admin.sta=e.ak.us> Subject: Date: trom: To: l.,Tane, 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 / ~Z\.gency Ccntact Narne DaLe Mailed AOGCC Jane í1illiamson 8/30/06 DNR - DOG .Z\.r t Copoulos 8/30/06 DOE 2obyn~: 'V'Jilson 8/3D/ 6 of3 11/13/20063:32 PM ll'WU. 1'.-". I~UlILc;J . . 10/12/06 lmadarko Mark Hanley 10/12/06 Union Oil Glenn Fredrick 10/12/06 Murphy Ignacio Herrera 10/11/06 Jerry ------------------------------------------------------------------------ *From:* Jane Williamson [cailto:jane williamson@admì~.state.ak.usJ *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.l the financially impacted parties are Chevron, ConocoPhillips, Exxon, Forest, Doyon, Nana, Murphy, DOG, MMS Jane Williamson, PE <¡ane williamson(âJadmin.state.ak.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission ) of3 11/13í2006 3:32 PM *1 . . FR;.uvK H. MURKOWSKI, GOVERNOR DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS o 550 WEST 7TH AVENUE. SUITE 800 ANCHORAGE, ALASKA 99501-3650 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 9950 1 Re: AOGCC "Application Report" for EMST'.! 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 E~lS 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: o Requests periodic reports on EJ\lS MPM perfonnance and evaluation. o Requests BPXA provide a summary of the MPM calibration and maintenance procedures and periodic results of the calibrations. "Develop, Conserve, and Enhance ,Vatural 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. SinCerely: /.i I .~ 1)11' G<~,_k:'{IVV~ :I /.. /." /,' t&,// V!!f~ William Van Dyke 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 4t;.{p . . Subject: Re: Recommendation to vacate Oct. 26 hearing on BP MPM application From: Cathy Foerster <cathy_foerster@admin.state.ak.us> Date: Tue, 17 Oct 2006 12: 1 0: 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 <daveJoby@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 10/17/2006 1:04 PM .""'...... "ob . ......_~~_.... . . Subject: Hearing vacated From: Jane Williamson <jane_ williamson@admin.state.ak.us> Date: Tue, 17 Oct 2006 12:19:09 -0800 To: Jerry Brady <bradyj1@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 <jane williamson(U¿admin.state.ak.us> Senior Reservoir Engineer (907) 793- I 226 Alaska Oil and Gas Conservation Commission ) f I I Oìl72ü06 104 PM "#-5 . . 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 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 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 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 th 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 moditìcation in order to comment or to attend the public hear' g, p ase contact the Commission's Special Assistant Jody Colombie at 793-1221 befo c r 23, 6. J r. C Published Date: September 22,", 6 AO 02714006 STATE OF ALASKA . NOTICE TO PUBLISHER . ADVERTISING ORDER NO. ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO.. CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02714006 F AOGCC AGENCY CONTACT OA TE OF A.O. R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M lody Colombie PHONE September 19,2006 PCN (907) 793 -1221 OATES AOVERTlSE'VIE~T REQUIRED: ¿ Anchorage Daily News September 22, 2006 Anchorage, AK THE MATERIAL BETWEEN THE DOUBLE LINES Ml'ST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL I~STR¡;CTlONS: Advertisement to be published was e-mai1ed STOF0330 Type of Advertisement Legal[g D Display Classified DOther (Specify) SEE A TT ACHED SEND INVOICE IN TRIPLICATE I AOGCC, 333 W. 7th Ave., Suite 100 TQ AnchonJ!!e. AK 9CJsnl REF TYPE NUMBER AMOUNT DA TE 1 VEN ¡ TOTALOF I PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS 2 ARD 3 4 02910 ~I'-I AM("\II'-IT c::v ('(' Pr.:M 1(' A(,(,T r::v NMR DrST lie 05 02140100 73451 2 3 4 REQUISITIONED BY: - .~ ,.-..... f···.. (\. 1.1 / \,: W·r,r; il- (..... '.k '¡ /0 .\N'~. ! ----- , ~ it .~i {I ____ \/,"j I,' .\ ,-. \] ¡DIVISION APPROVAL I 02-902 (Rev. 3/94) . . Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO. CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02714006 F AOGCC 333 West ih Avenue. Suite 100 A nrnrW!'wf' A J( QQ 'i n 1 907-793-1221 AGENCY CONTACT DATE OF A.O. R o Jodv Colombie Sentember ] 9. 2006 PHONE PCN (907) 793 -12) 1 DA TES ADVERTISEMENT REQURED: M T o Anchorage Daily News September 22, 2006 Anchorage, AK THE MA TERIAL BElWEEN THE DOUBLE LINES Ml:ST BE PRI'ITED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIOì\S: Advertisement to be published was e-mailed 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 SUBMITIED 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 helshe 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 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 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 . 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 Kay Munger Munger Oil Information Service. Inc PO Box 45738 Los Angeles, CA 90045-0738 Schlumberger Drilling and Measurements 2525 Gambell Street #400 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 Willìams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow. AK 99723 . 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 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Baker Oil Tools 4730 Business Park Blvd, #44 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 Oops . . 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: applicationlmsword Ad Order form.doc Content-Encoding: base64 Content- Type: applicationlmsword MPM Notice.doc Content-Encoding: base64 I of I 9/19/2006 I :39 PM t'UOIIC ¡\lance . . Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 19 Sep 2006 13:41 :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 <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjr l@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 1. Skillern" <SkilleRL@BP.com>, "Deborah 1. 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 1. 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 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.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, loren_Ieman <loren_Ieman@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@rkindustria1.com>, ghammons <ghammons@aol.com>, rmc1ean <rmc1ean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <itbmg@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>, n 1617@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/l 9/2006 1:53 PM PUblIC Notice . . <Iris_Matthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, Rob Dragnich <rob.g.dragnich@exxonmobil.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@marathonoil.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@marathonoil.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg ~imJegg@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@exxonmobil.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>, Sonja Franklin <sfranklin6@blomberg.net>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Cynthia B Mciver <bren _ mciver@admin.state.ak.us> Content-Type: applicationJpdf PBU END MILNE NS.pdf Content-Encoding: base64 : of2 9/1 9/2006 1 :53 PM '#=4 LA. ~~~. .I'-J......i. L.d~l""'" l~11 l~J. L"-.....·\..j,U......JLJ . . 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: Jody J Colombie <jody_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 200615:18:30 -0800 From: Brady, Jerry L <Jerry. .com> To: Jane Williamson <jane williamson@admin.state.ak.us> L~: Pospisil, Gordon <Gordon.Pospisil@bp.com>, Parviz Mehdizadeh .me~dizadeh@cox.net>, Dawson, Steve W (ASRC Energy Services) <steve.dawson@asrcenergy.cox>, Frontin, Russell A <Russell.Fro~tin@bp.com> Jane, We have discussed a testing plan wich 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 pla~ in place by then. ·Jerry -----Original Message----- From: Jane Williamson [mailtG:]2!12 W llia2s8~@admin.scate.ak.us] Sent: Friday, September IS, 2006 3:08 PM To: Brady, Jerry L Subject: EMS MPM Request Jerry I 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 fielà 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 bef re that time, please let me know. We can do an interim administrat ve approval fairly quickly. You'll need to provide your testing plans though (as I ve asked above) . Call It you have questions. ·Jane Jane Williamson, PE <jane williamsona;admin.state.ak.us> of2 10/6/2006 I :22 PM #'3 . . August 30,2006 Jane Williamson Alaska Oil & Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 Art Copoulos 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 AAC 25.228, and 20 AAC 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 . . 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 . . GUIDELINES For QUALIFICATION OF MUL TIPHASE METERING SYSTEMS FOR WELL TESTING November 30,2004 Alaska Oil & Gas Conservation Commission www.aoacc.alaska.gov Prepared by: Parviz Mehdizadeh, Ph.D. Production Technology Inc. Jane Williamson, P.E. Alaska Oil and Gas Conservation Commission \OGCC GUlde1l11es jor . QualIt"jcarion of Multi phase L Íug Systems 1] -30-04 Parviz l\ilehdizade .'-Oduction Technology Inc ~" ne WiJliamson, AOGCC 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 Application 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 Performance in Field............................ 10 4.1 Field Verification ............................................................10 4.2 Field Test Plan ............................................................... 11 4.3 Reporting the Field Results............................................ 13 -, !;:; AOGCC Guidelines fÒr . QuaJitìcation ofMuJtiphase nng Systems ¡ ] - 30-04 PanE i\.¡ehdizacl.roduelíon Technology lne ane Williamson, AOGCC Guidelines for Qualification of Multiphase Metering Systems for Well Testing 1.0 Purpose 1.0.1 The use of multi phase 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 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: ~"'I l) T j:: ~\(j(JCC' GuidelInes for QuaJjfïcation onv"!uJtiphase ì\eng Sysœms 11-30-04 Pacvî.Z :Vlebclizade1 ·oductionTechnok)gy· IDc e1e WiJ!iamson, AOGCC 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 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 Qualifyinq 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 qualification of the multiphase metering systems and outlines requirements for documentation of the field test results. 1.2 uPrinciples 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. ~!" of ¡ 5- /\OGCC GllIde!illÔS for . OuaJificat¡ol1 ofMuJÜDhase, rim>: Systems < '- ....... v ! 1-30-04 Par'VIZ i.\¡Iêhdizacle..·.Ocluction 'rechn.olO¿v Inc. ~o ne WiI!ìamson. .!\OGCC 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 MC 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 A/J/Jlication 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. 5 ~I-r L~ ¿,OGCC Guidelines for . QualitÏcation of ¡V!ultiphas, tering Systems ¡ ] -30-04 Parviz i'vlehdiZ::¡e· ,'oduetion Tec.hnologv Tne . . .. '-.I Jane Wi]]iamsÙI1. AOGCC 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 Qualifving Multiphase Metering Systems for Well Testing 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, modal, type and measurement 15 ).,.()(jCC' ClU IcleìÍl1e~..; Í"(,)l- . QuaJil"Ìcarion ofMuJtiphase èring Systems ì J -30-04 Parviz ldehdizact.. rodLlction.. Tec.'hnology ¡ne Jane \Villiamsoll. AOGCC 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 (WC), 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 - i.e. 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 -; ()j' ] 5 _,-\OGC'(' GUidelines for QuaJi1~cation of i'vIultiphase efmg Systems J Î -30-U4 Parviz i\lehdizaCk.· -"'oduction Technolo¡¿v II.lC -' ne Williamson, A.OGCC 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 Accuracy 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 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 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 = (ErrS + E2MP) 12 Where: TPE = total probable error in the measurement E TS = error due to the Test Separator measurement E MP = error due to the Multìphase Meter measurements As an example, if the test separator accuracy is 5% and the multiphase 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 AOGCC will consider applications on a case-by-case basis if thorough justification is provided with the application to the AOGCC. ,~ , - CL ]:\ AOGCC Cìuide!mes for Qualificarion of MulriphaSeering Systems i \-30-04 Parviz ['v Ie hd WI de.· '·oducrw!1 Technology Lne me \Vil1iamson. AOGCC 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 reduce 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 drìllsite 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. () ~'1,'::, AOGCC Guicklmcs for . Quahticat¡on ofr'vluJtíphas. lcring Systems ] 1-.30-04 PalVIZ Mehclizao.. roduCt..lOJ1 Tc.'-.'hn.olOgy ~.1~ Jane W1Jliamsoil. AOGlL 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: t'I5 ."-\C)GCC CÌuic1eJ IDe') for Qualification or MUltiPha,.ring II-JO-04 Paniz ¡VlehòiZ9d.· .'-'-OductiOl1._ Technology inc - . ~~. . ane WíJ!lamson. AOGCC 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 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 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 L 15 . . GUIDELINES For QUALIFICATION OF MUL TIPHASE 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 AOGCC Guidelines for . Qualificarion of Multiphase ¡Vletering Systems 1 í -30-04 Parviz i\!ehdizade 'ductiOll TeclmoloS!:v Inc ~- . ane WiJliamson. AOGCC Guidelines for Qualification of Multiphase Metering Systems for Well Testing Table of Contents 1.0 Pu rpose ....... I' II.. ............. ....1..1.................. 1..1.... I. I..................... 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 Process ............................................................... 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 ............................................................10 4.2 Field Test Plan ...............................................................11 4.3 Reporting the Field Results............................................ 13 , i ~ AOGCC Guidelines for . Qualification of Multiphase Ì\lletenng Systems i 1-30-04 PanlZ l\lehdizad, adL.l~t_lOn Teehno.logy Ine ~;1e Wllltamson. AOGCC Guidelines for Qualification of Multiphase Metering Systems for Well Testing 1.0 Purpose 1.0.1 The use of multi phase 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 multi phase 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 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: 3 \)f 15 ·\OGCC Guiclehnes for . Quaii tìcatiol1 of Multiphase 1\.1e[ering Systems I 1-30-04 Parviz Mehclizade' .'uction Technologv Ine . --.-' . .lane Williamson, AOGCC 1,0.7.1 As a guide for the operator in submitting a request to apply new multi phase 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 multi phase 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 Orøanization 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 Qualifyinq Multiphase Meterinq 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 uPrinciples of Multiphase Measurements" A separate document, "Principles of Multiphase Measurements", is concurrently issued with these guidelines. This document provides basic information on multi phase 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. ¡ ...., /I.OGCC Guidelines for . Qualification of r..1ultiphase Yletering Systems 11-30-04 Parviz Mel1diZadê-eductiün Technoiogy Inc lane Willi31nson. AOGCC 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 MC 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. 5 Gf 15 AOG<:C Guidelines for . n Quahhcauon ot Multlphase lVietenng :-'ystems ¡ ] -.30-04 Parviz [vlehdizade .[UeliOn Teel1l1oJogy Tne .lane W¡lhamsol1. AOGCC 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 QualifvinQ Multiphase MeterinQ Systems for Well TestinQ 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 Aøø/ication 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 h i' 1,~ AOGCC Guidelines for . Qualification of Multi phase !'vletering Systems i 1-30-04 Parviz lvlehdizad, .clllCtion Technology Inc Jane \Villiamson. AOGCC 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 (WC), 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 - i.e. 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 1:'::;: ¡ .~' ;OG~C Guide~ìne.; for . ~ VualÜ¡Catlon or :'v!ultlphase :'vcdcrmg :-;ystems ] ì -30-04 Paf\ìz ¡Vlehdìzacie'.c!uetìon Technology lne . anc WìJlìamson. AOGCC 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 Accuracy Exøectations 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 5% 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 = (ErrS + E2MP) Ÿ2 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% and the multiphase 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 AOGCC will consider applications on a case-by-case basis if thorough justification is provided with the application to the AOGCC. , " AOGCC GuidelInes for . Qua]jfication of Multiphase !VJetering Systems ] 1-30-04 Parviz rvlehdizade' _duct.ion Teehl1oJogy Ine ~le WIllIamson. AOGCC 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 multi phase 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 reduce 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 multi phase meter is less than that of the gravity based test separator. () 15 r\OGCC Guidelines for . QuaJification of Multiphase lv¡etering Systems 1 i - 30-04 Parviz Mehdizach e)ducÜOn Technologv Inc ~, Jane Williamson. AOGCC 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 multi phase 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 multi phase 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: lUoflS "O~"C' r "1' t' . h, LrL uUIQe mes or Qualitìcarion of Multiphase iV¡etering Systems 11-30-04 Parviz i\.1ehdizad" Aducrion Technology Inc ~1e WíJliam,;on. AOGCC 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 range, 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 i1 i5 AOG~C GLlide~íl1es for . co Qual¡hcatlOl1 or Multlphasè "detenng ::-'yslems 1]-30"04 Parviz l'v[ehdizade' .U\tlOl1 Technology Il1~ JaDe Vi ll]¡amson. AOGC,-- 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 multi phase meter. If repair, resetting, or recalibration is required during the field tests, the nature 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 multiphase 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 multi phase 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). L2 i '\ .",OGCC Guidelines for . Qualifïca¡jol1 of Multlphase ¡vletering Systems 11-30-04 Parviz MehdizadeJ .uction Technolog~~~ .I ant W ¡j hamson. A Ou\.-I... 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 4.3.3.2 4.3.3.3 4.3.3.4 4.3.3.5 4.3.3.6 4.3.3.7 4.3.3.8 Flowing pressure - measured at the meter in pounds per square inch absolute (psia). Flowing temperature - measured at the meter in degrees Fahrenheit (OF) Oil rate - Stock Tank Barrels of Oil per Day (STBO) corrected to standard conditions, at 14.65 psia and 60°F. Water rate - barrel per day (BPO). Gas rate - thousand standard cubic feet per day (MSCFO), at 14.65 psi a and 60°F. Gas-oil-ratio (GaR) - (SCF/STB) the gas volume flow rate, relative to the oil volume flow rate, both converted to volumes at standard pressure and temperature. Gas Volume Factor (GVF) - gas volume flow rate, relative to the multi phase volume flow rate (oil, gas, water), at the pressure and temperature prevailing at the meter. The GVF is normally expressed as a percentage 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. 1 _~ ,) t' 1 .5 ,!\OGCC Guidelines for . Qualitìcation of Multiphase l'v,,;;tering Systems 11-30-04 Parviz Mehdizade· AtU~[IOl1 Technology hl~ ~;~ vl;J!hamson, AOGCL 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: . . (max error) - (min error) repeatablllty = ~ number of tests 1 ~~ c't' l ~ . ~. (a.·,¡~ (_-..,~ "0 Par· 1Z é:l' IlL?' .due p.¡'¡, 'c ?õ.0·';C,,_ ;ailê Fig. 1 - An illustrative graphical method of reporting the accuracy performance of multiphase metering systems. These plots should be provided for each phase compared to G VF, water cut, and other important parameters. Liquid Flowrate Error VS. GVF Blue Lines, Range of relative flow rate error 50 s.. 40 0- ~ ~ 30 W a5 20 .... CD,! "iJ Q) 10 Eo:: ~ .9 0 o Q) -10 - > LL :æ -20 ~ Q) .- 0:: -30 ;j~ .2" ~-40 I ...J -50 .À . ~i .-4À ~ . ~~ ~ 20 30 40 50 ... [ 1 \. I' ~.:." ..¡. .À;¡..._.... ,f · r ~ Jì, 3 J.\A .1 .À ~A â.-k-- , !... i, t .1 Test Data I a-<i À À 1't ~-~ .j, A 60 90 ~ I !~ 100 Reference GVF (%) 70 80 , " , BPXi\ UTM6iNAD27 Drill Roads Unlj 6 " are Unit April any daims use of jhis dajR Table 2A.l - 1 LIST FIELDS, POOLS, AND WELLS AFFECTED BY THIS PROPOSAL - WORKING INTEREST, ROYALTY INTEREST, AND TAX TREATMENT FOR LEASES AOGC BP Processing Participating C Pool Exploratio Chevro Conoce Exxon Doyon Facility Area Code AOGCC Pool Description Royalty Rate % ELF n n Phillips Mobil Forest Oil LId Nana Unocal 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% to 20% Separate 67.9221 0.0234 21,0206 0.1291 0.3874 10.5174 100 Endicott Sag Delta North 220150 Sag Delta North 12.5% to 20% Separate 98.1327 04668 14005 100 Consolidated 26.35535 36,3954 LPC Niakuk 640148 Niakuk 12.5% Niakuk 6 1.16 36.06939 9 0.019768 100 Consolidated LPC Tract Operations 640147 GPMA Ivishak-Sag River 12,5% Niakuk . Consolidated 26.35535 36,3954 LPC West Niakuk 640149 Niakuk, Undefined 12.5% Niakuk 6 1.16 36.06939 9 0.019768 North Prudhoe 26.35535 36.3954 LPC Bay State 640152 North Prudhoe Bay State 12.5% Separate 6 1.16 36.06939 9 0.019768 100 26.35535 36.3954 LPC West Beach 640186 West Beach 12.5% Separate 6 1.16 36.06939 9 0.019768 100 LPC & Prudhoe 26.35535 36.3954 GC-1 Lisbume 640144 Lisburne 12.5% Separate 6 1.16 36.06939 9 0.019768 100 Milne Point MPU Kuparuk 525100 Milne Point Kuparuk 12.5% to 20% Separate 100 100 Milne Point MPU Sag River 525150 Milne Point Sag River 12.5% to 20% Separate 100 100 MPU Schrader Milne Point Bluff 525140 Milne Point Schrader Bluff 12.5% to 20% Separate 100 100 Milne Point Tract Operations 525160 Milne Point Ugnu, undefined 12.5% Separate 100 100 20% plus Northstar Northstar 590100 Northstar supplemental Separate 98,5772 14228 100 LPC & Prudhoe Consolidated 26.35535 36.3954 GC-1 Point Mcintyre 640180 Point Mcintyre 12.5% to 16.67% Prudhoe 6 1.16 36.06939 9 0.019768 . Prudhoe All GC Prudhoe IPAs Consolidated 26.35535 36,3954 &FS (ORlGG) 640150 Sadlerochit 12.5% Prudhoe 6 1.16 36.06939 9 0.019768 Consolidated 26.35535 36.3954 Prudhoe GC-1 Midnight Sun 640158 Midnight Sun, undefined 12.5% Prudhoe 6 1.16 36.06939 9 0,019768 100 Consolidated 26.35535 36.3954 Prudhoe GC-2 Aurora 640120 PBU Aurora, Undefined 12.5% Prudhoe 6 1.16 36.06939 9 0.019768 100 Consolidated 26.35535 36.3954 Prudhoe GC-2 Borealis 640130 PBU Borealis, Undefined 12.5% Prudhoe 6 1.16 36.06939 9 0.019768 100 Consolidated 26.35535 36.3954 Prudhoe GC-2 Orion 640135 PBU Orion, Undefined 12.5% Prudhoe 6 1.16 36.06939 9 0.019768 100 Schrader Bluff (Satellite), Consolidated 26.35535 36.3954 Prudhoe GC-2 Polaris 640160 undefined 12.5% Prudhoe 6 1.16 36,06939 9 0.019768 100 . . l'''' Tee n610gy Principle of Operation FlowSys TopFlow Multiphase Flow Meter May 2005 . . INDEX 1. GENE RAL... ..... ......... ....................... ........... ...... ............ ......... ........... ..... .... ...... ............................ ............. ............... 3 2. PRINCIPLE OF OPERATION AND FUNCTIONAL DESCRIPTION ............................................................ 3 2.1. PRINCIPLE OF OPERATION .................................................................................................................................. 3 2.2. F1..JNCT!ONAL DESCRIPTION .... .............................................. ......................................... .......... 5 2.2./. Capacitance sensor ........ ................ ..................... ... ........ ... ........ ........ ..................... ...... .... .... ................ ....5 2.2.2. Conductance sensor ... ........ .... ...... .......... ....... ...... .................................. .................... ... ..... ... ........ ......... ...5 2.2.3. Venturi meter................ ... ......................................................................................................................... 6 2.2.4. Cross-correlation ........................................................... .................... ............................... ............ ........... 6 T~t~-'I09Y . . FlowSys TopFlow Multiphase Meter 1. General This leaflet contains the principle of operation of the TopFlow multi phase flow meter. 2. 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. mixers or by-pass lines are required within the operating envelope of the TopFlow meter. However, the biggest advantage is the fact that the FlowSys concept does not make use of a radioactive source. Temperature Pressure Caþacitance I Conductance Watercut þ Oil Flow RClte .. Venturi (DP) .. Gas Fraction GVF Water Flow Rate .. Gas 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 *, T~~t;il~9Y . . FlowSys TopFlow Multiphase Meter The set of equations utilized in the calculations of the fractions are listed below: 1. Perm = I( Gas!J/o, {)i!~/o, W.Üsr°f¡) I Cond = f(Gas%, Dj~')¡o, "W3I!:Œ,;¡rG/o, Salinity ) 2. Density = j(DP, vel) = Gas% . DensGas + Oi10/0 . DensOil + Wai!::sro/o . DensWater 3. Gas1ik; + D¡¡% + ¥latsro/a = 1000/0 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 (Cone!) equation is valid for water-continuous mixtures. The permittivity (obtained from the capacitance measurement) or the conductivity (obtained from conductance measurement), DP and velocity (vel) 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 Dens Gas) are input parameters entered into the TopFlow computer. These parameters are normally set during commissioning. The Water-Liquid Ratio (WLR) is defined as: WLR = Water% Oil% + Water% The set of equations for the calculation of flow rates of oil, water and gas are listed below: 1. Oil F!O'J~ff Rata = Area. vel. DijO/<;» 2. WEri::s~' ;=§cw Rate = Area. vel. Waite,o/a 3. Gas rï!()'i'J Rate = Area. vel_ Gas!J/r) The cross sectional area of the pipe (Area) is known based on the geometry of the Venturi, the velocity (vel) 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 '~'I·'·"· "ie~' ~¿.;gy . . FlowSys TopFlow Multiphase Meter 2.2. Functional Description A functional description of the individual parts of the TopFlow meter is given in this section 2.2.1. 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 III Length ~ þ The capacitance is measured between two metal electrodes. The metal electrodes are incorporated in PEEK and flush with the inside pipe wall and are therefore not obstructing the flow in any way. The capacitance between the electrodes is a measure of the permittivity (dielectric property) of the fluids between the electrodes. - Capacitance C &0 . &mix . Area ap = Length 8"0 is the permittivity (dielectric constant) of vacuum 8"mix 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. Area III ~ Lenath þ The conductance is also measured between metal electrodes. These electrodes are also incorporated in 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"mix 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 \\\*1\)\) . Te~t';;¿1;9Y 2.2.3. . Venturi meter . FlowSys TopFlow Multiphase 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. Ir l.. ..uI DP ~ rr -~ Velocity 2.2.4. The density of the mixture inside the TopFlow meter can be derived from the Venturi equation. dP Pmix = K· VelocityZ K is a constant, DP is measured and the velocity is being measured using cross-correlation on signals from pairs of capacitance or conductance electrodes. Cross-correlation 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 - Downstream I 1. I d ~ '" I \-\ .r. ~/" '"-" ; "-' . Time Calculation of Velocity Velocity = d T T: Time shift between signals Page 6 of 6 The distance, d, between the set of sensors are fixed and known and when the time shift 1: is found by cross-correlating the signals, the Velocity can easily be calculated. The sensors, here illustrated as blue and red, will for the Top Flow meter be capacitance sensor in case of oil continuous flow and conductance sensors in case of water continuous flow. The oil- or water continuous state is a feature of the liquid only, irrespective of the content of gas in the fluid mixture. . APPENDIX 4A FLOWSYS PERFORMANCE GPB 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 Agar MPFM 401 FMC Flowsys Roxar (MPFM 1900VI) Schlumberger PhaseWatcher Vx 29 V olume flow Positive displacement and Venturi Device Cross correlation and Extended Venturi Venturi Device and cross correlation Venturi Device Gas fraction Venturi Device Venturi Device Gamma densitometer (137CS 662 keY) Gamma densitometer (133Ba 80 keY) Water cut Microwave (GHz) Electrical impedance (MHz) Electrical impedance (MHz) Gamma densitometer (I33Ba 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 ASRG 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 ± 1 %; a value of 2 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 performance of the Flowsys meter, using the 5% criteria, are shown in Table 4A.l. 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 stb/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 multiphase metering system, the Flowsys will be operating at GVF< 60%. The GPB 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 .1 - Summary scores for multiphase flow meter 5% criteria Parameter Measurement Capability Liquid flow rate Gas flow rate Water cut TOT AL score FMC All data 2.6 2.9 1.2 6.7 FMC GVF < 95% Liquid> 1100 stb/d 3.7 3.3 1.3 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 we for the Flowsys meter. These plots were used to assess the anticipated performance of the Flowsys meter within the EMS multiphase metering system. 50 'i' 40- u c f! 30- .! CII .. o 20- - CII > ~ 10- ãi .. ~ r- o .~ .. o .. :u -10- CII - ns ~ -20- o ¡;:: 'a -30- 'S r::r :J -40- -50 o . ,. Flowsys Holstein. NEL, 2005 vendor specification 'J> Flowsys. Prudhoe Bay, 2003 Flowsys, NEL, 2000 o Flowsys, Trecate, 2001 Flowsys, CMR. 2000 -"'~.. ..-..-- Xx x "'''''''''"''...==-'''==-=-.. I 10 I 20 I 30 . ~) " o <> x ,;' x .. x }o ), > ~ ¡ 0_ .~-+- y. ~ .; ~; . p : '1¡, x _ ' ëJ . -t .,/> ~ J x -,-;'" <- r-, =-H çQ'-(J] "7t?' 0 x "7:!.~ 0 v -,.,'~ ~ 0., 'Ö x~ 0 .1> ih .",..0.,""" . 0.",0 ~ 4: ji:/ f"c °ø x v"1\.:° > ~C, '9,,'".b fY';:¿ 0 CC¡j ð<u "J 0 ~ ,) .,' (] Mr." O.-::'<.i x· ce·" 0° ~¡jx ~ -' . ...,., _ "X U ,., 0 0 .. u~~>,", X') ~, 1.. L- .. - .. ..... .. ''tð- ..O~ -~ x· 0 XQ. ç.-J- '" _ {~ o O.ç¡ , ., o X } "'-..-.. x 0 OJ , ¡ o ., J x I I 40 50 60 Reference GVF ("!o) I 70 100 80 90 Figure 4A.l - Flowsys -liquid flowrate uncertainty vs. reference GVF (Test Loop and Field Tests) 50 40 - 'i' u c 30 - CII .. .! f! 20 - 0 - CII .~ 10 - 1ii ãi .. 0" ~ ~ .. 0 -10 - .. .. CII CII 1ii -20 - .. ~ 0 ¡;:: -30 - (/ ca C) -40 - -50 0 I .. Flowsys Holstein, NEL, 2005 vendor specification 'J> Flowsys, Prudhoe Bay, 2003 Flowsys, NEL. 2000 o Flowsys, Trecate. 2001 Flowsys. CMR, 2000 - ~ =-= -- """"""'''=". ,- 10 20 30 , l o 0 o o o ~ :..::.- .. - '" ~"ç"""""::~"- .. .....0 .. -0 0000.0 ~ }~ 1,0 :;~;;¡o_\Jo°oo~ ~~ c,~'~ . 0u 'J---¡-:->:-'r--- ~... ,"(' _",,'X)-"~___~:) 'ft '>:':;-õ ~ ,.00< ' ':) 2'-~')': ;.x '-' ~;~ ,~ x ~~ '" - ,?xCll¡-... - :~=-= '" ''?- ~; XCQ ~~c '{coo - 0 >Xý) x::; ::« ,. x ~, 1> 0 . ".... $ » >. o - ePC .. XX , x .' .:) €lc. )-í~% c. o x.... , 3 x .x..... 0 .. .. o <J ,< '" >X X '" , " x <0 " } >,. .> > 40 50 60 Reference GVF ("!o) 70 I 90 x .,) j x x ~ 80 tao Figure 4Ao2 - Flowsys - gas flowrate uncertainty vs. reference GVF (Test Loop and Field Tests) . . 25 20 .. Flowsys Holstein, NEL, 2005 - - vendor specification '. Flowsys, Prudhoe Bay, 2003 .. Flowsys, NEL, 2000 o Flowsys, Trecate. 2001 J Flowsys, CMR, 2000 -I I Q u ~ ¡ 15- ... .2! 41 ... E 10- o ... - .! =' Õ III .c ca ~ ... o ... Gi -10 - - =' u Gi -15- "1G ~ ,) Q 5- Q 0 OQ:¡ . ,_. .... :« x o.(~ i ¡ x ê x -, x ~_ _ j;g, x- -'tr-)< or; - .;4¿~_ r . - . "7 - - - - - - . - . T : ~- ~ . ~/~..c)_ ë -:~.- s- - eX;Ž¡' Oc:=;' "~ ,. OJ X X <h''__·. - iÞ'" ~ ....x. 'c' Q .- - 'iJôi~, v. -~ ,"'-- - ...'-' ~~x·co - ~#~~. - '~:¿,~:o -- ~~~~ V . '0 X ~ ~ },.- -"-~-"'-"'-"'-"_B_"'~"'T"'-I..i..x..-~~.._..Xí -,.. ~-t.. X * ~)~'X,,, ;{ " ",.' -.- .o_~_ ~ """" J,'¡'\ .. -5- ~oo 0: ,. ~o ogJ!J-~ ~ o ^ ~~ ¡ .. -i!> <... " .~ -20 - -25 I I 0 10 20 30 -~ [ I I 40 50 60 Reference GVF (%) 70 80 90 100 Figure 4A.3 - Flowsys - water cut uncertainty vs. reference GVF (Test Loop and Field Tests) REFERENCES [1] Klepsvik, 1., Dahl, E.O. and Baker, A.C., "Multiphase Flow Test Report - TopFlow Multiphase Flowmeter," Christian Michelsen Research Report, CMR-00-FI0021, September 2000. [2] Hall, A.R.W., "Evaluation of the FlowSys Top Flow Multiphase Flowmeter," NEL report 200/2000, October 2000. [3] Mazzoni, A., Halvorsen, M. and Aspelund, A., "Field qualification of the FlowSys Top Flow Meter", report from AGIP Trecate test facility and FlowSys, April 2001. [4] Hall, A.R. W., "Field evaluation of multiphase 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 Top Flow (FMC) multiphase flowmeter for Holstein," BP EPTG Report for DW GoM Production (Holstein 1 Mad Dog PU), S/EPT/096/05, November 2005. APPENDIX 4B ARAMCO TEST RESULTS Field Test Background 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 separator liquid flow rate. 10% (relative) compared to test . . . Water Cut: 90% of tests within +/-10% (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 following Figures 4B.l- 4B.3. The TopFlow meter performed well during the test, including the water cut measurement and was approved by Aramco to comply with the performance 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 Top Flow and the uncertainty in the reference manual sampling. ':;~a1~!~~.e~"~~~ Opti¡Jns ~- , FlowSys 100C10 ojIQ; ~ ~ '"" i ! I : .. 6OIlO Ie ... ....." I /'" , ~~. ' . ._-.r p':;::'" ....;::~.:--~' ,.. ·t,·/ ~¡" . . ..,;; '~ " t.fJ~ ....;~.;þ.. ..... 40IIØ 2IIIID i) ) 2000 4000 GOOO BDOØ 1DOØO Test Barge UqLl:ïdRaté (SBLPD) 121100 Figure 4B.l- Liquid flow rate accuracy 100 .. ..... ... D~f . -. ',-+ Ð 10 ,2:;!i.~!~Ì:!t~.:~~~ c::¡::t inn c; ~I _. ~. ~ sooo . C) 11 -I 0:: õ :!! .~ «000 :!! 2000 '-t}i'1!~f:!.~~~~~:-_ CI¡::tiDns 100 '" :iIO ~ - '$ Jill U iIO ... a¡o 1ã 50 :: :E .to !I.I. A. )0 :i 20 . FlowSys MPFM ~.. .. :. . ..... ". / .~ ,.~.~.. _<¥.- è: . ,..~!i/~~"'J.'~ /..~--~~-,.- -' ,. ,-'iii.. . .~. !a-"'fr-;~~'~' ..'~~ Q/ I) .zooo 4«10 moo - Test Barge Oil Rate (STBPO) Figure 4B.2 - Oil flow rate accuracy FlowSys .~ . .. . , " ; . . .. ~ ... .. . .. .1: lit' ..' .. 20 ~ ,j) 50 so Test Barge Water Cutl%) Figure 4B.3 - Water cut Accuracy . . . 1_ 10 1.zooo ~. .,~~' 811 fI(I HID · Andrew Hall has suggested the following formula for calculating combined uncertainty in mixed streams ET: {SORT [(OV/OT)'EV^2 + (QTF/OT)'ETF^2}} OT: Total volumetric rate OV : volumetric rate through the Vortex meter OTF : volumetric rate through the TopFlow EV : accuracy of Vortex meter ETF : accuracy of TopFlow for gas Note: The above formula calculates a mixed stream uncertainty that is independent of the total gas flow rate e CDS tested the Gasunie cyclone in the lab with very little liquid. At a GVF of 90% and higher (up to 99.99% at actual conditions), the cyclone separated at least 98% of all liquid droplets of 10 microns and bigger (at the ASRC conditions). The total carry over depends on the incoming droplet size distribution. So at these high GVF's the Gasunie cyclone should stay below the 0.5%v liquid in gas carry over. At lower GVF's we do not have quantitative test data. However the cyclone was tested in a skid similar to EMS ( with Shell and Daniel MPFM) about 5 years ago at NEL. At that time an ultrasonic meter was used to measure the gas rich leg. This meter stopped working if the liquid in gas exceeded 1 % by volume. The UT meter never 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% Vortex Meter Accuracy @ 1% 10% TF Meter Gas Accuracy 15% Average Vortex Meter Accuracy for 0.5 to 1% liquid 7.50% Diversion Rate 99% 98% 97% 96% 95% 94% 93% 92% 91% 90% 89% 88% 87% 86% 85% 84% 83% 82% see Fig. 6 see Fig. 6 see Fig. 6 EMS Accuracy % EMS Accuracy % Ave Vortex Accuracy 5% Vortex Accuracy 7.6% 7.7% 7.8% 7.9% 8.0% 8.1% 8.3% 8.4% 8.5% 8.6% 8.6% 8.7% 8.8% 8.9% 9.0% 9.1% 9.2% 9.3% 5.2% 5.4% 5.6% 5.7% 5.9% 6.1% 6.2% 6.4% 6.6% 6.7% 6.9% 7.0% 7.1% 7.3% 7.4% 7.5% 7.7% 7.8% separation technology An ''FMC TEchnologiEs Subsidiary . CDS-Gasunie cyclone scrubber The GU scrubber was originally developed by Gasunie Netherlands. Gasunie being faced with undesired condensate formation 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%. 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. . High liquid / gas ratio's can be handled · Maintenance friendly, no moving 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: +31267999100 Fax: +31267999119 H.R. Arnhem 090.90.976 Certificate No: 652134 separation technology An o¡:MC Technologies Subsidiary Principal of CDS-gasunie design PrCH:('SS ,:wdet Process ¡,~ J prQc.:H~'~ m ,. , inlet , - gas out liquids. sc!;~is out ... I~ Uq:.mhi $.oticts: = úutle-t . The CDS-Gasunie™ Cyclone Scrubber can be used for separation of liquids (water, hydrocarbon, glycol, etc.) from gases (natural gas and other), for the protection of downstream equipment (compressors, gas turbines, flow meters, etc.). Solid particles (dust, sand, etc.) will also be removed, making the scrubber suitable for use as a gas wellhead separator. Operating Principle The optimised blade geometry brings the combined phase into rotation. The resulting centrifugal force moves the liquid and solid particles towards the vessel wall, where they form a liquid film flowing downwards to the bottom of the vessel. The gas exits the vessel through the central pipe connected to the gas outlet nozzle. The baffles in the bottom of the vessel stop the rotation of the liquid, and the blocking plate prevents liquids from being entrained with the gas. In this way it is ensured, that no gas carry under or liquid carry over can occur. The optimised vane geometry is shown in the picture below. CDS Engineering BV, Delta 101, 6825 MN Arnhem, The Netherlands. Tel: +31 267999100 Fax: +31 267999119 HR. Arnhem 090.90.976 Certificate No: 652134 ~t~. separation technology , An "FMC Technologies Subsidiary . The Gasunie has made this graph long time ago. In the testing they used natural gas and glycol with a liquid percentage ofmax 2 %v. Operating pressure was 40 barg (580 psig) and operating temperature was 25°C (77 OF). Separator comparisons 100 90 ~ .. :>. 80 u C QI ï::; :e QI -5 70 .. rO U 60 o 0.2 04 10 0'6 Gas load Factor 0:8 d *~ P~as Gas Loa Factor = v gas 0_ P [;q¡¡id P gas gas density [kg/m3] liquid density [kg/m3] superficial gas velocity [mls] pgas Pliquid Vgas ¡II vane separator ') Gasunie cyclone ". gravity separator :~ multicydones '. meshpad ." coalescer separator 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 collected 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 %v of the injected liquid has been separated and 20 %v was carried over with the gas CDS Engineering BV, Delta 101, 6825 MN Arnhem, The Netherlands. Tel: +31267999100 Fax: +31267999119 H.R. Arnhem 090.90.976 Certificate No: 652134 . . EMS Control Philosophy CLIENT: ASRC PROJECT: BP Alaska Rev No. Details of Revision Pre :Jared By Date Checked By Date 5 4 3 2 2nd Issue for Review 1 151 Issue for Review OS DS 14-09-05 10-09-05 Business Park IJsseloord 2 Delta 101 6825 MN Arnhem The Netherlands Tel. (31) 267999100 Fax. (31) 26 7999119 separation technology An cj¡:8iìC Technologies Subsidiary Client Order No. Field/Platform End User BP Alaska ASRC Client Document No. CDS Project No. P04-11 006 CDS Document No. P04-11006-CPH Rev No. I No. Pages 2 16 R F>V n",tF> ?<;nFìn::¡ r.WF_7 H I~I separation techn~Ic.~...~\:,+t An 'iFMf: Technologies Subsidiary .DS Doc. No.: Revision: Date: P04-11006-CPH 2 14.09.05 Table of Contents 1. Introduction. ............ ..... ......... ... ...... ....... ...... ... ......... .................. ... ..............3 2. Control Ph ilosophy .................................................................................... 3 2.1 High Liquid I Low Gas ........................................................................................... 3 2.2 Low Liquid I High Gas ...........................................................................................4 20fñ I···· ~..~.,>.. I ,- -.-q-,"'-.-, separation techn~I~~'''.~ An ";:i\f«~ Technologies Subsidiary .S Doc. No.: . Revision: Date: P04-11006-CPH 2 14.09.05 1. Introduction 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. 2. Control Philosophy 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 10^4 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 multi phase 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. · 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 I Low Gas . 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 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. :i ofó separation techno~~.;. An 'FM~ Technologies Subsidiary ..8 Doc. No.: . Revision: Date: P04-11006-CPH 2 14.09.05 2.2 Low Liquid 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 Topflow 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, initially by opening the gas control valve followed by the liquid control valve. 4- of ñ separation technO~(øl.+.. An ""Fí'\¡lC Technologies Subsidiary Outputs :................................................................................. . . C';~~L;;~ ":¿,6"0' 1 L:'9h3~~::~e:::"~_lj Gas Control Valve (Analogue) ~ y .. A liquid Control Valve (Analogue) Outputs r--;~;;;:~~~,:~) I High level Set Point to 3cd Party P&ID H- . . .................................................................................; Figure 1: Control Schematic CDS Doc. No.: . Revision: Date: P04-11006-CPH 2 14.09.05 I Standard inputs I · i--I---~;;;--p · II T ~~!a:~~re I Meter 1... ~.!.' I Pressure drop I ; (Analogue) ¡ . II C'~g;;:oœ I ¡ · i I Ca~;~:~o'e I 1 :,.................................................................... I I I I I I , I I I I 3'd Party PID Controller Meter 2 · A · A .. A .. A ... I· Â Additional inputs I Standard inputs I · il--;;;;---l ~ T~~!a::u~re ! : ~ i I L~ ~ ~ .. :.....................n............................................~ II Gas Flow I : : : ¡ · II ~~~i¿;~~~ ¡ i I I level Transmitter I Pressure drop (Analogue) .. Liquid Valve Positioner . Conductance (Digital) . . .....................................................................: Capacitance (Digital) . . ...................................................................., · C · .. y y y y (í of (í m LillJ INLET 5K ... " A1 ~ . V -1 00 I.D. TIT DESIGN PRESSURE DESIGN TEMP. 364 mm 2860 mm 1335 psig -50/+250' F NOTE 3 -------- m 600# RF lJU ~CO~CD~ I I y ~I 3"FC SDV I I I I L -r -' w z « a- u :::; ::> ~ o >- I ::2: a a:: IL SD 1 S[10U02psiq - 3" 3" H2 CHOKE NOTE 6 FB I lC()Jr '"" W I- a :z II 3" 7fJ1 CD? I u... "z:::l - 2500# ¡ 600# T æ g NOTE 2 II I NOTE 6 . --- e . SAFE AREA O-m- MUL TIPHASE METER CONTROL COMPUTER m 600# RF LmJ ------------------- ------- 3" 2500# NOTE 1 3" (iiT) ~ NOTE 6 :t.-, L . 3" 600# ß'J rpsv - SfTOtJJ5p5iq 2"900# f\ 4" 6"x3" IIC}-~ ~ -11 QJ NOÆ50~~ \ @ L______________________.J TRANSMITTERS SCOPE CDS MOUNTED ON SCOPE ASRC SPOOL ~~ ~ 4"= ¡ ~ ¡ 2" L_______________________.J -1C()Jf- . 2" --------- ~T'" ---- V -1 00 ~ m lK1LJ -11 [r] m LillJ - NOTE 6 4" (PiT) ~ NOTE 6 I I I FB IC()JI ¿ -- 3" æQ cpcp ~ -;-. \""0"00"'"'' ~: t 001 I ~g~~ltLS~PPLY BLIND FLANGE. 4" I I 4" ~SKID SUPPLIED WITH DUMMY VALVE. ADDED VALVE E2 -j f- SCOPE ASRC - CD I 00 Q ¡:: u... a 6"x3" z ., Dill 3" ,,,. 2 C)-----A ¡ ~~ C)--..--(f-QFo ~ - ,------- ~ '"" N?i' ;--T,~ § I 001 I - 20xD - VORTEX ~--- -- ------- ----- -- --." L: : 2" !@ i ------+ ~~J ¡ œ:. . ~ :@ : ~ ------+ 60~ ¡ <C. . :I:' . a..' . ~ -------1- TE IT ¡ (D :::;;¡ :002002: Z : ~--...-- T L_m__m__m______! - I" æQ '"" W I- a z FB IC()JI -5xD- 4" I FB --JC()JI FB 1C()Jf- NOTE 6 NOTE 6 I I TURBINE METER (FUTURE) SCOPE ASRC I FB FB IC()JN~PI 600# 12500# [1]" ! N2 I I OUTLET 5K NI-' I '"" W I- a :z II '"" W I- a :z '"" UJ I- a 3"x4" z FB r--! k:J-YC()J1 .-L ..---------------------.. 1Õo,: : l' I ._____..L@PT¡ i 001 : œ:. . ~ i® ¡ ~ -------1- ~~ ¡ <C. , :I:' . a..' . ~ _______1. TE IT ¡ (D :::;;¡ i 001 001: Z : ~--...-- . '- T ~m__.___.___________; - NOTE 6 NOTE 1: SKID BYPASS LINE. NOTE 2: BYPASS LINE AROUND CHOKE. NOTE 3: DESIGN PRESSURE STATED IS EQUIVALENTTO A FULL ANSI 600# RATING AT 250'F. DESIGN OF THE SKID IS TO BE SUCH THAT THE FULL ANSI 600# RATING, APPLIES AT ALL TEMPERATURES IN THE DESIGN TEMP, RANGE. NOTE 4: DELETED NOTE 5: GUIDED WAVE RADAR TYPE INSTRUMENT WITH INTERNAL MAGNETIC LEVEL GAUGE. NOTE 6: J2" THREADOLET WITH THREADED PLUG 2" FB I IC()J~ I I NOTE 6 2" ~w; 1~~:~5 :~me rDS~ Checked - separation tech~¡y Ö^. Process 190405 OS An fIIIC Technologies Subsidiary V Size Project BP WELL TESTING ~~;nlR~~c.NO. ;04-11006 lint-re....- A 1 Client FMC Clients Ref. _ ~ Title P&ID Drawing no. I Rev. MULTI PHASE METERING SKID f' All nr~ '1 n /, q r----- , , . . : 2" : - NOTE 6 Lh--Tmm-----J 4"x3" FB NofE 6 ~C()Jf- -----------., , 3" 13 DESIGN TEMPERATURE/PRESSURE UPDATED 130706 MG DS 12 DESIGN TEMPERATURE/PRESSURE UPDATED 270606 MG DS II COMMENTS ASRC ADDED. CV·S MOVED 030306 MG DS Revision Description 01 Revision Date Drown Checked --------- --- ------------ . . APPENDIX - 9 GUIDELINES PERFORMANCE OF FACTORY ACCEPTANCE TEST 1. If at all possible 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 what was actually done. It is suggested that the final set-up be done in the presence of the customer. 3. If the Multiphase Measurement System utilizes one or more HMI'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 multiphase 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 technique but one can also use a separator or a second verified meter. 6. If the desired F AT matrix exceeds the vendors system capabilities, the F AT would have to be performed at and by a third party test loop. If the F AT is performed at a third party test facility, the purchaser may wish to have either personally witness or have a third party witness the tests. 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 determine 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 performance tested to determine 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 F AT matrix. Items to be made available to users at the end of F AT 1. The vendor should supply a formal 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 measurement results with illustrations in the form of error graphs and exception explanations. Signed calibration sheets for all instruments. 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 · e APPEND IX - 10 GUIDELINES PERIODIC FIELD TESTING - CALIBRATION Periodic field-testing may be required as a scheduled maintenance wherein the end devices or metering systems have to be verified. This verification may range from 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 well production rate is higher than a couple of hundred barrels per day, the only options for 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: 4. 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. If the system utilizes single-phase meters, perform 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 of leakage. 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. 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 kinetic 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). The pressure of the well, selected as the "proof well", 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 performance, 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. 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). 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. 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 repeãted 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 0 f tests should be run to verifY the meter factors. 1. 2. , .J. 5. 6. 7. 8. 1-1 . c: '.. .................... . ,', FlowSys TopFlow Multiphase Meter Site Verification Test Procedure Document type Doc.no : PRD-OOOOO24544 Procedure Page 1 of 10 Status Change no. Date Version Revision Released Version 500000028763 10.03.2004 00 This document is the property ofFMC Measurement Solution and is not to be reproduced or disclosed to any party without the written consent of FMC Measurement Solution. ELECTRONIC ORIGINAL User is responsible for verification of released revision status on document copy .. -':J-d\:ifllii\;~ . . '~eViSiOn . Doc.no.: t"KU-UUUUU~4t)44 . I Version : 00 Page no.: 2 of 10 Table of Contents PR E F ACE ..... ...... .......................... ............................... ........ ............ ........... .... ............ .... ..... ...... 3 2 SITE VERIFICATION TEST ..................................................................................................4 2.1 ELECTRICAL PARTS................. ..... ... .... ....................... ........... .......... ............ ................. ......4 2.1.1 Current loops ....... .... .... ........ ... ....... ........ ......... ........ ...... ...... ................... ............ ........ ...4 2.1.2 Transmitters ............... ..... ............ ... ........... ...... ........ ............ ....................................... ...5 2.2 MECHANICAL PARTS...... ... ......... ...... ... ...... .... .......... ................. ........ ............. ...... ............ ...6 2.3 CAPACITANCE AND CONDUCTANCE SENSOR.......................................................................7 2.3.1 Capacitance sensor.......... ......... ........ ..... ..... .... ........ ........ .... ........ ........... ........ .... ........ ... 7 2.3.2 Conductance sensor......... ......... ......, ....,. ..... .... ............................................... .... .... .......8 2.4 TopFLOW PERFOR."vIANCE ....... .................... ................. ................... .... ........................ .....10 3 CO RRECTIVE A CTIONS................................................. .................................................... to 4 SITE VERIFICATION REPORT .........................................................................................10 it-; . FlowSys TopFlow Multiphase Meter Site Verification Test Procedure I Version: " '~~ViSion : Doc.no.: t"f'(U-UUUUU~4:)44 . ,J' jG¡'[j\.:¡¡¡ 00 Page no.: 3 of 10 1 PREFACE The FlowSys TopFlow Multiphase Meter is manufactured by FMC Measurement Solutions based on technology and electronic components from FlowSys ASA. Telephone No.: (1) 361 289 3484 Customer Support: Contact Address: FMC Measurement Solutions FMC Technologies Inc. 737 N Padre Island Drive Corpus Christie Texas 78406 USA Telefax No.: (1) 361 289 1115 E-Mail: dan. househo lden@fmcti.com Internet: www.fmcmeasurementsolutions.com Copyright All technical information 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 written permission of FMC Measurement Solutions. © 2004 FMC Measurement Solutions Trademarks Products listed are trademarks of their respective manufacturers. Company names listed are trade names of their respective companies. This revision IS based on FlowSys Topflow Site Verification Test Procedure, Rev. Oa 12.11.2002 1r:·· . FlowSys TopFlow Multiphase Meter Site Verification Test Procedure -'.1- :J'..:;m":~ . '~:ViSiOn . Ooc.no.: rn.u-uuuuu",~o~~ . Page no.: 4 of 10 I Version: 00 2 SITE VERIFICATION TEST The objective of the Site Verification is to verify the factory calibration of the TopFlow Multiphase Meter as well as verifying the mechanical parts of the TopFlow 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: · Verification of mechanical parts · Verification of electrical parts · Verification of capacitance and conductance sensors · Verification of TopFlow 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 below. A seperate Field Verification Test procedure is covering tests that can be performed while 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: · DP Transmitters · Temperature transmitter · 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 0,5% of the applied currents. .1f.:' . FlowSy's Topf1ow MulÜphase Meter S;:'te Verificatiol1 Test fTocedure [,J""' :J\4I:J\';'iJm 'ReViSion. Doc.no.: r-~u-uuuuu¿;&+~&+&+ . Page no.: 5 of 10 I Version : 00 2.1.2 Transmitters The transmitters have been precalibrated. The calibration of the transmitters are verified by using pressure and temperature calibration kit. The following pressures and temperatures are applied to verify the calibration. Transmitter Pressure Transmitter DP transmitter Temperature transmitter 1 1 Bara o mBar Minimum 2 50% ofmax 1250 mBar 50% ofmax 3 Max 2500 mBar Maximum 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 Operating Manual for the TopFlow meter. If the measured pressure or temperature for a transmitter are not within 2% of the set pressure or temperature, the transmitter shall be recalibrated. It is also recommended that the pressure and temperature transmitters included in the TopFlow meter are included in the same maintenance programme that is used by the customer for other similar transmitters in the field. ì'f- iJ ..> FlowSys TopFlow Multiphase Meter Site Veri fication Test Procedure -.r JI':>I!J'.:.Ð ~~~eViSion . Doc.no.: fJ KU-UUUUUÃl4t)44 . I Version: 00 Page no.: 6 of 10 2.2 MECHANICAL PARTS The objective of this check is to verified that the dimensions of the TopFlow meter have not been changed due to erosion or that a layers of any kinds are not being build up inside the TopFlow meter. The TopFlow 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 TopFlow meter an estimate (within ±0,5mm) of the thickness of the layer shall be made and reported. Dimensions that are being used by the Top Flow meter in the calculation of flow rates are being measured. The physical dimensions of the TopFlow meter that are being measured are: · Venturi throat inner diameter (E-F). · Upstream pipe inner diameter (G-H). II 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 TopFlow 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 below: I C --------------------- -------- D \ / E -~-----------------------------·F G - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - ·H I I 1f. , FlowSys TopFlow Multiphase Meter Site Verification Test Procedure ~~ ;.J~!j':.'ZJ '~eViSion . Doc.no.: ....I'(U-UUUUU~4~44 . Page no.: 7 of 10 I Version: 00 2.3 CAP ACIT ANCE AND 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. 2.3.1 Capacitance sensor The multiphase flow meter is placed vertically and a blind flange including a tapping point mounted at the bottom of the meter. --..., Multiphase meter ,.--' Blind flange z: ,. 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 lowest permittivity and the liquid of highest permittivity is the last fluid added to the meter. Fluids used: Fluid Empty pipe Diesel Theoretical Permittivity 1,0 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. 3. Close the buttom valve and fill the meter with Diesel. 4. Wait 5 minutes for small bubbles to float to the top. 5. Record the measured permittivity from the user interface. l'L . FlowSys TopFlow Multiphase Meter Site Verification Test Procedure ~~ .j\j;f¡¡J' z:¡ I Version: 00 '~eViSion . Doc.no.: ~t(U-UUUUU:¿4::»44 . 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 view the measured permittivity. The User Interface Software is described in detail in the Software Operating Manual of the TopFlow Multiphase Meter. The acceptable limits for the measurements obtained during the static check is shown below. Empty ! pIpe I Diesel Table Minimum 0,98 Maximum 1,02 2,1 2,35 Acceptable limits for static checks. 2.3.2 Conductance sensor The multi phase flow meter is placed vertically and a blind flange including a tapping point is mounted at the bottom of the meter. -...., Multiphase meter J <III Blind flange z:: <III Tapping point The meter is first filled with 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: Mixture # Mixture 1 Mixture 2 Mixture 3 Table 1 Salt content 6g/1 50 g/l 100 g/l Mixtures 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-interface. FlowSys TopFlow Multiphase Meter Site Vó:rification Test Procedure -,rLi\c/[J'.¡¡ . t~viSion . uoc.no.: r r'\.uauuuuu,....\J........ I Version: 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 with Mixture 1. 3. Wait 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. It is verified that the measured salt content is measured within ±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 view the measured salinity. The User Interface Software is described in detail in the Software Operating Manual of the TopFlow Multiphase Meter. 1f I. FlowSys TopFlow Multiphase Meter Site Verification Test Procedure I.;¡¡, ,;;0\;04'-"""..-'.<4 - '~-i., LlU~.UU.. II' '''''''-VVV V V."""TV'-r...... . Page no.: 10 of 10 ~ 00' ';" ~ReViSion: I Version: 2.4 TOPFLOW PERFORMANCE 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 within acceptable limits shall be and corrective actions will be proposed. 4 SITE VERIFICATION REPORT A Site Verification report shall be made. 1í~ . FlowSys TopFlow Multiphase Meter Site Verification Test Procedure :#;1 ee ee Notice of Public Hearing OR\GlNAL STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Badami Pool, North Slope Alaska. BP Exploration (Alaska), Inc. by letter dated July 6, 1998 has requested an exception to the provisions of 20 AAC 25.240 to waive the gas-oil ratio limitation for wells producing in the Badami Pool, North Slope, Alaska. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM August 7, 1998, with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest is timely filed and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 AM on August 25, 1998 in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433 after August 7, 1998. If no protest is filed, the Commission will consider the issuance of the order without a 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, please contact Diana Fleck at 279-1433 no later than August 18, 1998. Published July 23, 1998 ADN A002914003 38714 STOF0330 AO-02914003 $59.67 .. .. AFFIDAVIT OF PUBLICATION July 23, 1998 STATE OF ALASKA, THIRD JUDICIAL DISTRICf. . ..EvA..: ....Kaufmann............. being first duly sworn on oath deposes and says that he/she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska.. and it is now and during 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 form) of said newspaper on 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 individuals. ~~~. Subscribed and sworn to ~re me this ....... day of .................... \ttl(l{{(rff,r 19...... \\\"-'."t ~~~.~lcl..rr"r": ~ ~,"".' ..- '. ~-;.. ~4.~..' 01ARj;·~~ .......................................\::....;.. --- .- Notary Public in and for g PUBL\C, = ê the State of Alaska. _ '. dI --- c!.: :::; Third Division. :::.. ~h.. . bI' ~ Anchorage. Alaska ~ . . : c: Of ,,~ . . y MY COMMISSION EXPIRES....../ . . . .' :\' /.1.1 * ,\\ /}))}JJJ})\' . . . . .. .. . . . . . . . .. .. .. .. .. . . . . . .. . . . .. . ... 1 9. . . . .. : DRI / MCGRAW HILL RANDALL NOTTINGHAM 24 HARTWELL LEXINGTON MA 02173 OVERSEAS SHIPHOLDING GRP ECON DEPT 1114 AV OF THE AMERICAS NEW YORK NY 10036 ALASKA OFC OF THE GOVERNOR JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON DC 20001 OIL DAILY CAMP WALSH 1401 NEW YORK AV NW STE 500 WASHINGTON DC 20005 US MIN MGMT SERV CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON VA 20170-4817 .. -. PlRA ENERGY GROUP LIBRARY 3 PARK AVENUE (34TH & PARK) NEW YORK NY 10016 NY PUBLIC LIBRARY DIV E GRAND CENTRAL STATION POBOX 2221 NEW YORK NY 10163-2221 AMERICAN PETR INST STAT SECT JEFF OBERMILLER 1220 L ST NW WASHINGTON DC 20005 ARENT FOX KINTNER PLOTKIN KAHN LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON DC 20036-5339 LIBRARY OF CONGRESS STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON DC 20540 U S DEPT OF ENERGY PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON DC 20585 US GEOL SURV LIBRARY NATIONAL CTR MS 950 RESTON VA 22092 AMOCO CORP 2002A LIBRARY/INFO CTR POBOX 87703 CHICAGO IL 60680-0703 LINDA HALL LIBRARY SERIALS DEPT 5109 CHERRY ST KANSAS CITY MO 64110-2498 MURPHY E&P CO ROBERT F SAWYER POBOX 61780 NEW ORLEANS LA 70161 .. -. TECHSYS CORP BRANDY KERNS PO BOX 8485 GATHERSBURG MD 20898 SD DEPT OF ENV & NATRL RESOURCES OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY SD 57702 ILLINOIS STATE GEOL SURV LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN IL 61820 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA KS 67202-1811 UNIV OF ARKANSAS SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE AR 72701 CROSS TIMBERS OPERATIONS SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY OK 73102-5605 IOGCC POBOX 53127 OKLAHOMA CITY OK 73152-3127 CH2M HILL J DANIEL ARTHUR PE PROJ MGR 502 S MAIN 4TH FLR TULSA OK 74103-4425 BAPI RAJU 335 PINYON LN COPPELL TX 75019 -. US DEPT OF ENERGY ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS TX 75201-6801 -. DWIGHTS ENERGYDATA INC JERLENE A BRIGHT DIRECTOR PO BOX 26304 OKLAHOMA CITY OK 73126 OIL & GAS JOURNAL LAURA BELL POBOX 1260 TULSA OK 74101 R E MCMILLEN CONSULT GEOL 205 E 29TH ST TULSA OK 74114-3902 MARK S MALINOWSKY 15973 VALLEY VW FORNEY TX 75126-5852 PURVIN & GERTZ LIBRARY 1201 MAIN ST STE 2600 DALLAS TX 75202 DEGOLYER & MACNAUGHTON MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS TX 75206-4083 GAFFNEY, CLINE & ASSOC., INC. ENERGY ADVISORS MARGARET ALLEN 16775 ADDISON RD, STE 400 DALLAS TX 75248 MOBIL OIL JAMES YOREK POBOX 650232 DALLAS TX 75265-0232 STANDARD AMERICAN OIL CO AL GRIFFITH POBOX 370 GRANBURY TX 76048 SHELL OIL CO J F CORDARO POBOX 2463 HOUSTON TX 77001 -. -. MOBIL OIL CORP MORRIS CRIM POBOX 290 DALLAS TX 75221 GCA ENERGY ADV RICHARD N FLETCHER 16775 ADDISON RD STE 400 DALLAS TX 75248 JERRY SCHMIDT 4010 SILVERWOOD DR TYLER TX 75701-9339 PRITCHARD & ABBOTT BOYCE B BOLTON PE RPA 4521 S. HULEN STE 100 FT WORTH TX 76109-4948 SHELL WESTERN E&P INC K M ETZEL POBOX 576 HOUSTON TX 77001-0574 ENERGY GRAPHICS MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON TX 77002 PURVIN & GERTZ INC LIBRARY 2150 TEXAS 600 TRAVIS HOUSTON TX COMMERCE TWR ST 77002-2979 CHEVRON PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON TX 77010 OIL & GAS JOURNAL BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON TX 77027 MOBIL OIL N H SMITH 12450 GREENSPOINT DR HOUSTON TX 77060-1991 -. -. H J GRUY ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON TX 77002 RAY TYSON 1617 FANNIN ST APT 2015 HOUSTON TX 77002-7639 BONNER & MOORE LIBRARY H20 2727 ALLEN PKWY STE 1200 HOUSTON TX 77019 PETRAL CONSULTING CO DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON TX 77042 MARK ALEXANDER 7502 ALCOMITA HOUSTON TX 77083 -. MARATHON OIL CO GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON TX 77210 EXXON EXPLOR CO LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON TX 77210-4778 CHEVRON USA PROD CO ALASKA DIVISION ATTN: CORRY WOOLINGTON POBOX 1635 HOUSTON TX 77251 PHILLIPS PETR CO ALASKA LAND MGR POBOX 1967 HOUSTON TX 77251-1967 WORLD OIL MARK TEEL ENGR ED POBOX 2608 HOUSTON TX 77252 UNOCAL REVENUE ACCOUNTING POBOX 4531 HOUSTON TX 77210-4531 EXXON EXPLORATION CO. T E ALFORD POBOX 4778 HOUSTON TX 77210-4778 PETR INFO DAVID PHILLIPS POBOX 1702 HOUSTON TX 77251-1702 UNION TEXAS PETR ALASKA W ALLEN HUCKABAY POBOX 2120 HOUSTON TX 77252 -. UNION TEXAS PETR ALASKA CORP MANAGER-WORLDWIDE BUSINESS DEVELOP. STEVEN R FLY POBOX 2120 HOUSTON TX 77252-2120 UNION TEXAS PETROLEUM TECHNICAL SERVICES JIM E. STEPINSKI, MANAGER POBOX 2120 HOUSTON TX 77252-2120 EXXON CO USA G T THERIOT RM 3052 POBOX 2180 HOUSTON TX 77252-2180 PENNZOIL E&P WILL D MCCROCKLIN POBOX 2967 HOUSTON TX 77252-2967 MARATHON MS. NORMA L. CALVERT POBOX 3128, STE 3915 HOUSTON TX 77253-3128 PHILLIPS PETR CO JOE VOELKER 6330 W LP S RM 492 BELLAIRE TX 77401 -. -. EXXON CO USA RESERVES COORD RM 1967 POBOX 2180 HOUSTON TX 77252-2180 EXXON CO USA GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON TX 77252-2180 CHEVRON CHEM CO LIBRARY & INFO CTR POBOX 2100 HOUSTON TX 77252-9987 PHILLIPS PETR CO ERICH R. RAMP 6330 W LOOP SOUTH BELLAIRE TX 77401 PHILLIPS PETR CO PARTNERSHIP OPRNS JERRY MERONEK 6330 W LOOP S RM 1132 BELLAIRE TX 77401 TEXACO INC R EWING CLEMONS POBOX 430 BELLAIRE TX 77402-0430 INTL OIL SCOUTS MASON MAP SERV INC POBOX 338 AUSTIN TX 78767 DIANE SUCHOMEL 10507D W MAPLE WOOD DR LITTLETON CO 80127 AMOCO PROD CO C A WOOD RM 2194 POBOX 800 DENVER CO 80201-0800 C & R INDUSTRIES, INC. KURT SALTSGAVER 1801 BROADWAY STE 1205 DENVER CO 80202 .. -. TESORO PETR CORP LOIS DOWNS 8700 TESORO DR SAN ANTONIO TX 78217 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON CO 80122 GEORGE G VAUGHT JR POBOX 13557 DENVER CO 80201 AMOCO PROD CO LIBRARY RM 1770 JILL MALLY 1670 BROADWAY DENVER CO 80202 JERRY HODGDEN GEOL 408 18TH ST GOLDEN CO 80401 -. NRG ASSOC RICHARD NEHRING POBOX 1655 COLORADO SPRINGS CO 80901-1655 EG&G IDAHO INC CHARLES P THOMAS POBOX 1625 IDAHO FALLS ID 83415-2213 RUI ANALYTICAL JERRY BERGOSH POBOX 58861 SALT LAKE CITY UT 84158-0861 MUNGER OIL INFOR SERV INC POBOX 45738 LOS ANGELES CA 90045-0738 US OIL & REFINERY CO TOM TREICHEL 2121 ROSECRANS AVE #2360 ES SEGUNCO CA 90245-4709 -. RUBICON PETROLEUM, LLC BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS CO 80906 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE ID 83702 TAHOMA RESOURCES GARY PLAYER 1671 WEST 546 S CEDER CITY UT 84720 LA PUBLIC LIBRARY SERIALS DIV 630 W 5TH ST LOS ANGELES CA 90071 BABSON & SHEPPARD JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH CA 90808-0279 ANTONIO MADRID POBOX 94625 PASADENA CA 91109 PACIFIC WEST OIL DATA ROBERT E COLEBERD 15314 DEVONSHIRE ST STE D MISSION HILLS CA 91345-2746 SANTA FE ENERGY RESOURCES INC EXPLOR DEPT 5201 TRUXTUN AV STE 100 BAKERSFIELD CA 93309 TEXACO INC PORTFOLIO TEAM MANAGER R W HILL POBOX 5197X BAKERSFIELD CA 93388 SHIELDS LIBRARY GOVT DOCS DEPT UNIV OF CALIF DAVIS CA 95616 e. -. ORO NEGRO, INC. 9510 OWENS MOUTH , #7 CHATSWORTH CA 91311 76 PRODUCTS COMPANY CHARLES BURRUSS RM 11-767 555 ANTON COSTA MESA CA 92626 WATTY STRICKLAND 1801 BLOSSOM CREST ST BAKERSFIELD CA 93312-9286 US GEOL SURV KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK CA 94025 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE CA 95969-5969 ECONOMIC INSIGHT INC SAM VAN VACTOR POBOX 683 PORTLAND OR 97207 MARPLES BUSINESS NEWSLETTER MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE WA 98119-3960 DUSTY RHODES 229 WHITNEY RD ANCHORAGE AX 99501 DEPT OF REVENUE BEVERLY MARQUART 550 W 7TH AV STE 570 ANCHORAGE AK 99501 FAIRWEATHER E&P SERV INC JESSE MOHRBACHER 715 L ST #4 ANCHORAGE AX 99501 -. -. US EPA REGION 10 LAURIE MANN OW-130 1200 SIXTH AVE SEATTLE WA 98101 PATTI SAUNDERS 1233 W 11TH AV ANCHORAGE AK 99501 DEPT OF ENVIRON CONSERV PIPELINE CORRIDOR REG OFC PAMELA GREFSRUD 411 W 4TH AVE ANCHORAGE AK 99501 DEPT OF REVENUE OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE AK 99501 GUESS & RUDD GEORGE LYLE 510 L ST, STE 700 ANCHORAGE AK 99501 STATE PIPELINE OFFICE LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE AK 99501 TRADING BAY ENERGY CORP PAUL CRAIG 2900 BONIFACE PARKWAY #610 ANCHORAGE AK 99501 PRESTON GATES ELLIS LLP LIBRARY 420 L ST STE 400 ANCHORAGE AK 99501-1937 DEPT OF REVENUE OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE AK 99501-3540 HDR ALASKA INC MARK DALTON 2525 C ST STE 305 ANCHORAGE AK 99503 . . TRUSTEES FOR ALASKA 725 CHRISTENSEN DR STE 4 ANCHORAGE AK 99501 YUKON PACIFIC CORP JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE AK 99501-1930 ALASKA DEPT OF LAW ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE AK 99501-1994 BAKER OIL TOOLS ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE AK 99503 KOREAN CONSULATE OCK JOO KIM CONSUL 101 BENSON STE 304 ANCHORAGE AK 99503 N-I TUBULARS INC 3301 C STREET STE 209 ANCHORAGE AK 99503 HWW CONSULTANTS HARRY WASSINK 1340 W 23RD AV STE A ANCHORAGE AK 99503-1644 LONNIE SMITH 200 W. 34TH AVE, #982 ANCHORAGE AK 99503-3969 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS BRUCE WEBB 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS MARK MYERS 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 . . WEBB'S BUSINESS CONSULTING SERVICES BILL WEBB 1113 W. FIREWEED STE 200 ANCHORAGE AK 99503 ALASKA OIL & GAS ASSOC JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE AK 99503-2035 AK JOURNAL OF COMMERCE OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B STREET STE #210 ANCHORAGE AK 99503-5911 DEPT OF NATURAL RESOURCES DIV OIL & GAS WILLIAM VAN DYKE 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS TIM RYHERD 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES PUBLIC INFORMATION CTR 3601 C STREET STE 200 ANCHORAGE AK 99503-5948 ARLEN EHM GEOL CONSLTNT 2420 FOXHALL DR ANCHORAGE AK 99504-3342 STU HIRSH 9630 BASHER DR. ANCHORAGE AK 99507 US BLM AK DIST OFC RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE AK 99507-2899 . . DNR - DIV OIL & GAS LINDA WESTWICK ROYALTY ACCT SECT 3601 C ST STE 1390 ANCHORAGE AK 99503-5948 FINK ENVIRONMENTAL CONSULTING, INC. THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE AK 99504-3305 RUSSELL DOUGLASS 6750 TESHLAR DR ANCHORAGE AK 99507 US BUREAU OF LAND MNGMNT ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE AK 99508 . CASS ARlEY 3108 WENTWORTH ST ANCHORAGE AK 99508 US MIN MGMT SERV RICHARD PRENTKI 949 E 36TH AV ANCHORAGE AK 99508-4302 US MIN MGMT SERV RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE AK 99508-4302 US MIN MGMT SERV LIBRARY 949 E 36TH AV RM 603 ANCHORAGE AK 99508-4363 US MIN MGMT SERV FRANK MILLER 949 E 36TH AV STE 603 ANCHORAGE AK 99508-4363 . UNIVERSITY OF ALASKA ANCHORAGE INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE AK 99508 US MIN MGMT SERV AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS MINERALS MANAGEMENT SERVICE ALASKA OCS REGION 949 E 36TH AV STE 308 ANCHORAGE AK 99508-4363 US MIN MGMT SERV RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE AK 99508-4555 USGS - ALASKA SECTION LIBRARY 4200 UNIVERSITY DR ANCHORAGE AK 99508-4667 CIRI NANCY MOSES POBOX 93330 ANCHORAGE AK 99509-3330 ANCHORAGE TIMES BERT TARRANT POBOX 100040 ANCHORAGE AK 99510-0040 ARCO ALASKA INC JENNY KEARNEY ATO 1255 POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE AK 99510-0360 . . TUNDRA TIMES GIL GUITERREZ POBOX 92247 ANCHORAGE AK 99509-2247 GAFO GREENPEACE PAMELA MILLER POBOX 104432 ANCHORAGE AK 99510 BRISTOL ENVIR SERVICES JIM MUNTER POBOX 100320 ANCHORAGE AK 99510-0320 ARCO ALASKA INC JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC LIBRARY POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE AK 99510-0360 ARCO TRANSPORATION AK INC M D KYRIAS ATO 926 POBOX 100360 ANCHORAGE AK 99510-0360 PETROLEUM INFO CORP KRISTEN NELSON POBOX 102278 ANCHORAGE AK 99510-2278 ALYESKA PIPELINE ROSS C. OLIVER, TAPS PLANNER 1835 S BRAGAW ST ANCHORAGE AK 99512 . . ARCO ALASKA INC MARK MAJOR ATO 1968 POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC SAM DENNIS ATO 1388 POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC SHELIA ANDREWS ATO 1130 PO BOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE AK 99510-6105 ALYESKA PIPELINE SERV CO PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE AK 99512 . ALYESKA PIPELINE SERV CO CHUCK O'DONNELL 1835 S BRAGAW - MS 530B ANCHORAGE AK 99512 US BUREAU OF LAND MGMT OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE AK 99513-7599 JWL ENGINEERING JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE AK 99516-6510 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE AK 99517-1303 ASRC CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE AK 99518 . ALYESKA PIPELINE SERV CO LEGAL DEPT 1835 S BRAGAW ANCHORAGE AK 99512-0099 ANCHORAGE DAILY NEWS EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE AK 99514 NORTHERN CONSULTING GROUP ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE AK 99517 DAVID CUSATO 600 W 76TH AV #508 ANCHORAGE AK 99518 SCHLUMBERGER DARREN AKLESTAD 1111 E 80TH AV ANCHORAGE AK 99518 HALLIBURTON ENERGY SERV MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE AK 99518-2146 JACK 0 HAKKILA POBOX 190083 ANCHORAGE AK 99519-0083 MARATHON OIL CO OPERATIONS SUPT POBOX 196168 ANCHORAGE AK 99519-6168 UNOCAL JANET BOUNDS POBOX 196247 ANCHORAGE AK 99519-6247 EXXON COMPANY USA MARK P EVANS PO BOX 196601 ANCHORAGE AK 99519-6601 . . OPSTAD & ASSOC ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE AK 99519 ENSTAR NATURAL GAS CO RICHARD F BARNES PRES POBOX 190288 ANCHORAGE AK 99519-0288 MARATHON OIL CO BRAD PENN POBOX 196168 ANCHORAGE AK 99519-6168 UNOCAL KEVIN TABLER POBOX 196247 ANCHORAGE AK 99519-6247 BP EXPLORATION (ALASKA) INC MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE AK 99519-6612 . BP EXPLORATION (ALASKA) INC BOB WILKS MB 5-3 POBOX 196612 ANCHORAGE AK 99519-6612 BP EXPLORATION (ALASKA) INC PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE AK 99519-6612 BP EXPLORATION (ALASKA), INC. MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE AK 99519-6612 AMERICA/CANADIAN STRATIGRPH CO RON BROCKWAY POBOX 242781 ANCHORAGE AK 99524-2781 L G POST O&G LAND MGMT CONSULT 10510 CONSTITUTION CIRCLE EAGLE RIVER AK 99577 . BP EXPLORATION (ALASKA) INC INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE AK 99519-6612 BP EXPLORATION (ALASKA) INC SUE MILLER POBOX 196612 M/S LR2-3 ANCHORAGE AK 99519-6612 JOHN KURZ PO BOX 220363 ANCHORAGE AK 99522 AMSI/VALLEE CO INC WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE AK 99524-3086 DIANA FLECK 18112 MEADOW CRK DR EAGLE RIVER AK 99577 D A PLATT & ASSOC 9852 LITTLE DIOMEDE CIR EAGLE RIVER AK 99577 DEPT OF NATURAL RESOURCES DGGS JOHN REEDER POBOX 772805 EAGLE RIVER AK 99577-2805 RON DOLCHOK POBOX 83 KENAI AK 99611 PHILLIPS PETR J A LANDRUM KENAI REG MGR P 0 DRAWER 66 KENAI AK 99611 PENNY VADLA POBOX 467 NINILCHIK AK 99639 . . PINNACLE STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER AK 99577 COOK INLET VIGIL JAMES RODERICK POBOX 916 HOMER AK 99603 DOCUMENT SERVICE CO JOHN PARKER POBOX 1137 KENAI AK 99611 KENAI PENINSULA BOROUGH ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI AK 99611-3029 BELOWICH COAL CONSULTING MICHAEL A BELOWICH HC31 BOX 5157 WASILLA AK 99654 JAMES GIBBS POBOX 1597 SOLDOTNA AK 99669 KENAI NATL WILDLIFE REFUGE REFUGE MGR POBOX 2139 SOLDOTNA AK 99669-2139 VALDEZ PIONEER POBOX 367 VALDEZ AK 99686 UNIV OF ALASKA FAIRBANKS PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS AK 99701 JACK HAKKILA POBOX 61604 FAIRBANKS AK 99706-1604 . . PACE SHEILA DICKSON POBOX 2018 SOLDOTNA AK 99669 ALYESKA PIPELINE SERVICE CO VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ AK 99686 VALDEZ VANGUARD EDITOR POBOX 98 VALDEZ AK 99686-0098 RICK WAGNER POBOX 60868 FAIRBANKS AK 99706 C BURGLIN POBOX 131 FAIRBANKS AK 99707 FAIRBANKS DAILY NEWS-MINER KATE RIPLEY POBOX 70710 FAIRBANKS AK 99707 DEPT OF NATURAL RESOURCES DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS AK 99709-4699 ASRC BILL THOMAS POBOX 129 BARROW AK 99723 UNIV OF ALASKA FBX PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS AK 99775 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU AK 99801-1182 . . FRED PRATT POBOX 72981 FAIRBANKS AK 99707-2981 K&K RECYCL INC POBOX 58055 FAIRBANKS AK 99711 RICHARD FINEBERG POBOX 416 ESTER AK 99725 UNIVERSITY OF ALASKA FBKS PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS AK 99775-5880 DEPT OF ENVIRON CONSERV SPAR CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU AK 99801-1795 . . ~ SNEA(P) DISTR FRANCE/EUROPE DU SUD/AMERIQUE TOUR ELF CEDEX 45 992078 PARIS LA DE FE FRANCE ~1 . . NO. 3587 P. 1 BP EXPLORATION BÞ ExplOratiOn (^la~K!I) Inc. mlO E!a9t Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 July 6, 1998 ::::"",,.:'f: 'ft' Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Application for Waiver to GOR Production LimitationJor Badami Pool Dear Mr. Johnston: Pursuant to 20 AAC 25.240, BP Exploration (Alaska) Inc. (BPXA), as Badami Unit Operator, respectfully submits on behalf of the Badami Working Interest Owners an application for a waiver to the GOR production limitation for the Badami Pool. Should you need any additional information to support this application, please contact me at 564-5789. Sincerely, ~V:~~ "c-c¡:.\'Jt:O o "7 '998 J\}l ~t\ ()\&GalCØ\$· ~&f}I.ß M~ W.L. Bredar Subsurface Manager, Badami OR \G\ NÞ.~.. JUL. 6. 1998 4: 33PM . . NO. 3587 P. 2 Application for Waiver to GOR Production Limitation for Badami Pool 20 AAC 25.240 BP Exploration (Alaska) Inc, (BPXA) in its capacity as a Working Interest Owner (WIO) and Operator of the Badami Unit, hereby applies for a waiver to the GOR production limitation as described in 20 AAC 25.240. BPXA is requesting that the waiver be granted to cover operations in which BPXA will act as Operator, including the Badami pool as currently defined in Conservation Order 402. The application for this waiver is based on the following grounds, as described in Section (c) of 25.240: · All produced gas from this pool, minus gas used for fuel, will be returned to the same pool, as described in part (2) of section (c). · Additionally, an additional recovery operation (water injection) will commence approximately two to four months after the start of production, followed closely by miscible gas injection. by ear1y 1999. This operation covers a second reason for granting a waiver from the GOR limitation, as described in part (1) of section (c). In general, the successful implementation of this project requires maximizing flexibility of production operations. It is normal for production wells in projects that include the injection of gas and/or miscible injectant, to see significant increases in their producing GOR over time as the injected gas reaches the production wells. In order for BPXA to maximize production from the Badami Pool, it will need to have the flexibility to produce wells to as high a GOR as is economic. t\J::C.P=1 VI::D ./1" 0 7 1998 Alaska Oil & Gas Coos. Commission AndJorage ORIGINAL