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Home My WebLink AboutCO 402 B~~ ~, Image Project C)rder File hover Page XI-IVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. G d ~''~~~ Order File Identifier Organizing tdone) RES AN Color Items: (_ Greyscale Items: ^ Poor Quality Originals: .o,aea iuuniumuiiii DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: ke,~,,~~e,~..~ iuumioiiim. OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Nan-Scannable) ^ Other: ^ Logs of various kinds: NOTES: ^ Other:: BY: Maria Date: 5 D lsl Project Proofing III IIIIII IIIII II III BY: aria Date: ~ /s/ Scanning Preparation x 30 = + =TOTAL PAGES - (Count does not include cover sheet). `n/~ BY: Maria Date: l ~.. ~s,~(,'j Isl Y (' Production Scanning Stage 7 Page Count from Scanned File: ~ ~ ~ (count does include cover sheet) Page Count Matches Number in Scannin Preparation: YES NO BY: Maria Date: 1 ~ rS/~q lsl ~ ~/' Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. III II VIII III II I I III ReScanned Maria Date: Isl Comments about this file: o~a,.~~e~kea iiiiimiiiiuiiii 10/6!2005 Orders File Cover Page.doc `'"'" Conservation Order 402B ~`~ Badami Oil Field 1. November 2, 2006 AOGCC letter re: Badami Automatic Shut-in Equipment 2. November 16, 2006 BPXA response to AOGCC letter of November 2, 2006 3. December 21, 2006 AOGCC letter to BPXA re: Badami Automatic Shut-In Equipment 4. December 22, 2006 Public Hearing Notice Advertising Order 5. December 27, 2006 AOGCC Memorandum from Jim Regg re: Badami Hearing - safety Valve System Requirements 6. January 12, 2007 E-mail from AOGCC to BPXA re Badami SVS Hearing 7. January 17, 2007 AOGCC Memorandum from Jim Regg re: Badami SVS - Proposed Rule 8. January 18, 2007 Public Hearing Notice Vacating Hearing of January 25, 2007 and rescheduling Hearing to February 22, 2007 9. January 18, 2007 Public Hearing Notice Vacating Hearing of January 25, 2007 and rescheduling Hearing to February 22, 2007 with corrected Proposed Pool Rule 10. February O1, 2007 AOGA ltr re: Comments on Draft Safety Valve System Regulations (20 AAC 25.265) 11. February 02, 2007 BPXA ltr requesting hearing be held as scheduled on February 22, 2007 12. February 20, 2007 BPXA ltr re: Addition of Sub-Surface Safety Valves (SSSV) rules to Badami Field Conservation Order 402A 13. February 22, 2007 Public Hearing Transcript 14. March 7, 2007 BPXA Powerpoint re: Badami Stabilization Information 15. July 8, 2008 BPXA Application Report for EMS Multiphase Metering System (C0402A-004) 16. August 25, 2008 AOGCC request for comments 17. September 30, 2008 Comments from MMS 18. October 3, 2008 Comments from DNR 19. October 7, 2008 Comments from DOR 20, _____________________ Various e-mails 21. December 2, 2008 BPXA Supplemental data for the AOGCC Report Conservation Order 402B `=` STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7t'' Avenue, Suite 100 Anchorage Alaska 99501 Re: Rule governing AUTOMATIC SHiJT-IN ) Conservation Order No. 402B EQUIPMENT for wells within the Badami ) Field, Arctic Slope, Alaska ) Badami Field Badami Oil Pool ~ March 16, 2007 ORDER CLOSING DOCKET BY THE COMMISSION: The Commission has the closed the Docket in the above captioned matter. DATED AND EFFECTIVE at Anchorage, Alaska and this I6th day of March, 2007. BY DIRECTION OF THE COMMISSION to the Commission STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: Rule governing AUTOMATIC SHUT-IN EQUIPMENT for wells within the Badami Field, Arctic Slope, Alaska Conservation Order No. 402B Badami Field Badami Oil Pool March 16, 2007 IT APPEARING THAT: 1. The Alaska Oil and Gas Conservation Commission ("Commission") on its own motion proposed to clarify automatic shut-in equipment requirements for wells within the Badami Oil Pool. 2. The Commission published notice of an opportunity for public hearing in the Anchorage Daily News on January 18, 2007. 3. The Commission received a request, dated February 2, 2007, from BP Exploration (Alaska) Inc. ("BPXA") for public hearing. FINDINGS: 1. BPXA is the operator of the Badami Oil Pool; the working interest owners are BPXA and Petrofina Delaware, Incorporated. 2. The Commission issued Conservation Order ("CO") 402, dated August 22, 1997, providing initial rules for the startup of development of the Badami Oil Pool on the North Slope of Alaska. 3. BPXA representatives testifying in support of CO 402 stated that BPXA would seek additional rules governing, among other things, completion and production practices following some initial development drilling. 4. Production commenced from the Badami Oil Pool in August 1998. 5. Area Injection Order ("AIO") 17, approved by the Commission on August 26, 1998, authorized the injection of water, gas, and miscible injectant for enhanced oil recovery operations in the Badami Oil Pool. i t ~, 6. The Commission issued Conservation Order 402A, dated August 27, 1998, amending CO 402 to include a waiver of the gas-oil ratio limitations of 20 AAC 25.240. 7. Rules governing completion and production practices were not included in CO 402A or AIO 17. 8. Commission regulation, 20 AAC 25.265, states that requirements for automatic shut-in equipment will be established for wells with onshore surface locations at the discretion of the Commission upon public notice and opportunity for hearing. 9. The Commission sent BPXA a letter, dated December 21, 2006, following review of safety valve system ("SVS") performance test results and existing pool rules for Badami. That letter provided notice of a hearing scheduled for January 25, 2007. The hearing was intended to establish SVS requirements for the Badami Field. The hearing was rescheduled to February 22, 2007 to allow BPXA additional time to prepare. 10. BPXA provided comments, by letter dated February 20, 2007, focusing on the subsurface safety valve provisions of the rule noticed by the Commission. 11. A public hearing was convened on February 22, 2007. BPXA testified about the challenges of implementing subsurface safety valve requirements in Badami wells. There was no testimony from BPXA regarding the proposed requirements for surface safety valve systems. BPXA requested the Commission consider: a. A temporary suspension of subsurface safety valve requirements for any well that does not have the appropriate hardware to make installation of a subsurface safety values possible; installation would occur in conjunction with the next tubing replacement; b. Revised wording regarding the reinstallation and testing of subsurface safety valves following any workover intervention activities; c. Delayed installation of subsurface safety valves until more temperate months; and d. Revised timing for submittal of SVS test results. 12. BPXA provided additional information by electronic mail, dated March 7, 2007, as requested during the hearing. That correspondence documents the stabilization time for wells operating in the Badami Field. CONCLUSIONS: 1. Requirements for automatic shut-in equipment on all Badami Field wells are warranted based on consistency with other North Slope fields similarly positioned near the Beaufort Sea coastline. 2. Amending CO 402A with a new rule establishing clear SVS requirements and performance expectations is consistent with the Commission's understanding of BPXA's intent when such rules were deferred to allow for early field development. 3. All active Badami wells are equipped with automatic surface safety valves and hydraulically actuated wing valves (operated by the same low pressure switches that actuate the surface safety valves), and the wells were initially constructed so that one of several types of subsurface safety valves could be added. Conservation Order No. 402B Effective March 16, 2007 Page 2 of 5 i 4. Some special considerations may impact the installation and operation of subsurface safety valves because of paraffin production from Badami wells. Optimizing subsurface safety value performance during the summer months will mitigate potential risks to pipeline operations resulting from downtime associated with the installation, maintenance, and operation of subsurface safety valves. 5. Conservation Order 402A should be amended and reissued to include requirements for automatic shut-in equipment on Badami Field wells. NOW, THEREFORE, IT IS ORDERED that Conservation Order 402A be amended to include requirements for the installation, operation and testing of automatic shut-in equipment and that the terms and conditions of Conservation Order 402A be reissued as Conservation Order 402B. The findings, conclusions, and administrative records for Conservation Orders 402 and 402A 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 402A. Rule 1 Field and Pool Name The field name is Badami. Hydrocarbons underlying the affected area and within the herein defined interval of the Canning Formation 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 of 9,500 feet and 11,500 feet in the Badami No. 1 well. Rule 3 Well Snaciris Nomina120-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. Rule 5 Gas-Oil Ratio Limitation Wells producing from the Badami Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(b) as long as the provisions of 20 AAC 25.240(c) apply. Conservation Order No. 402B Effective March l 6, 2007 Page 3 of 5 Rule 6 Automatic Shut-in Equipment a. All completed wells except water source wells, disposal injection wells (wells used for the disposal of oilfield wastes), and monitor wells must be equipped with a functional safety valve system, except when the well's production or injection zone is mechanically isolated from the atmosphere or during well workover or intervention operations. b. The safety valve system must include: 1. A fail-safe surface safety valve with actuator and aloes-pressure pilot or low- pressure transmitter with the capability to shut in the well when the flow line pressure drops below the required system actuation pressure. For development wells, the required system actuation pressure is at least 50 percent of the inlet separator pressure or 25 percent of the flowing tubing pressure, whichever is greater; for gas injection wells, the required system actuation pressure is 50 percent of the compressor discharge pressure. 2. A fail-safe subsurface safety valve installed in the tubing string below the base of the permafrost and capable of preventing uncontrolled flow from the tubing. Wells that pass a no-flow performance test (i. e., where there is no flow of hydrocarbons to the surface) witnessed by a Commission representative are not required to have subsurface safety valves. Wells that require subsurface safety valves under this rule but do not have the necessary hardware to make subsurface safety valve installation possible are exempt from the subsurface safety valve requirements only until such time as tubing is removed from the well. 3. A safety valve system control unit placed in a location that is readily accessible. c. All safety valve systems must be maintained in good operating condition at all times and must be protected to ensure reliable operation under the range of weather conditions that may be encountered at the well sites; d. All the safety valve systems must be tested as follows: 1. At least once every 210 days; 2. Within 48 hours after returning to operation after shut-in; Before each SVS test, the Commission must be given at least 48 hours notice for an opportunity to witness the test. Results of any test must be provided in an electronic format to the Commission within 14 days of the completion of the test. e. Subsurface safety valves may be blocked or removed when necessary for well workover or intervention operations. Subsurface safety valves must be made operable immediately and tested within 48 hours after returning the well to operation, unless otherwise authorized by the commission or the well is shut-in. Conservation Order No. 402B Effective March 16, 2007 Page 4 of 5 f. Surface safety valves and low pressure pilots or low pressure transmitters may be removed or defeated only when the wells are shut-in or the pads are continuously manned by a person trained in well operations. DONE at Anchorage, Alaska and dated March 16, Norman, Chairn~P~ ~2il,~fnd Gas Conservation Commission (1 ~ ~ ~ f i{ . ~ >' , r ~ c1 ..~.t.g .I ~ ' .1 ~ ~ ' ~ : 1 ~ ~.~ s f"~ ~ ~ ,, , ' .. ' 4S u ~~ ~t i :~ r y ~ ~ e Y 1• 5 ~~ .~'_%-_ J` Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Cathy P. F erster, Commissioner Alaska 0 1 and Gas Conservation Commission 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 23`d 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 ]0-day period. An affected person has 30 days from 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., 10`h day after the application for rehearing was filed). Conservation Order No. 402B Effective March 16, 2007 Page 5 of 5 Mary Jones ~' David McCaleb XTO Energy, Inc. IHS Energy Group Cartography GEPS 810 Houston Street, Ste 2000 5333 Wertheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 George Vaught, Jr. Jerry Hodgden PO Box 13557 Hodgden Oil Company Denver, CO 80201-3557 408 18th Street Golden, CO 80401-2433 John Levorsen Kay Munger 200 North 3rd Street, #1202 Munger Oil Information Service; Inc Boise, ID 83702 PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Schlumberger Halllburton Drilling and Measurements 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Land Department 9649 Musket Bell Cr.#5 PO Box 93330 Anchorage, AK 99507 Anchorage, AK 99503 Gordon Severson Jack Hakkila 3201 Westmar Cr. PO Box 190083 Anchorage, AK 99508-4336 Anchorage, AK 99519 James Gibbs Kenai National Wildlife Refuge PO Box 1597 Refuge Manager Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin PO Box 60868 PO Box 70131 Fairbanks, AK 99706 Fairbanks, AK 99707 North Slope Borough Williams Thomas PO Box 69 Arctic Slope Regional Corporation Barrow, AK 99723 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 ~~1 p~ w , `~' Subject: CO 402B From: Jody Colombie <Jody_colombie@admin.state.ak.us> Date: Tue, 20 Mar 2007 15:44:23 -0800 To: undisclosed-recipients:; BCC: 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 <trmjrl @aol.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinacom>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco,com> "Randy L. Skillern" <Ski11eRL@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" <P1attJD@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.go~>, 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@shelicom>, 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>, 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> bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, many <marty@rkindustral.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net,>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary. Schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, 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.corn>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bil1 Fowler@anadarko.COM>, Scott Cranswck <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, jack. newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, n1617@conocophillips.com, Tim Lawlor <Tim Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda^Kalui@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@aogaorg> Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Gary Rogers <gary_rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur Copoulos@dnrstate.ak.us> Ken <klyons@otsintl.com>, Steve Lambert <salambert@unocal.com>,-Joe Nicks mews@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews <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 of 2 3/20/2007 3:44 PM <mike@kbbi.org>, Garland Ro~inson <gbrobinson@marathonol.com>~ammy Taylor <Camille_Taylor@law.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 <jim_regg@adminatate.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.stateak.us>, David Steingreaber <david.e.steingreaber@exxonmobil.com>, akpratts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve, moothart@dnratate.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paulTbloom@ml.com>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple_davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com> Tricia Waggoner <taggoner@nrginacom>, Mike Stockinger <Mike.Stockinger@anadarko.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegarner <jimwinegarner@brooksrangepetro.com>, Matt Rader <matt rader@dnr.state.ak.us>, carol smyth <carol.smyth@shell.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoil.com>, fours@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@international.gc.ca~, Cary Carrigan <cary@kfgd.com>, Sonja Frankllin <sfranklin6@bloomberg.net> Jody Colombie <iody colombie(c~,admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf C0402b.pdf Content-Encodings base64 2 of 2 3/20/2007 3:44 PM CO 402B ~ ~' Subject: CO 402B From: Ceresa Tolley <ceresa tolley@admin.state.ak.us~ Date: Tue, 20 Mar 2007 15:38:19 -0800. To: Cynthia B'Mcver <bren rnciver a,admin.state.ak.us> Here is Conservation Order 402B Content-Type: application/pdf D00070320-OOl.pdf Content-Encoding: base64 1 of 1 3/20/2007 3:46 PM • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: AN ORDER rescinding those rules within ) Docket Number: CO -10 -21 existing Conservation Orders relating to ) Other Order No. 66 well safety valve systems. ) ) Statewide, Alaska ) January 11, 2011 IT APPEARING THAT: 1. On October 13, 2010 the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) formally adopted new regulations relating to well safety valve systems, at 20 AAC 25.265. 2. The newly adopted well safety valve system regulations underwent final review by the Regulations Section of the Alaska Attorney General's Office and were forwarded to the Alaska Lieutenant Governor's Office on October 28, 2010. 3. The new regulations were signed by the Lieutenant Governor and took legal effect on December 3, 2010. 4. To ensure consistency with the new regulations, the AOGCC, on its own motion, proposed to rescind part or all of the outdated rules within existing Commission Orders relating to well safety valve systems. 5. On November 4, 2010, pursuant to 20 AAC 25.540, the Commission published in the Alaska Daily News notice of opportunity for public hearing on December 6, 2010. 6. The Commission received written comments in response to its public notice, and held a public hearing on December 7, 2010. 7. Oral testimony and written comments were provided at the December 7, 2010 hearing. FINDINGS: 1. Well safety valve systems are regulated under newly- adopted 20 AAC 25.265, which consolidates the requirements previously established in legacy documents, policies, and statewide guidelines relating to safety valve systems. 2. Thirty -four existing Commission Orders contain rules governing well safety valve systems. Twenty of those Orders contain broad regulatory requirements for safety valve systems that are now covered by the newly- adopted regulations. The remaining fourteen Orders include field- or pool - specific safety valve system requirements. Other Order 66 • • Page 2 Statewide, AK January 11, 2011 3. Within existing Commission Orders are rules unrelated to well safety valve systems; these rules will continue in effect, unmodified. 4. Existing Commission Orders containing individual rules relating to well safety valve systems are enumerated in the attached Table. CONCLUSIONS: 1. Eliminating redundant requirements and standardizing wording for those field - and pool- specific safety valve system requirements deemed appropriate to retain will improve regulatory clarity. 2. Twenty existing Commission Orders that include rules relating to well safety valve systems are rendered unnecessary, and can be replaced by newly- adopted 20 AAC 25.265. As more fully set forth in the attached Table, those Orders are Conservation Orders 98A, 207A, 300, 311B, 317B, 329A, 341E, 345, 402B, 432D, 452, 457B, 471, 477, 484A, 505B, 553, 559, 570, and a Commission unnumbered Order signed March 30, 1994 (policy dictating SVS performance testing requirements). 3. Fourteen existing Commission Orders include field- or pool- specific safety valve system requirements that the Commission considers appropriate for retention. Wording for the same safety valve system requirements existing in different Commission Orders has been standardized. As more fully set forth in the attached Table, those Orders are Conservation Orders 406B, 423, 430A, 435A, 443B, 449, 456A, 458A, 562, 563, 569, 596, 597, and 605. NOW, THEREFORE, IT IS ORDERED THAT individual rules in thirty-four existing Commission Orders that relate to well safety valve systems are hereby rescinded or revised as enumerated in the Table. Remaining rules unrelated to safety valve systems within affected Commission Orders remain in effect, unmodified. DONE at Anchorage, Alaska, and dated ary 11, 2011 Ave .-- Daniel T. Sear o , r., Commissioner, Chair • • . • it . • : , s Conservation Commission O ti'*8 44 i, Co er rA 7 rip.arrman, Oil • . • a Conserva ion Commission '''' Cat y P. oerst r, Commissioner /h)N I0 ` Alaska it and Gas Conservation Commission Other Order 66 • • Page 3 Statewide, AK January 11, 2011 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, January 11, 2011 4:08 PM To: Ballantine, Tab A (LAW); '(foms2 @mtaonline.net)'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; 'caunderwood'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber; 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe, '• '; 'Fred Laugh lin'; 'Gary Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; Fred Steece , 'Gary g ry Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; 'Marguerite kremer; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tina Grovier; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombia, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk @alaska.gov); Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA) Subject: Other 66 Safety Valve Systems Attachments: other66.pdf Samlowi hcv Fi4'.ear �1Za.s?:.aiOLLa Coqvu(n,vkio (907)793 -1223 (907)276-7542 (fax) 1 • 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 \NA \ \\\\ Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reqts from Order Revised Rule - "Well safety valve systems" (2) Comment fail -safe auto SSV and SCSSV; injection wets (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "In wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.2659(b); 25.265(d)( Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve" fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(1); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Kuparuk 596 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit Raven 570 5 yes r N/A deactivated SVS was replaced with requirement to maintain a deactivated SVS; sign on wellhead 25.265(m) tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "In wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." Prudhoe Ba Unit Put River 559 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Deep Creek Unit Happy Valley 553 3 yes ssv or SSSV 25.265(a) N/A Prudhoe Ba Unit Orion 505B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple p e requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Polaris 484A 3 yes prescribed by Commission 25.265(h)(5) p requirement laces SSSV nipple re uiremeM for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI Milne Point - 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; Milne Point Unit Schrader Bluff 477 5 yes injection well require SSSV or injection valve below permafrost; test 25.265(h)(5) N/A replaces SSSV nipple requirement for all wells every 6 months Prudhoe Ba Unit Borealis 471 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells Northstar Northstar 458A 4 no fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500- 25.265(a); 25.265(b); 25.265(d)(1) "The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." Existing pool rule established a minimum setting depth for the ft minimum setting depth for SSSV SSSV Prudhoe Ba Unit Aurora 457B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test every 6 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; Y Y months 25.265(h)(5) NIA replaces SSSV nipple requirement for all wells fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Prudhoe Ba Unit Midnight Sun 452 6 yes fail -safe auto SSV (all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y g flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be installed above or below 25.265(a); 25.265(b); 25.265(d)(1); "The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip 25.265(h)(5) above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by pressure; test every 6 months arrangement." readopted regulation fail -safe auto SSV and SCSSV (producers and gas injectors); water "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve injection wells require (i) double check valve, or (ii) single check valve 25.265(a); 25.265(b); 25.265(d)(2)(H) arra ement or ii a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by I Colville River Unit Alpine 443B 5 no in 1 eq O O n9 O g f readopted regulation and SSV SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve. SSSV requirement for MI injectors fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Requirement to maintain a wellhead sign and list of wells with deactivated; maintain list of wells w /deactivated SVS; test as deactivated SVS was replaced with requirement to maintain a Kuparuk River Unit; 25.265(a); 25.265(b); 25.265(h)(5); Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP 25.265(m) N/A 432D.009 l when not manned; ve [re:dadministrative e LPS when O surface Milne Point Unit may be defeated on W. Sak injectors w /surface pressure <500psi w/ notice when defeated and placed back in service injection pressure for West Sak water injector is <500psi] Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Revised Rule - "Well safety valve systems" (2) Comment Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reqts from Order fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Milne Point - Sag fail -safe auto SSV; injection wets require double check valve; test Check valve requirements for injectors are not covered by Milne Point Unit 423 7 no every 6 months 25.265(a); 25.265(b); 25.265(h)(5) "Injection wells must be equipped with a double check valve arrangement." readopted regulation River . fail -safe auto SSV; gas /MI injectors require SSV and single check Check valve requirements for injectors are not covered by valve and SSSV landing nipple; water injection wells require (i) double "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve readopted regulation; readopted 25:265(d)(5) does not include Unit Kuparuk West Sak 406B 6 no check valve, or (ii) single check valve and SSV; test every 6 months; 25.265(x); 25.265(b); 25.265(d); arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or SSSV requirement for MI injectors; administrative approval CO Kuparuk River Um p CO 406B.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be 4066.001 remains effective [re:defeating the LPS when surface injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi." injection pressure for West Sak water injector is <500psij placed back in service fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A Badami Badami 402B 6 yes submit test results electronically within 14days; SVS defeated /removed 25.265(m) only if well SI or pad continuously manned fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission 25.265(m) tag on well when not manned fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must be maintained and tested as part of SVS; sign on well if SVS 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; N/A Prudhoe Bay Unit Prudhoe 341E 5 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells prescribed by Commission fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Niakuk 329A 5 yes deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be rermoved as part of 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Pt. McIntyre 317B 8 yes routine well ops w/o notice 25.265(1); 25.265(m) replaces SSSV nipple requirement for all wells fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit West Beach 311B 6 yes w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork West Fork (Sterling 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A A &B) Requirement to maintain a wellhead sign and list of wells with fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); N/A deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Lisburne 207A 7 yes w/deactivated SVS; test as prescribed by Commission 25.265(m) tag on wet when not manned suitable automatic safety valve installed below base of permafrost to 25.265(d) N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 yes prevent uncontrolled flow replaces SSSV nipple requirement for all wells AOGCC Policy - SVS Failures; issued by order of the N/A N/A yes Commission policy dictating SVS performance testing 25.265(h); 25.265(n); 25.265(o) N/A Commission 3/30/1994 (signed by Commission Chairman Statewide N/A requirements Dave Johnson) Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded Page 2 of 2 • • Public Hearing Record And Backup Information available in Other 66 `~~ r t ~ ~ a ~ ~:_ g ~._ti (6jj-tl <. ~ ~~ ~ ~ i ~ ~ ~ ~E'~ ~ i~-~ ~g SARAH PALIN, GOVERNOR ~~SA OI~ ~D ~~ 333 W. 7th AVENUE, SUITE 100 CO1~T5F,RQA'I`IO1~T COMIIIISSIOIQ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 Fp,)( (907) 276-7542 CORRECTED ADMINISTRATIVE APPROVAL CO 559.009 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.007 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.005 All other oil pools within Prudhoe Bay Field ADMINISTRATIVE APPROVAL CO 548.005 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.008 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.005 All Northstar Pools ADMINISTRATIVE APPROVAL CO 402B.001 Badami Oil Pool Gordon Pospisil 'T'echnology & 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 Administrative Approval number for CO 547. By letter dated April 27, 2009, BP Exploration (Alaska), Inc. (BPXA) requests authorization to use FMC Technologies System (EMS) multiphase flowmeter system (EMS MPM system) for well testing and allocation in the pools referenced above, subject to certain conditions. BPXA's request is GRANTED with the conditions identified below. In 2007, under temporary authorization from the Alaska Oil and Gas Conservation Commission (AOGCC or Commission), BPXA began field trials of the EMS MPM system utilizing the Arctic Slope Regional Corporation (ASRC) Unit #5 portable well testing system. The qualification testing program occurred in three stages. The first stage occurred at the Prudhoe Bay Unit (PBU) L and E pads and Milne Point Unit (MPU) S and H pads. During this phase, a total of 69 tests were conducted on 23 wells using ASRC Unit #5 to assess hardware performance. These tests were undertaken in series with the ASRC Unit #1, a conventional portable well testing system, and tank strapping tests (to verify the accuracy of both portable metering systems (ASRC Unit #5 and ASRC Unit #1)). The results were used to design and implement modifications to the ASRC Unit #5 hardware, fluid data input, and crew training and testing protocols. The second stage occurred at the MPU I pad, where seven tests were conducted on six wells to evaluate the effectiveness of the modifications made after the first stage. These tests were also done in series with the ASRC Unit #1. The third stage occurred at the PBU V Pad and MPU B, G, I, J, K, and S pad(s), and involved a total of 99 tests conducted on 64 wells. Four of these well tests were conducted with the ASRC Unit #5 and ASRC Unit # 1 in series. The results were compared with historical testing data and water cut samples obtained during this phase of testing. During this stage, special attention was paid to improving fluid property input; equipment and protocol modifications were made. Additional crew training was also provided. Over the course of this qualification testing, the modified EMS MPM system utilized on ASRC Unit #5 was demonstrated to be a reliable system for well testing and production allocation. When compared with ASRC Unit # 1 and historical testing data, ASRC Unit #5 is typically within 10% for total liquid rate and within 5% for water cut, with no apparent bias toward under- or over-reporting. When operated within the limits outlined in BPXA's April 27, 2009 application, the EMS MPM system will provide reliable results for well testing and production allocation. Accordingly, BPXA's request to utilize the EMS MPM system for well testing and production allocation in the subject pools is GRANTED subject to the following conditions: 2) 3) the system must be operated within the parameters identified in the document titled "Supplemetal-2 Data for the AOGCC -Report 3/24/09," which was included with BPXA's April 27, 2009, application; changes to the parameters must be approved by the Commission; and use of the EMS MPM system at No ar Unit must be approved by the Minerals Service of the U.S. Depar~ent of e Int rior. DONE at Anchor e Al s a, and dat June , 2009. Daniel T. Seatnount, Jr. J n Nor a Cathy . Foerster Chairman ommis ' ner _ Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 3 ] .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 f'or reconsideration must set out the respect in which the order or decision is believed to be erroneous. 'fhe 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. 'Chat appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5.00 p.m. on the next day that does not fall on a weekend or state holiday. June 24, 2009 Page 2 of 2 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, June 24, 2009 8:10 AM Subject: Various AA's multiphase flow metering Attachments: Various AA's multiphase flow metering.pdf k;+. Various AA's multiphase flow m... cc: Anna Raff; Barbara F Fullmer; bbritch; Bill Walker; Brad McKim; Brandon Gagnon; Brian Gillespie; Brian Havelock; Brit Lively; Bruce Webb; buonoje; Cammy Taylor; Cande.Brandow; carol smyth; Cary Carrigan; caunderwood@marathonoil.com; Charles O'Donnell; Chris Gay; Cliff Posey; Dan Bross; daps; Daryl J. Kleppin; David Brown; David Gorney; David House; David L Boelens; David Steingreaber; ddonkel; Deborah Jones; Decker, Paul L (DNR); doug_schultze; Eric Lidji ;Evan Harness; eyancy; foms2@mtaonline.net; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gregg Nady; gspfoff; Hank Alford; Harry Engel; jah; Janet D. Platt; jejones; Jerry Brady; Jerry McCutcheon; Jim Arlington; Jim White; Jim Winegarner; Joe Nicks; John Garing; John S. Haworth; John Spain; John Tower; John W Katz; Jon Goltz; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; knelson@petroleumnews.com; Krissell Crandall; Kristin Dirks; Kristin Elowe; Laura Silliphant; mail=akpratts@acsalaska.net; mail=fours@mtaonline.net; Marilyn Crockett; Mark Dalton; Mark Hanley; Mark Kovac; Mark P. Worcester; Marguerite kremer; Melanie Brown; Michael Nelson; Mike Bill; Mike Jacobs; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Nick W. Glover; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; Patty Alfaro; Paul Winslow; Pierce, Sandra M (JPO); Rader, Matthew W (DNR); Randall Kanady; Randy L. Skillern; rmclean; Rob McWhorter ; rob.g.dragnich@exxonmobil.com; Robert Campbell; Robert Province; Rudy Brueggeman; Scott Cranswick; Shannon Donnelly; Sharmaine Copeland; Sondra Stewman; Sonja Frankllin; Stan Porhola; stanekj; Steve Lambert; Steve Moothart; Steven R. Rossberg; tablerk; Tamera Sheffield; Temple Davidson; Teresa Imm; Terrie Hubble; Thompson, Nan G (DNR); Tim Lawlor; Todd Durkee; Tony Hopfinger; trmjr1; Von Gemmingen, Scott E (DOR); Walter Featherly; Walter Quay; Wayne Rancier; Aaron Gluzman; Dale Hoffman; Frederic Grenier; Gary Orr; Jerome Eggemeyer; Joe Longo; Lamont Frazer; Marc Kuck; Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; Sandra Lemke; Scott Nash; Steve Virant; Tom Gennings; Willem Vollenbrock; William Van Dyke; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) ~,,~~: ~a..~,..~~. Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 ~~O/ ~' ., ~~ ~,~, l ~°:~ 9 ~' ~~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~.:~ j~ ~~ ~ SARAH PALIN, GOVERNOR SSA OIL Als~ 1705 333 W. 7th AVENUE, SUITE 100 COj~T5F,,RQA'I`IO1~T COMDII5SIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 559.009 Put River Oil Pool ADMINISTRATIVE APPROVAL CO 570.007 Raven Oil Pool ADMINISTRATIVE APPROVAL CO 547.002 All other oil pools within Prudhoe Bay Field ADMINISTRATIVE APPROVAL CO 548.005 All Endicott Pools ADMINISTRATIVE APPROVAL CO 550.008 All Milne Point Pools ADMINISTRATIVE APPROVAL CO 551.005 All Northstar Pools ADMINISTRATIVE APPROVAL CO 402B.001 Badami Oil Pool Gordon Pospisil Technology & Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Pospisil: By letter dated April 27, 2009, BP Exploration (Alaska), Inc. (BPXA) requests authorization to use FMC "Technologies System (EMS) multiphase flowmeter system (EMS MPM system) for well testing and allocation in the pools referenced above, subject to certain conditions. BPXA's request is GRANTED with the conditions identified below. In 2007, under temporary authorization from the Alaska Oil and Gas Conservation Commission (AOGCC or Commission), BPXA began field trials of the EMS MPM system utilizing the Arctic Slope Regional Corporation (ASRC) Unit #5 portable well testing system. The qualification testing program occurred in three stages. The first stage occurred at the Prudhoe Bay Unit (PBU) L and E pads and Milne Point Unit (MPU) S and H pads. During this phase, a total of 69 tests were conducted on 23 wells using ASRC Unit #5 to assess hardware performance. These tests were undertaken in series with the ASRC Unit #l, a conventional portable well testing system, and tank strapping tests (to verify the accuracy of both portable metering systems (ASRC Unit #5 and ASRC Unit #1)). The results were used to design and implement modifications to the ASRC Unit #5 hardware, fluid data input, and crew training and testing protocols. The second stage occurred at the MPU I pad, where seven tests were conducted on six wells to evaluate the effectiveness of the modifications made after the first stage. These tests were also done in series with the ASRC Unit # 1. The third stage occurred at the PBU V Pad and MPU B, G, I, J, K, and S pad(s), and involved a total of 99 tests conducted on 64 wells. Four of these well tests were conducted with the ASRC Unit #5 and ASRC Unit #1 in series. The results were compared with historical testing data and water cut samples obtained during this phase of testing. During this stage, special attention was paid to improving fluid property input; equipment and protocol modifications were made. Additional crew training was also provided. Over the course of this qualification testing, the modified EMS MPM system utilized on ASRC Unit #5 was demonstrated to be a reliable system for well testing and production allocation. When compared with '` °~...~ ASRC Unit # 1 and historical testing data, ASRC Unit #5 is typically within 10% for total liquid rate and within 5% for water cut, with no apparent bias toward under- or over-reporting. When operated within the limits outlined in BPXA's April 27, 2009 application, the EMS MPM system will provide reliable results for well testing and production allocation. Accordingly, BPXA's request to utilize the EMS MPM system for well testing and production allocation in the subject pools is GRANTED subject to the following conditions: 1) the system must be operated within the parameters identified in the document titled "Supplemetal-2 Data for the AOGCC -Report 3/24/09," which was included with BPXA's April 27, 2009, application; 2) changes to the parameters must be approved by the Commission; and 3) use of the EMS MPM system at Northstar Unit must be approved by the Minerals Management Service of the U.S. Department of the nt rior. D NE at Anchorage, Alaska, a J 2 , Daniel T. Seamount, Jr. John Orman Chairman o m' 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." [n 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. June 23, 2009 Page 2 of 2 . i Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, June 24, 2009 8:10 AM Subject: Various AA's multiphase flow metering Attachments: Various AA's multiphase flow metering.pdf ~::. '~:. Various AA's multiphase flow m... cc: 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; Chris Gay; 'Cliff Posey'; 'Dan Bross'; 'daps'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; Deborah Jones; Decker, Paul L (DNR); 'doug_schultze'; 'Eric Lidji '; 'Evan Harness ; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin ; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'Janet D. Platt'; 'jejones'; 'Jerry Brady'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; 'Julie Houle'; 'Karl Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Kristin Elowe'; 'Laura Silliphant'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; Melanie Brown; 'Michael Nelson'; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Winslow'; Pierce, Sandra M (JPO); Rader, Matthew W (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; Teresa Imm; 'Terrie Hubble'; Thompson, Nan G {DNR); 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjr1'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Mary Jones ~ David McCaleb XTO Energy, Inc. IHS Energy Group Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 George Vaught, Jr. Jerry Hodgden PO Box 13557 Hodgden Oil Company Denver, CO 80201-3557 408 18th Street Golden, CO 80401-2433 Mark Wedman Schlumberger Halliburton Drilling and Measurements 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99502 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 Anchorage, AK 99503 Anchorage, AK 99507 Gordon Severson Jack Hakkila 3201 Westmar Cr. PO Box 190083 Anchorage, AK 99508-4336 Anchorage, AK 99519 James Gibbs Kenai National Wildlife Refuge PO Box 1597 Refuge Manager Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin PO Box 60868 PO Box 70131 Fairbanks, AK 99706 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 i .~. Cindi Walker 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 Ciri Land Department PO Box 93330 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 ~ 21 Supplemental Data for AOGC 2 -02 -08 0 Supplemental data for the AOGCC Report 12/02/00 ASRC Unit 5 Field Qualification Tests This report provides supplemental data requested by Jane Williamson of AOGCC in regards to the ASRC Unit 5 Field Qualifications. A report describing field qualification of ASRC Unit 5 was originally presented to AOGCC during the week of Sept 8, 2008. A Teleconference was then arranged to discuss the details of the Unit 5 performance. The discussion in the current supplemental report is intended to address questions submitted by Jane Williamson in her email of Sept. 29, 2008. These questions fall essentially in the following categories: 1. Unit 5 in comparison with Unit 1 — oil, gas, WC Excel raw data 2. Corrections for Permittivity/ conductivity 3. Corrections for viscosity, Reynolds number The following information is supplied to address the above issues. Table 1 shows the piggy back test results from early qualification tests. As noted in our initial report these were the only piggy back and tank tests conducted during the qualification tests. Lack of availability of reference Unit 1 and HSE concerns resulted in the remaining portion of the qualifications tests to be pursued without piggy back tests as will be discussed later. The oil and gas rate as well as the WC data are presented in Table 1. In addition Table 1 provides grab sample water cut (SWC) data that was also used for reference. A third method of referencing the data — i.e. tank strapping was also used for qualification. The tank tests results are shown in Table 1. Since the qualification tests were conducted over the August 2007- April 2008 period, it was necessary to go back and "reprocess" some of the older tests based on the knowledge gained from the more recent tests. One major issue that came to our attention during the March -April 2008 testing period was that permittivity and conductivity of fluids measured from salinity of produced water or API gravity of the oil was not representative of the in -situ permittivity /conductivity of fluids as was seen by the multiphase meter. An in -situ permittivity /conductivity protocol was developed to correct this problem. This protocol was field tested in April of 2008 and formally adopted for all tests that were conducted from that time on. However since this information was not available when the early piggy back tests were conducted, we had to go back and reprocess the early data for the permittivity and conductivity. The reprocessed data is the data shown for Unit 5 in Table 1. Page 1 of 5 Supplemental Data for AOGCC 12 -02 -08 Table 1 — Piggy Back Tests 1 Unit 5 Tank - BBL Accumulated Well Date Oil -BPD Gas - MSCFD %WC SWC %WC I Oil - BPD Gas -MSCFD Tank Unit 1 Unit 5 MPS -12 8/10107 t ; 88% 88% 512 483 84 83 92 MPS -08 8/12/07 65% 62% 1 729 103 MPS -17 8/10/07 84% 79% 1 705 1215 MPS -17 8112/0 78 7 7 8 72 MPS-29 8/9/07 78% 76% 453 29 MPS -04 8/11/07 97% 92% 112 19 MPS -19 8/11/07 92% 95% 95 19 9 4 7 1 3 07 MPS -25 8110/ 90 0 0 19 5 53 I % % 58 MPH -04 8/13/07 26% 22% 187 10 MPH -13 8/13107 59% 56% 1 98 48 MPH -16 8112/07 23% 25% 679 155 MPI -03 12114/07 -10, - . '..� ,, 5% 1% 97 13 MPI -03 12/18/07 4% 1% 104 19 MPI -04 12/18/07 55% 49 °bi 181 143 MPI -06 12/15/07 ' , • m . 62% 57% 139 122 MPI -14 12116/07 43, " -' 47% 59% 254 110 MPI -17 12/14/07 20% 34% 755 355 MPI -19 12/17/07 ".'. ` 11% 17% 423 1 323 The reprocessing was used to revaluate all tests conducted in the early stages of qualification as well as some of the tests in April — May 2008 to confirm that correction protocol for fluid properties was working. The reprocessing was discontinued in May 2008 after the results showed no changes in measurements between the original and the reprocessed test data. This was taken as the indication that the fluid property input protocol developed in April 2008 was working properly. The spreadsheet shown in appendix 1 has been used to establish corrections for permittivity and conductivity values for a test. Another major issue that came to our attention during the early qualification tests was the impact of well stream composition and flow rates on discharge coefficient of the Venturi used in the TopFlow meter. Andrew Hall has developed a smart spreadsheet to calculate the discharge coefficient of the Venturi based on the following input parameters: • Well flow rate, WC, GVF • Operating pressure and temperature of the well stream • Oil, Water and Gas density • Venturi Geometry These parameters are measured during the stabilization period — actually these fluid properties are also needed for permittivity /conductivity determination. The oil, water and gas density is used to estimate viscosity at the operating temperature and pressure. The calculated Reynolds number, Venturi geometry, and velocity profile based on flow rates are then used to estimate the Discharge Coefficient for the test. The calculated VDC has varied from 0.75 to 0.99 in the tests conducted. Page 2 of 5 Supplemental Data for AOGCC 12 -02 -08 Two methods are used for the continuous "quality control" check on the well tests conducted since the field test report that was submitted to AOGCC in September 2008. The first method is to continue sample WC analysis in every test. This method essentially amounts to continued field verification testing as recognized by AOGCC Guideline — Section 4.1.2. Figure 1 shows the difference in grab sample WC and Unit 5 WC values during August of 2007 to November 2008. One would note the substantial improvements in the WC accuracy (narrowing of scatter band) as more effective testing protocols are implemented and Unit 5 crew has gained experience working with equipment. Since accurate WC values impact measurements of oil as well as gas rates in Unit 5 measurements, the data in figure 1 can be taken as an indicator of improved well testing quality. 50 • MP -8 a MP -E 40 x MP -G x MP -H • MP - 1 + MP - 30 ❑ MP -K 0 MP -S - - - +/- 5 0 20 x � • x V x = 10 • 0 e x + L _- _- _- _- _- _- _- _ -_____ or a, + a x 0 p x ® - - - - - - • x +� - - - - - - v -10 00 + n L d • -20 ®0 x 0 -30 • -40 -50 04 -28 -2007 08 -06 -2007 11 -14 -2007 02 -22 -2008 06 -01 -2008 09 -09 -2008 12 -18 -2008 Figure 1 — difference in WC values between grab samples and Unit 5 during the entire course of field testing The second quality control method that has been used is the comparison of the Unit 5 field test results against the historical values. As an example, Figures 2 -4 show this historical comparison for Milne Point K -pad wells. These plots show the WC, gross fluid, and gas rate data for all K- pad wells tested. We find good tracking of Unit 5 tests with historical well test data as well as the grab samples used as the reference for the WC data. Page 3 of 5 � ^ 5uoo�nmenta|0ataforA�� -- 2-02-08 nIt �5��C So WC 55% SO WC � Supplemental ~~- Figure 2— Comparison ofVVC data from Unit 5, garb sample / and Historical values for all wells at Milne Point K-pad. Vertical bars indicate "estimated" variation in the historical WC data. BHP CHANGE sm Amps % Change — Historic GF -35% 1500 25% 1000 20% 500 10% Figure 3 — Comparison of Gross Fluid rote for Unit S and Historical values for all vxe||s at Milne Point K- pad.Vert|ca|bars|ndicate"estinnated"veriation|nthehistorica|data. Page 4of5 i Supplemental Data for AOGCC 12 -02 -08 450000 - - -- - — - - - -- -- - - - -- -- - -- - - - -- - - - 50% 400000 _ - _ -- 45% 350000 - - - - -- 40% 35% 300000 - ------------------ - - - - -- -- ®BHP — CHANGE t ® Hz % Change EM Amps %Change 30°A 250000 -- - -- - - - -- — Historic Gas Rate' i I -- Unit 5 Gas Rate l 25% j 200000 I 20% 150000 15 °k 100000 10% I `'0000 5% Oil 0 0% MPK -02 MPK -05 MPK-06 MPK-09 MPK -13 MPK -13 MPK -17 MPK -17 MPK -30 MPK -30 MPK -37 MPK -37 MPK -38 MPK-38 Figure 4 — Comparison of Gas rate for Unit 5 and Historical values for all wells at Milne Point K -pad. Vertical bars indicate "estimated" variation in the historical data. Page 5 of 5 420 Additional Data for our Weatherford G2.0 Application to the AOGCC Page 1 of 1 Dolombie Jody J DOA From: Williamson, Mary J (DOA) Sent: Monday, October 20, 2008 11:32 AM To: Colombie, Jody J (DOA) Subject: FW: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Attachments: Gen 2 0 field trial summary data for Jane 091108.xls; Prudhoe Wet gas Meter Test for Jane 091108.ppt Please place this e-mail and attachments in the file for the Gen 2 application. From: Brady, Jerry L [mailto:Jerry.Brady @bp.com] Sent: Thursday, September 11, 2008 2:18 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane, As a follow up to our meeting yesterday, we are sending you the following data for inclusion as part of our Weatherford Gen 2.0 application. 1. Excel table of the Gen 2.0 and Unit #1 well test results. 2) Data to support our capability to measure liquid rates at the very high gas volume fraction. I have included a power point with 4 slides that provides you with information on a test of the sonar and V- cone in the gravity drainage area of Prudhoe Bay. We hope this along with discussions yesterday help to address your questions. The enclosed can be considered as a part of our submission and used to supplement the report. Please contact me if you have any questions or comments on this data. Best regards, Jerry <<Gen 2 0 field trial summary data for Jane 091108.xls>> <<Prudhoe Wet gas Meter Test for Jane 091108.ppt>> 10/24/2008 Li uid Rate Gas Rate Watercut Temp at Pressure at overate Flowrate Flowrate Flowrate GOR @ GVF at Oil Oil Temp at Pressure at Test Unit 1 Unit 1 Gen 2.0 Unit 1 Gen 2.0 Unit 1 Gen 2.0 Unit 1 Unit 1 Unit 1 Density Viscosity Reynolds Gen 2.0 Gen 2.0 Well Date deg F psig bpd bpd Mscf d Mscf d % % scf /stb % kg/m3 cp Number deg F psig Comments V -02 1/31/20083:00 82.8 280.8 801.0 776.2 1663.2 16696 32.7% 386% 2151 94.85 868.3 10.8 6162 88.2 349.8 V -03 2/3/2008 14:00 86.0 311.1 676.7 7730 19908 2023.9 45.5% 41.5% 2618 95.14 876.9 8.0 7260 91.4 410.7 V -04 1/28/200815:00 101.0 296.4 1458.2 1387.2 15996 1749.9 38.0% 327% 1261 91.21 845.9 5.6 18756 106.9 398.7 V -101 2/5/2008 21:00 105.4 380.2 2239.6 22240 24906 2337.8 96.3% 916% 1051 87.36 893.1 1.2 124463 107.8 510.8 V -102 1/291200811:00 100.1 281.8 1701.5 18334 1764.1 1844.3 86.5% 70.2% 1006 89.76 884.8 2.6 51569 103.5 427.0 V -103 1/31/200816:00 82.1 334.6 1130.7 1190.1 1360.6 1432.9 69.3% 610% 1204 88.53 895.7 11.3 9549 83.9 421.0 V -106 -8 1/30/200813:00 103.5 306.7 1744.4 18274 1588.0 15451 94.7% 834% 846 87.26 897.4 1.4 89665 107.0 407.3 V -108 2/412008 4:00 69.1 318.2 1001.1 8854 1484.7 13702 54.7% 57.3% 1548 91.40 901.2 129 7161 73.4 407.1 V- 111 2/4/2008 18:00 58.4 2878 639.8 602.3 1583.3 1466.1 7.2% 12.2% 2434 94.88 905.4 36.3 1496 591 347.6 V-1 13-6 1/27/2008 12 00 65.9 284.7 813.0 755.7 1888.2 1958.9 54.6% 52.6% 2592 95.13 898.0 20.6 3438 66.5 387.2 V -122 2/5/2008 8:00 109.1 3533 3031.0 3172.2 2664.9 25812 61.6% 59.3% 814 84.69 875.7 3.7 60767 113.9 556.4 V -202 2/1/2008 5:00 553 2984 14869 1573.0 2062.4 2498.4 2.0% 10.3% 1588 9207 925.3 82.6 1338 55.9 442.8 • V -203 -A 1/28/2008 200 534 306.2 1749.6 1806.1 3382.7 3469.8 0.0% 25% 1921 92.81 926.8 72.2 1949 52.3 488.8 V -203 -B 2/2/200812:00 50.2 311.8 1501.4 1669.8 3169.8 3070.5 0.0% 24% 1839 92.32 927.7 64.4 1924 50.2 487.4 V -204 2/12008 20:00 48.4 308.5 683.4 977.0 3436.9 3205.9 35.8% 22.2% 3281 95.71 937.3 192.1 412 51.4 4275 Lost heat during test resulting in bad test data V -205 2/312008 1.00 38.3 319.3 1 328.1 383 0 1 2796.1 2772.7 1 0.0% 0.6% 1 7240 97.95 953.7 653.1 68.3 38.6 4505 b• Wet Gas Meter Testing @ Prudhoe, • Uses the same basic technology as Gen 2.0 S — Sonar and pressure differential gas measurement meter • This test used sonar and V -cone • Gen 2.0 uses sonar encapsulated venturi — Gen 2.0 superior to sonar and V -cone » Encapsulated venturi allows for greater turn -down ratio » Provides reliable sonar data at lower velocities •• Well wet gas meter test vs. pad 0,4 se arator gas rate 50 • 45 ±5% 40 N 35 30 i L 3 25 0 20 Q � 15 U 10 5 0 0 5 10 15 20 25 30 35 40 45 50 Test separator gas flowrate (MMscf /d) 0 0 V -Cone + CiDRA liquid flowrate (stb /d) N 4�1 O 00 O N • ' O O O O O O O O O O O O O , O O C ° fD (D (D Q 3 o � g O =- N - n O O , r ` A Er C \ ` ' lD O D a ` • y \ y o < . D ' CD c< Z: _ a� �* O 3 m ' J CD \ a \ \ FF CD O ` \ O O , C� �— a -_ O < O\ N n \ N (D y 0 y co '< v m � cD CD ° :3 i U1 c U' U2 a d A 3 CD O m 5� 3 Q O ° O O O N _ O O I •• Well wet gas meter test vs. pad s eparator • 100000 90000 ±5000 _ 80000 70000 o ' N ' v 60000 V -cone transmitter 0 suspected out of Q 50000 range U 40000 a� o 30000 U 20000 10000 0 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 Test separator GOR (scf /bbl) Request for AOGCC to approve Gen meters on DS -01 and Victor pad Page 1 of 1 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, October 20, 2008 11:32 AM To: Colombie, Jody J (DOA) Subject: FW: Request for AOGCC to approve Gen 2.0 meters on DS -01 and Victor pad Another e -mail for Gen 2 application. From: Brady, Jerry L [mailto:Jerry.Brady @bp.com] Sent: Thursday, October 09, 2008 1:43 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Request for AOGCC to approve Gen 2.0 meters on DS -01 and Victor pad Jane, As we discussed on the phone, BP would like to begin design work to install the Weatherford Gen 2.0 multi -phase flow meters at several pads for well testing and allocation. However, we do not want to proceed with this work until we have state approval. You have suggested that the AOGCC would likely approve application at specific pads as you continue to work the overall approval to use the meter across the North Slope. Again for clarity, BP is only asking to use the meter in areas that are similar to the wells that we tested at Victor and Echo pads. These meters will be used as a replacement of current well testing kit. The first two pads we have currently targeted at Prudhoe Bay are DS -01 and Victor pads. We would like AOGCC approval to install Gen 2 at these two pads in the next few days. This action would allow you to proceed with overall approval of our original Gen 2 application and prevent us from loosing any time on the deployment of these meters. Remember that BP is looking at a phased in approach with these meters and the sooner we can get them installed the quicker we will have more data to base the rest of our deployment on. Thanks! Jerry 10/24/2008 Additional Data for our Weatherford Gg 2.0 Application to the AOGCC Page 1 of 5 • r Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, October 20, 2008 11:34 AM To: Colombie, Jody J (DOA) Subject: FW: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC last e-mail for Gen 2 application. From: Hall, Andrew (ABZ) [mailto:andrew.hall @uk.bp.com] Sent: Monday, October 13, 2008 2:43 AM To: Williamson, Mary 3 (DOA) Subject: RE: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane I apologise for using confusing notation. We tested wells V -106A, V -113 and V -203 twice each during the field test. The first test of V -106 we did not get Unit 1 and Unit 5 data because of some operational issues with Unit 5. They bypassed the units to keep warm fluids flowing through the test skid and I requested a repeat of the well test on the next shift. I labeled the second test V- 106 -8. I did not use the first test. The first test of V -113 was abandoned mid way through due to a plant trip. Again I requested a repeat of the well test on the next shift, numbered the new test V -1 13 -B. There was not enough data in the first test to be useful. V -203 was tested twice, on different days, just because there are only 4 orion wells and we thought it useful to get more tests, and I labeled these V -203 -A and V- 203 -B. 1 did not ask for tests on V -107 or V -109 just from time constraints and because we had already tested more of the Borealis wells than the other formations. Also I recall to bring V -101 on line - which I thought was interesting because of its high water cut - we had to cut back on some of the other wells. Regards Andrew. From: Williamson, Mary 3 (DOA) [mailto :jane.williamson @alaska.gov] Sent: 12 October 2008 03:21 To: Hall, Andrew (ABZ) Subject: RE: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Andrew, In going through the data you sent, in the collumn named Well you have tests shown for V- 203 -A, and V- 203 -B. Are these 2 separate tests for the V -203 Well? The well name in our records is V -203. Also in the Well collumn of your data sheets you note V- 106 -B, V- 113 -B. Our files show the names V -106A and V -113 Respectively. Following are the Oil Producers we have filed in our database (excludes laterals of motherbore) with API # and Permit Number noted. V -01, V -07, V -115, V117 were not producing during the test period. Did you attempt tests on V -107 and V -109? They were producing at the time but no tests are noted. 10/24/2008 Additional Data for our Weatherford G2.0 Application to the AOGCC Page 2 of 5 • PI WELL # PTD # Well Name Pool Formation Status Dt. Test Gen 2? Producing 1/26/08-2/5/08? 50- 029 - 23210 -00 -00 2040900 -01 Prudhoe Bay Oil Pool Sadlerochit 11- Jul -04 No No 50- 029 - 23209 -00 -00 2040770 -02 Prudhoe Bay Oil Pool Sadlerochit 18- Jun -04 Yes Yes 50- 029 - 23124 -00 -00 2022150 -03 Prudhoe Bay Oil Pool Sadlerochit 31- Dec -02 Yes Yes 50- 029 - 23322 -00 -00 2061340 -04 Prudhoe Bay Oil Pool Sadlerochit 01- Dec -06 es Yes 50- 029 - 23372 -00 -00 2071410 -07 Prudhoe Bay Oil Pool Sadlerochit 10- Dec -07 No No 50- 029 - 23074 -00 -00 2020560 -101 Borealis Oil Pool Kuparuk 04 -May- es Yes 50- 029 - 23070 -00 -00 2020330 -102 Borealis Oil Pool Kuparuk 23- Jun -02 Yes Yes 50- 029 - 23117 -00 -00 2021860 -103 Borealis Oil Pool Kuparuk 07- Jan -03 Yes Yes 50- 029 - 23083 -01 -00 2041850 -106A Borealis Oil Pool Kuparuk 30- Oct -04 Yes Yes 50- 029 - 23108 -00 -00 2021550 -107 Borealis Oil Pool Kuparuk 28- Dec -02 No Yes 50- 029 - 23112 -00 -00 2021660 -108 Borealis Oil Pool Kuparuk 5- Nov -02 Yes Yes 50- 029 - 23120 -00 -00 2022020 -109 Borealis Oil Pool Kuparuk 12- Nov -02 No Yes 50- 029 - 23161 -00 -00 2031030 -111 Borealis Oil Pool Kuparuk 15- Aug -03 Yes Yes 50- 029 - 23125 -00 -00 2022160 -113 Borealis Oil Pool Kuparuk 18- Feb -03 Yes Yes 50- 029 - 23195 -00 -00 2040270 -115 Borealis Oil Pool Kuparuk 04- Apr -04 No No 50- 029 - 23156 -00 -00 2030900 -117 Borealis Oil Pool Kuparuk 01- Jul -03 No No 50- 029 - 23328 -00 -00 2061470 -122 Borealis Oil Pool Kuparuk 05- Jan -07 Yes Yes 50- 029 - 23153 -00 -00 2030770 V -202 Orion Oil Pool Schrader Bluff 03 -May es Yes 50- 029 - 23285 -00 -00 2051680 V -203 Orion Oil Pool Schrader Bluff 16- Feb -06 Yes Yes 50- 029 - 23217 -00 -00 2041310 V -204 Orion Oil Pool Schrader Bluff 01- Sep -04 es Yes 50- 029 - 23338 -00 -00 2061800 V -205 Orion Oil Pool Schrader Bluff 18- Feb -07 Yes Yes From: Brady, Jerry L [mailto:Jerry.Brady @bp.com] Sent: Thursday, October 09, 2008 1:35 PM To: Williamson, Mary J (DOA) Cc: Hall, Andrew (ABZ); Parviz Mehdizadeh; Pospisil, Gordon Subject: FW: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane, Below is Andrew's answers to your questions. I am in hopes that this will help speed our application along. It would be very helpful to us to have approval by the end of the month. Thanks! Jerry Answers to Jane's questions 1. 1 used a Reynolds number calculated from Re - 4 * total mass flowrate / (pi * liquid viscosity * nozzle i.d.) So Re is based on total mass flowrate and liquid viscosity. I have not used the effect of free gas on mixture viscosity. The fluid in contact with the pipe walls is liquid; frictional loss which leads to the reduction in discharge coefficient is a function of flowrate and the fluid properties in contact with the pipe. We got good consistency between field results based on this Reynolds number and the laboratory calibration of the meter in oil. 10/24/2008 Additional Data for our Weatherford G 2.0 Application to the AOGCC Page 3 of 5 0 • 2. 1.used liquid viscosity (and PVT) calculated by SLB. They sampled the fluids and measured density and dead oil viscosity for each test. SLB's reported liquid viscosity then takes into account temperature, gas dissolution ('live' oil viscosity) and water cut effects. Temperature effect is a straightforward log viscosity vs 1/1' relationship; live oil viscosity is calculated from a live oil viscosity correlation, and water cut effect is an emulsion viscosity correlation. I don't know what correlations SLB are using but we could do a similar calculation. This wil I be done for the field Gen 2.0. Note that we are calculating viscosity and hence Reynolds every 1 minute during the 8 -hour test. The values I quoted are an average over the whole test. Actually this is quite an important point, because even in the low Reynolds number tests, we might see a substantially larger Reynolds number during a liquid slug (when the mass [ lowrate is higher) than the average for the test, so there is probably less sensitivity of the mass flowrate to the discharge coefficient - Reynolds number curve than you might think. 3. Water shakeouts were collected every 1 hour during most of the tests, by Unit 1, Unit 5 and SLB. Normally it is 1/2 hour but we reduced the sample frequency to avoid FI2S issues in the Unit 5 operating area. 8 samples is not really enough for a good statistical average. however, normally these samples agreed well between the three locations. Exceptions were V -03 and V -103 where individual shakeout samples could vary from 5% to 70% water cut due to the unstable nature of these wells. Table 15.2: Statistioal analysis of manual sample water cuts Ihiil 1 . m xw.xal cw�dan � 1,InU � . n.+rna.M �nnq'Ms Schlr.daeryni , maer+rral c.� �r. � 'li�3 b.•.aap+ aBry ... <x.f t Hurt +pr zlJnv 9i', rxnl I s,w <aa. �Ihxv 'K'. +'nrt 19\ 3936 ::.,y`_..._....._.. ij;...._{ V 07 'i €k I e ; �',:: t :1:76':S. l5'a !.h'•. rl:r s, 1S"w !r " - -. E VAN I :.' >.1 7G 0!. •: IIiI , 733 ti:n e t! .S di I!h. 71 >~•�: ?: ?S 'i .lt'� �F. '°a ':7` =. ;.' I ;1?' r 7 S.S': F." 7 71 :+ ' 1.183 ; � y ,. 79% 55'?: I i.'9'. 4e 3.:. 5: 5;a 19% V-111 t501 `9.. '. tt. }: t:: Vk 14% ;3 tr`. 32 t V117 li5k; . 4.95: .thlJ«, 3',.'. 'i •Itt `... +G'ti 0; 3., t Y" V 11if i74 to "t. ^;P?4 711.7'C: 14 J, "4ti 11, ^ 5, IQ'ti tiF:*S, 'i A If, VAl IN ' ^ti :a. `::; � t74y,. pf, ^2, t:1ti I irA 95N 5 Note: these are hand samples and this data is not metering for Unit 1, Unit 5 or Schlumberger. 4. see Excel attachment If you need a phone call 1 suggest about Ipm Alaska / l Opm UK one day. Thursday would work. Mad a good discussion with Mike Mullally and Gordon Stobie on the phone yesterday. DSI will need to use a wet gas model for most of the wells. Andrew. From: Williamson, Mary J (DOA) [mailto:jane.williamson @alaska.gov] Sent: 08 October 2008 05:06 To: Brady, Jerry L; Hall, Andrew (ABZ) Cc: Parviz Mehdizadeh Subject: RE: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jerry and Andrew, I'm still working on the review of the V -Pad test comparison. Sorry it's taking me so long - lots of things on my plate. I'm trying to do a thorough job reviewing, recognizing that this would be the first "certification" we've done for any MPFM system. It would be 10/24/2008 Additional Data for our Weatherford G 2.0 Application to the AOGCC Page 4 of 5 • helpful to get a few more pieces of information. 1) 1 would like to see how Reynolds number was calculated. 2) Were total fluid viscosities measured (not just the oil - combined emulsion)? If so what are they? 3) Were shakeouts /fluid samples collected to determine water cut? How do these compare? 4) Would it be possible to provide the V pad separator tests that correspond to the Unit 1 and Gen 2 tests? I need to be able to explain differences in oil rates inferred from the measurements of the Unit 1 vs Gen 2. While I know that Parviz believes comparisons should be done for fluid and gas rates, not oil rates, in the end - oil is the "pay" fluid and we have to address this. I'm not as concerned when there are no or little differences in ownership and royalties (PBU), these factors could come into play for some of the fields /pools you've applied for. So far, I'm seeing the largest oil rate differences with the higher water cuts, mainly in the Borealis (Kuparuk). This might be explained by the different methods for water cut measurements, entrained gas in the fluid leg of Unit 1, correlation differences, differences in operating pressures at the 2 units, and PVT correlations. I thought I'd see bigger differences at high viscosity, lower reynolds number - but I'm seeing just the opposite. Perhaps that's taken care of with the correlations. I've spoken a bit with Parviz about it, but I would like to speak by phone with Andrew. It would be best if we could set up a specific time for Andrew to call. Jerry, I'm not so concerned with the oil rate questions for the Prudhoe Bay drillsite applications we discussed by phone today - V pad and DS 1. If you need approval from the AOGCC in a hurry for those applications, I think I can do that. Again, with no differences in ownership /royalties /tax treatment - it's a matter of what's ok for reservoir management, and I'm comfortable. You may require separate approval from DOG for Orion (maybe also Boreallis) PAs, but I don't think this will be a big deal. This blanket approval you've requested is more difficult, though. Jane .Jane 'WiCfiamson, 1 AOGCC Senior Reservoir Engineer (907) 793 -1226 From: Brady, Jerry L [mailto:Jerry.Brady @bp.com] Sent: Thursday, September 11, 2008 2:18 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane, As a follow up to our meeting yesterday, we are sending you the following data for inclusion as part of our Weatherford Gen 2.0 application. 1. Excel table of the Gen 2.0 and Unit #1 well test results. 2) Data to support our capability to measure liquid rates at the very high gas volume fraction. I have included a power point with 4 slides that provides you with information on a test of the sonar and V- cone in the gravity drainage area of Prudhoe Bay. We hope this along with discussions yesterday help to address your questions. The enclosed can be considered as a part of our submission and used to supplement the report. Please contact me if you have any questions or comments on this data. 10/24/2008 Additional Data for our Weatherford 2.0 Application to the AOGCC Page 5 of 5 Be't regards, Jerry <<Gen 2 0 field trial summary data for Jane 091108.xls>> <<Prudhoe Wet gas Meter Test for Jane 091108.ppt>> 10/24/2008 Request for AOGCC to approve Gen meters on DS -01 and Victor pad Page 1 of 2 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Thursday, October 09, 2008 2:47 PM To: Brady, Jerry L Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh; Taylor, Cammy 0 (DNR); Davidson, Temple (DNR) Subject: RE: Request for AOGCC to approve Gen 2.0 meters on DS -01 and Victor pad Jerry, I'll proceed with the order for early deployment at DS -1 and V -Pad, and I may be able to get orders for all PBU pools at the same time, or shortly thereafter. It would be nice if you could send a letter under Gordon's signature reiterating your request. A phased approach is reasonable. I would also prefer such a phased approach for long term approval for the remainder BP operated areas. Similar to your remark below, additional data would provide for a more solid framework for AOGCC approvals from a technical and legal standpoint and would provide a good basis for future orders. I believe such an approach would help you in the long term and could actually save you time. I perceive relatively small risk to the ownership interests within PBU and I believe the employment would aid overall reservoir monitoring and management. That said, you should probably speak with Temple Davidson (269 -8784) and /or Cammy Taylor (274 -7691) to make sure you receive any DOG approvals that may be required. You may need specific approval for Orion (maybe Borealis ?) for V -Pad. I'm not sure in the case of DS -1 or other PBU pools. I'm cc'g them on this e-mail. As I've expressed in the past, I think the progress you've made here is very exciting and I can see a lot of potential in existing and future developments. Jane From: Brady, Jerry L [mailto:Jerry.Brady @bp.com] Sent: Thursday, October 09, 2008 1:43 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Request for AOGCC to approve Gen 2.0 meters on DS -01 and Victor pad Jane, As we discussed on the phone, BP would like to begin design work to install the Weatherford Gen 2.0 multi -phase flow meters at several pads for well testing and allocation. However, we do not want to proceed with this work until we have state approval. You have suggested that the AOGCC would likely approve application at specific pads as you continue to work the overall approval to use the meter across the North Slope. Again for clarity, BP is only asking to use the meter in areas that are similar to the wells that we tested at Victor and Echo pads. These meters will be used as a replacement of current well testing kit. The first two pads we have currently targeted at Prudhoe Bay are DS -01 and Victor pads. We would like AOGCC approval to install Gen 2 at would these two pads in the next few days. This action w ou allow y ou to proceed with overall approval of our original Gen 2 application and prevent us from loosing any time on the deployment of these meters. Remember that BP is looking at a phased in approach with these meters and the sooner we can get them installed the quicker we will have more 10/15/2008 Request for AOGCC to approve Gen20meters on DS -01 and Victor pad Page 2 of 2 data to base the rest of our deployment on. Thanks! Jerry 10/15/2008 Additional Data for our Weatherford .0 Application to the AOCiCC: Page 1 012 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Thursday, September 11, 2008 3:31 PM To: Lusher, James A; Davidson, Temple (DNR) Cc: Maunder, Thomas E (DOA); Roby, David S (DOA); Brady, Jerry L Subject: FW: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Attachments: Gen 2 0 field trial summary data for Jane 091108.xls; Prudhoe Wet gas Meter Test for Jane 091108.ppt Jim and Temple, Torn and I met with Jerry Brady, Gordon Pospisil and Parviz Mehdizadeh yesterday concerning some questions we had in regards to BPXA's July 8 application to the Commission for use of the Gen 2 multiphase flow meter system for well tesing and production allocation in currently established BPXA operated pools. I requested an excel version of the individual well tests of the Gen2 vs. the Unit 1 portable test separator, with fluid properties /operating conditions noted. For wet gas application, they also sent the attached ppt file. Jerry indicated that these items can be placed in the public record. Jerry is anxious to get the Gen 2 AOGCC approval to help them ensure continued funding in progessing the field application of this technology. For the AOGCC record in this determination, I would appreciate a letter, preferably by Wed Sep. 17, as to whether your respective agencies have any objection or specific concerns which the Commission should consider in finalizing an order concerning the use of the Gen2 metering system in properties where you have a royalty share. Note that BPXA is not requesting, at this time, that the Gen 2 system be used as a replacement to "Lact Meters" for custody transfer. If you wish to contact Jerry, his work phone is 564 -5291, and cell is 440 -8465. Jai ' I wiffiia isoi1, PE AOGCC Senior Reservoir Engineer (907) 793 -1226 From: Brady, Jerry L [mailto:Jerry.Brady @bp.com] Sent: Thursday, September 11, 2008 2:18 PM To: Williamson, Mary J (DOA) Cc: Pospisil, Gordon; Hall, Andrew (ABZ); Parviz Mehdizadeh Subject: Additional Data for our Weatherford Gen 2.0 Application to the AOGCC Jane, As a follow up to our meeting yesterday, we are sending you the following data for inclusion as part of our Weatherford Gen 2.0 application. 1. Excel table of the Gen 2.0 and Unit #1 well test results. 2) Data to support our capability to measure liquid rates at the very high gas volume fraction. I have included a power point with 4 slides that provides you with information on a test of the sonar and V- cone in the gravity drainage area of Prudhoe Bay. We hope this along with discussions yesterday help to address your questions. The enclosed can be considered as a part of our submission and used to supplement the report. Please contact me if you have 9/16/2008 Additional Data for our Weatherford C 2.0 Application to the AOGCC Page 2 of 2 any questions or comments on this data. Best regards, Jerry <<Gen 2 0 field trial summary data for Jane 091108.xls>> <<Prudhoe Wet gas Meter Test for Jane 091108.ppt>> 9/16/2008 Li uid Rate Gas Rate Watercut Temp at Pressure at lowrate Flowrate F owrate Flowrate GOR @ GVF at Oil Oil Temp at Pressure at Test Unit 1 Unit 1 Gen 2.0 Unit 1 Gen 2.0 Unit 1 Gen 2.0 Unit 1 Unit 1 Unit 1 Density Viscosity Reynolds Gen 2.0 Gen 2.0 Well Date deg F Psig bpd bpd Mscf d Mscf d % % scf /stb % kg /m3 cp Number deg F psig Comments V -02 1/31 /2008 100 828 2808 801.0 776.2 1663.2 16696 32.7% 38.6% 2151 9485 868.3 10.6 6162 88.2 3498 V -03 2/3/2008 14:00 860 311 1 676.7 773.0 19908 2023.9 45.5% 41.5% 2618 9514 8769 80 7260 91.4 4107 V -04 1/28/2008 15 00 101.0 2964 1458.2 1387.2 15996 17499 38.0% 32.7% 1261 91.21 845.9 56 18756 1069 398.7 V -101 2/5/2008 21.00 1054 380.2 22396 22240 2490.6 23378 96.3% 91.6% 1051 87.36 893.1 12 124463 107.8 510.8 V -102 1/29/200811:00 1001 2818 1701.5 1833.4 17641 1844.3 86.5% 70.2% 1006 89.76 884.8 2.6 51569 1015 427.0 V -103 1/31/2008 16:00 821 3346 11307 1190.1 13606 14329 69.3% 61.0% 1204 88.53 8951 11.3 9549 839 4210 V -106 -8 1/30/2008 1300 1035 3067 1744.4 1827.4 15880 15451 947% 834% 846 8726 897.4 1.4 89665 107.0 407.3 V -108 2/4/2008 4:00 691 3182 1001 1 885.4 1484.7 13702 54.7% 573% 1548 91.40 901 2 129 7161 73.4 4071 V -111 2/4/2008 18:00 584 287.8 639.8 6023 1583.3 14661 7.2% 12.2% 2434 9488 9054 363 1496 59.2 3476 V -113 -8 1/27/2008 12:00 659 2847 8130 7557 18882 1958.9 54.6% 52.6% 2592 95.13 898.0 206 3438 665 387.2 V -122 2/5/2008 8'00 109.1 3533 3031.0 3172.2 26649 2581.2 61.6% 59.3% 814 84.69 8757 3.7 60767 1139 556.4 V -202 2/1/2008 500 55.3 298.4 14869 1573.0 20624 2498.4 20% 10.3% 1588 9207 925.3 82.6 1338 55.9 4428 V -203 -A 1/28/2008 2:00 534 306.2 1749.6 18061 33817 3469.8 00% 2.5% 1921 92.61 9268 72.2 1949 523 488.8 V -203 -B 2/2/2008 12.00 50.2 3118 1501.4 1669.8 3169.8 3070.5 0.0% 2.4% 1839 9232 9277 644 1924 502 487.4 V -204 2/1/2008 20:00 48.4 3085 683.4 977.0 34369 3205.9 35.8% 22.2% 3281 95.71 9373 192.1 412 514 4275 Lost heat dunng test resulting in bad test data V -205 2/3/2008 1.00 38.3 3193 1 328.1 383 0 1 2796.1 27727 1 0.0% 06% 1 7240 9795 953.7 6531 68.3 38.6 4505 �t • Uses the same basic technology as Gen 2.0 — Sonar and pressure differential gas measurement meter • This test used sonar and V -cone • Gen 2.0 uses sonar encapsulated venturi — Gen 2.0 superior to sonar and V -cone » Encapsulated venturi allows for greater turn -down ratio » Provides reliable sonar data at lower velocities i i O 0 .\ o LO LO ® to M ^ CC G 4a a.+ L 0 N H 1 •, e� Q � O 1 ► C N N LO ~ LO \ O 0 1 (p /13SWW) OW"011 Se6 VHMO ao ' .n o Afth a Ah .f ON 40 • • 1 W 0 1 V 1200 p 1000 / +r N v +% All these points 3 800 within ±10% - O O - O . � 600 Cr unreliable/ low liquid Q rate from test separator O V -cone transmitter U 400 ' - -- O suspected out of + O range j 200 -- V -cone transmitter Liquid rate verified 0 certainly out of with ASRC Unit 1 range 0 0 200 400 600 800 1000 1200 Test separator liquid flowrate (stb /d) Ah 100000 77 90000 - ±5000 80000 70000 0 0 O 60000 V-cone transmitter suspected out of range ange tx 40000 0 30000 U > 20000 10000 0 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 Test separator GOR (scf/bbi) Page 1 of 1 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Friday, August 08, 2008 11:39 AM To: Brady, Jerry L, Parviz Mehdizadeh; Hall, Andrew (ABZ) Cc: Maunder, Thomas E (DOA); Roby, David S (DOA) Subject: Draft comments on July 8 Gen2 application Attachments: BPMPM.doc Jerry, Andrew, Parviz, I went through the Gen 2 application and I'm providing some comments, though you should consider this as draft now, and there may be other comments forthcoming from Tom. As I've said before, the development of this device is quite exciting. The Gen2 still seems to be in a prototype stage, but it appears to be a great step forward. At this time, I'm not convinced that an open -ended approval in all properties, especially where there are differences in royalty, is appropriate. I do believe there are many places where the design will improve well testing for reservoir management - as you've shown for V pad. You indicated you're not sure where you will be putting these meters at this time. Maybe just 4 or so a year. You have a few places in mind but not a full plan in place. Perhaps we could discuss a mechanism of approval at this time, for the purposes of enhancement of well testing accuracy of existing separators, with a later notification of installation when your inhouse or WIO approvals are, and define criteria for when further approval is needed (getting input from DNR and MMS as appropriate- not sure why DOR would care unless there is a between unit and facilities sharing issue.) We'll need updates on how the meters are performing, and interpretation - is the meter working as it should, has it improved allocation, any operating problems, etc? Something much less time consuming than the report you've worked on - more like a permit form or a 2 -3 page summary. I found both the Pioneer Oooguruk and your application a bit difficult to ensure required documentation is fully addressed as outlined in the Commissions Guidelines for Qualification of Multiphase Metering Systems for Well Testing" (see http://www.state.ak.us/local/akpages/ADMIN/ogc/MeterGuide.shtml ). The attached questions are related to sub - sections of these Guidelines. It would be helpful if you could go through these questions and answer them. Just send back by e -mail. It's not necessary to redo the application. Also, can you provide me with an electronic copy of the slides after our Monday meeting? Jane Williamson AOGCC Senior Reservoir Engineer, PE (907) 793 -1226 9/16/2008 J . AOGCC /MV Draft Comments - Jul 8, 2008 Gen f1pplication Y Sections noted from Commission "Guidelines for Qualification of Multiphase Metering Systems 11/04/04 3.1.1 Proposed locations and timing of the meters: BP has requested approval for well test allocation in all properties operated by BP. We are concerned about providing blanket approval without more information on the proposed locations and timing of installation over the next few years and knowledge of what conditions this meter will be placed in. Please verify further. 3.1.2 Appendix 1 A: Point McIntyre is produced into LPC as well as GC 1. 3.1.3 Appendix 1 A: ELF no longer applies. Make sure the royalties are correct. 3.1.4 Statement that all working interest owners, royalty owners (including Alaska Department of Natural Resources, and Mineral Management Services), Alaska Department of Revenue. This is further verified by the planned meeting. 3.1.5 Complete. 3.1.6 Complete for V -Pad, but what about other potential areas? 3.1.7 Complete for V -Pad, but what about other potential areas? 3.1.8 Please provide a statement of expected accuracy over set of operating /fluid properties conditions. (a) Your main report shows uncertainties in comparison to the ASRC Unit 1 and V pad Separator. An additional appendix would be helpful which outlines the verification of the ASRC Unit 1. Also, what sorts of "corrections" and "algorithms" were required (any due to viscosity, Reynolds number, other). (b) The report on loop testing suggests that improvements are still needed and that this is in the prototype stage. Have I interpreted this correctly? (c) You are requesting a blanket approval through all properties and conditions. It appears you are claiming this can be used through full range of GVF, water cut, viscosity, flow regime — is that correct? a. The V pad separator results appear favorable — in fact much improved over the Loop tests. Why? Loop tests suggest "accuracy better than 20% at GVF below 80 % ", and slugging flows cause difficulties, especially above 80% GVF. "Additional work is required to improve the multiphase and especially sonar performance in unsteady flow conditions." (d) For reservoir management, there may be no problem with a +/- 20% accuracy at very high GVF's, but we need to make sure that your expectations are quite clear. If there are fiscal allocation effects, you will need to get into more detail as to the effects of the uncertainties. (e) Did you see any indication of bias? For instance in Figure 11 of the flow loop test. Would this suggest some bias of liquid flow rate over various Lockhart Martinelli numbers? 3.1.8.1 The Guidelines require review of accuracy to be stated for all phases. (a) I can't find anything stating or shown for oil rate accuracy. 3.1.8.2 Accuracy measurements Table 3 are relative to Unit 1. Again provide oil. 3.1.8.3 Loop test confidence was +/- 95% confidence. Same for Field tests? 3.1.9 No change in allocation methodology. I believe that is true, but as other installations besides V pad are installed, you should verify within existing conservation orders and perhaps consider if allocation technique /discussion needs AOGCC /MJW Draft Comments Page I of 2 8 -8 -08 AOGCC/M Draft Comments - July 8, 2008 Gen pplication Sections noted from Commission "Guidelines for Qualification of Multiphase Metering Systems 11/04/04 update. For V pad, allocation is in accordance with Prudhoe Bay Unit Western Operating Metering Plan. 3.1.10 Contingency plan addressed for places where a test separator exists. 3.1.11 & 3.1.12 Perhaps a bit skimpy discussion on long term quality assurance and accuracy. See attached Pioneer for Vx meter. (a) Particularly, measurements of fluid properties (density at operating conditions), Composition of gas, Salinity of water (still not totally understanding the verification that salinity does not affect red -eye), viscosity of oil at operating conditions, viscosity of oil -water emulsion. This should be done for each well, not just by pool. 3.2 Relaxation of accuracy criteria. Thoughts for discussion, consideration. (a) Used solely for well testing for reservoir management? As in the improvement at V pad. No ELF, differences in Royalty (b) Will need to discuss with DNR, MMS for areas where royalty interests differ and whether other approvals will be required. i. Maybe limit requests for replacement /improvement of existin test separator systems? ii. Find some method of notification that installation planned? iii. Consider using uncertainty analysis looking at affect of more frequent well testing as compared with less accuracy for those areas where royalty is a concern. 4.0 Validation of Meter performance in Field — Excellent field testing! a few comments 4.1 Some discussion of the calibration of the Unit 1 should be included. 4.3 Reporting Field Results. 4.3.1 Review of oil accuracy in accordance with 4.3.1 (a) How does fluid viscosity affect the results? Could you discuss how /whether Reynolds number corrections required? Any other properties that are important? 4.3.3 Individual well test results in tabular form needed compared to the Unit 1 and V pad Separator. (a) For each well tested provide fluid properties including Gas, Oil, Water Density, Oil API, fluid viscosity. Can Lockhart Martinelli values be provided for the wet gas? (b) How are gas lift values figured in? How good are the meters for gas lift? Impact meter results? (c) Need PVT properties to get to standard conditions. Again, how is gas lift included? (d) Were any other tests performed, tank tests, other? AOGCC /MJW Draft Comments Page 2 of 2 8 -8 -08 Page 1 of 3 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Thursday, July 17, 2008 1:12 PM To: Brady, Jerry L Cc: Roby, David S (DOA); Maunder, Thomas E (DOA); Birnbaum, Alan J (LAW); Taylor, Cammy 0 (DNR); Colombie, Jody J (DOA) Subject: RE: 070808 BP Cover Letter Jerry, Yes, I can see that BPs prior request for Unit 5 also requested under 20 AAC 25.228 and 11 AAC 83.371. Take a look at the public notice AOGCC put out in 2007 for the Unit 5 proposal. If you can't find the earlier notice in your files, David may be able to find it for you. The whole question here is what are you wanting to apply for at this time. The Commission has authority for the state to approve /require standards for well test equipment and allocation methodology per 20 AAC 25.230. It's a new ball game if the MPMs are being proposed instead of LACT meters between units, such as the Pioneer /KRU and Liberty /Endicott plans. If seeking "fiscal allocation" methods to replace LACT unit requirements, you would need approval from the Commission to waive requirements of 20 AAC 25.228, plus DNR and likely DOR will be very involved in this (and MMS for Northstar, and Liberty.) Alan Birnbaum is our attorney for the Commission and perhaps he can help you further. Cammy Taylor, Unit Manager at DNR has experience on this from Commission and DNR standpoint, and I think she would be of great help to you. I am cc'g both on this. If it can all wait till I get back, that might be best. Monday is ok with me. I'm outa here till July 30. Later Jane From: Brady, Jerry L [mailto:Jerry.Brady @bp.com] Sent: Thu 7/17/2008 8:19 AM To: Williamson, Mary J (DOA) Subject: RE: 070808 BP Cover Letter Thanks Jane! I will check on this. I am somewhat confused though. These are the same numbers we used last time. Were they also incorrect? Another topic, Andrew is not available on Friday. I will see if Monday can work. Jerry From: Williamson, Mary J (DOA) [mailto :jane.williamson @alaska.gov] Sent: Wednesday, July 16, 2008 8:50 PM To: Brady, Jerry L Cc: Pospisil, Gordon; Seamount, Dan T (DOA); Colombie, Jody J (DOA); Birnbaum, Alan J (LAW); Foerster, 7/18/2008 Page 2 of 3 w Catherine P (DOA); Norman, John K (DOA); Roby, David S (DOA); Maunder, Thomas E (DOA); Kline, Carol; Colombie, Jody J (DOA) Subject: RE: 070808 BP Cover Letter Jerry, Thank you for the exciting overview of the Gen2 today. Excellent technical work. I reviewed the cover letter of the application again and I noticed a few things that you need to review with Gordon to make sure it is correct. It was my understanding that you are solely requesting use of this Gen 2 MPFM device for well testing and for use in production allocation within existing BP operated properties. • Your letter states you are requesting approval under 11 AAC 83.371 which is not under AOGCC authority. This is within DNR - Kevin Banks group. I would see if Cammy Taylor cammy.taylor @alaska.gov at 269- 8817 can help you concerning this. I don't believe this regulation applies. • You also mention 20 AAC 25.228 - This doesn't apply unless you are requesting use in custody transfer applications. We would not be able to approve this without opportunity for hearing, and I'm fairly certain a hearing would be held if you do have this in mind. • If you are only requesting approval to use the GEN2 to enhance current test separation for existing pools, the Commission has the authority to approve under 20 AAC 25.230(a) and the Conservation Orders noted in your letter. • You should change the title of CO 547 to include all oil pools within the Prudhoe Bay Field, with the exception of Put River Oil Pool, Raven Oil Pool. • Your slides suggested you have a few specific projects in mind, but you stated you want to move toward full scale use of this technology. My preference would be a more measured, pilot approach, and I suggest you think about this, and specifically indicate where these will be used, say in the next 2 years or so. If you could limit the scope to what you will be getting to in the next 2 years, then I expect administrative approval wouldn't be a big deal. Of course we can notice for hearing in the larger scale and just see if there are comments /objections. I know you are in a hurry, but after considering this further, I need to take more time to collect comments from everyone and get our attorney to weigh in on the handling of your request. And, unfortunately, everyone is swamped with more pressing items at the moment. Therefor, I'll work on this when I get back. I will be on vacation from July 17 to July 29. It is really important to get this right from a legal standpoint. In the meantime, I suggest you work to set up a technical meeting with MMS (who will have their own requirements), DNR, and DOR. I believe your technical contact at MMS is Ja mes. Lush er @MMS _go_v_. At DNR, Cammy will ensure it is coordinated. I'm afraid I have no idea who at DOR would be involved or if they need to be involved. I'm not sure if Dudley is the technical guy any more. I suggest you contact Jon Iversen, 269- 6620, Jonathon. Iversen @alaska.gov for a SPOC. I really think your technical work is very exciting and I do think this should be shared with them. If you have further questions, Dave Roby may be able to help at 793 -1232. Jane WiCfiamson, P2: AOGCC Senior Reservoir Engineer (907) 793 -1226 From: Williamson, Mary J (DOA) Sent: Tuesday, July 15, 2008 12:41 PM To: 'Kline, Carol'; 'Brady, Jerry L' Cc: Pospisil, Gordon; Seamount, Dan T (DOA); Colombie, Jody J (DOA); Birnbaum, Alan J (LAW); Foerster, 7/18/2008 I r Page 3 of 3 Catherine P (DOA); Norman, John K (DOA); Roby, David S (DOA); Maunder, Thomas E (DOA) Subject: FW: 070808 BP Cover Letter Carol and Jerry, It appears that this is your official application for approval to use the Gen 2 Multiphase Meter System, which will require amendment to 7 Conservation Orders. If so, we request 10 hard copies of the signed cover letter and application, one for each conservation order file, and 3 for Commissioners and Staff. You've requested amendment of CO 551 for Northstar. MMS is a royalty owner there and you therefor need to add to your cc list Jeff Walker, Regional Supervisor of Field Operations, Mineral Management Service Alaska Field Office - 3801 Centerpoint Drive, Suite 500, Anchorage AK 99503. After we receive the hard copy of the application, the Commission will determine whether they wish to act upon these requests administratively or notice the applications for public hearing. Jane 1Nillia.mson, PE AOGCC Senior Reservoir Engineer (907) 793 -1226 From: Kline, Carol [mailto: Carol. Kline @BP.com] Sent: Monday, July 14, 2008 5:31 PM To: Williamson, Mary J (DOA); Seamount, Dan T (DOA) Subject: 070808 BP Cover Letter Dan Jane It appears that the zipped file of the complete Application Report for Weatherford Generation 2.0 Multiphase Metering System was too large and bounced back to me. The only difference between the one sent last week and today is the signature on the cover letter. Attached is the cover letter for your file. Do you require a hard copy? Please let me know. I'm happy to bring one to you, if necessary. carol kline Office: (907) 564.4744 Cell: (907) 223.9494 email: carol I 7/18/2008 419 4 e Sarah Palin, Governor 0 ❑ State Office building PO Box 110420 Juneau, AK 99811 -0420 DEPARTMENT OF REVENUE 907.465.2320 91 550 W 7th Ave Suite 500 Tax Division Anchorage, AK 99501 -3555 907.269.6620 www. tax. state. ak. us October 7, 2008 Hand Delivered Daniel T. Seamount, Jr. Chair Alaska Oil & Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, AK 99501-3539 - Re: Application by BP Exploration (Alaska) Inc. (BP) to the Alaska Oil and Gas Conservation Commission for use of the Weatherford Generation 2.0 Multiphase Metering System in the Prudhoe Bay, Endicott, Milne Point, Northstar, Put River, Raven, and Badami Oil Pools. Dear Chair Seamount: You have requested that the Department of Revenue, Tax Division (DOR) provide the Alaska Oil & Gas Conservation Commission ( AOGCC) with a letter of no objection regarding AOGCC's authority to approve or deny BP's application for the use of the Weatherford Generation 2.0 Multiphase Metering System for well testing and production allocation within BPXA operations conducted in the Prudhoe Bay, Endicott, Milne Point, Northstar, Put River, Raven and Badami Oil Pools. DOR has no objection to BP's use of the Weatherford Generation 2.0 Multiphase Metering System as an alternative to conventional gravity based test separators for well testing and production allocation within the oil pools referenced in paragraph 1, above. This conceptual approval is limited to the facts as presented and does not constitute consent for use or approval of multiphase meters for production allocation between units or any other purposes. In BP's AOGCC "Application Report" for the Weatherford Gen 2 Multiphase Metering S, s� tern (Application Report), BP stated that it would inform the DOR about the use of the metering system "when the application of the metering system affects such interests ". However, DOR requests to be notified of any changes in BP Application for Weatherford Generation 2.0 Multiphase Metering System October 7, 2008 Page 2 the use of the metering system. Given the significant role that oil and gas production, including metering measurements and allocations of production and costs have on state revenues, and in light of DOR's regulatory responsibilities, the department feels it is necessary and appropriate for BP and the AOGCC to keep DOR informed of any changes in use or approval of BP's measurement systems. Given the evolving nature of this technology, DOR believes it would also benefit from being concurrently updated in any changes in use of the meters, regardless of whether BP believes use or application of the meters affects DOR's interests. DOR very much appreciates AOGCC's ongoing efforts to keep the department informed and updated regarding the use and application of multiphase meters as they continue to be used and implemented in Alaska production operations. If you have any questions, please contact John Larsen at (907) 269 -8436, or in his absence, Lennie Dees at (907) 269 -6624. Sincerely, Jon than Iversen Director cc by email: Kevin Banks, DNR Cammy Taylor, DNR Temple Davidson, DNR Jack Hartz, DNR Marcia Davis, DOR John Larsen, DOR Lennie Dees, DOR Gordon Pospisil, BPXA Jerry Brady, BPXA �1$ a SARAH PALlN, GOVERNOR DEPARTMENT OF NATURAL RESOURCES 550 WEST 7 T " AVENUE, SUITE 800 ANCHORAGE, ALASKA 99501 -3560 DIVISION OF OIL &. GAS PHONE.' (907) 269 -8800 FAX (907) 269 -8938 Hand Delivered. October 3, 2008 Daniel T. Seamount, Jr. Chair Alaska Oil and Gas Conservation Conunission 333 W. 7"' Avenue, Suite 100 Anchorage, Alaska 99501 -3539 Re: Request by BP Exploration (Alaska) Inc. (BPXA) to the Alaska Oil and Gas Conservation Commission for approval to use multiphase measurement devices for well testing and production allocation within BPXA operations conducted in the Prudhoe Bay Field All Pools, Endicott Oil Pool, Milne Point Oil Pool, Northstar Oil Pool, Put River Oil Pool, Raven Oil Pool, and Badami Oil Pool pursuant to I 1 AAC 83.371, 20 AAC 25.228, and 20 AAC 25.230. Dear Chair Seamount: The Alaska Oil and Gas Conservation Commission (Commission) has requested a letter fiom the Department of Natural Resources, Division of Oil and Gas (Division), stating whether the Division objects to any request in the application of BPXA for the use of multiphase measurement devices, and if so, the reasons for each objection. BPXA has requested approval from the Commission to use Weatherford Generation 2.0 Multiphase Metering System devices for well testing and production allocation within BPXA operations conducted in die Prudhoe Bay Field All Pools, Endicott Oil Pool, Milne Point Oil Pool, Northstar Oil Pool, Put River Oil Pool, Raven Oil Pool, and Badaini Oil Pool. The Division conceptually agrees with the request. The Division defers to the Commission's teclunical expertise in crafting the specific conditions for the requested approvals. The Division also has no objection to the Commission granting an interim, conditional, or temporary approval to allow use of these meters by BPXA. "Develop, Conserve, and Enhance Natural Resources f or Present and Future Alaskaiis. " A16C BPXA Weatherford Gen 2.0 10/3/08 Page 2 of 2 However, as BPXA has not yet finalized plans for the timing and installation of the meters, the Division does not yet know which participating areas may receive the meters and how those meters will be installed and implemented. When BPXA has decided where to install the meters, and how they will implement them for well testing and production allocation, BPXA must request concurrence and approval from the Division as required by participating area formation decisions � pl q and 11 AAC 83.371. If you have any questions please contact Temple Davidson with the Division at 907- 269 -8784. Sincerely, ,rt Kevin R. Banks Acting Director cc by e -mail: Jonathan Iversen, DOR Jolun Larsen, DOR Temple Davidson, DOG Jack Hartz, DOG Gordon Pospisil, BPXA Jerry Brady, BPXA I I x$17 a Si r OT OR Ty • T4 ,��eHT or 'M United States Department of the Interior v P S ZP 4 Y MINERALS MANAGEMENT SERVICE sb � CH 33 �a' Alaska Outer Continental Shelf Region ��NAGEIM�' 3801 Centerpoint Drive, Suite 500 Anchorage, Alaska 99503 -5823 SEP 3 0 2008 Mr. Dan Seamount, Jr. - Chairman Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Seamount: The MMS is submitting the below comments on the BPXA July 8, 2008 request to AOGCC for authorization to use a multi -phase measurement device for the purpose of well testing and production allocation within selected BPXA- operated North Slope oil pools. The MMS appreciates the AOGCC invitation to the MMS to submit comments in recognition that the request includes the Northstar pool which is co- managed by the MMS and State. The MMS also wants to thank Jane Williamson for her efforts to include the MMS in discussions and information exchange on the BPXA request. The MMS generally supports BPXA's proposal. The MMS concurs with BPXA that approval of the request will allow BPXA to further demonstrate that multi -phase metering technology can provide allocation well tests comparable to a conventional test separator. With this goal in mind, the MMS provides the following comments. • Any application of these meters for measurement of oil/gas from the Northstar oil pool will also require approval separately from MMS (per 30 CFR Part 250.1202 Liquid Hydrocarbon Measurement). • The MMS suggests BPXA clarify, or the AOGCC confirm, the intended purpose to use multi -phase meters for "production allocation." Among different regulatory authorities, "production allocation" has different regulatory and legal connotations. The MMS understands that in the context of this application, BPXA is not proposing multi -phase meters as a replacement to LACT Meters for custody transfer. It's not clear if BPXA is proposing to use this multi -phase meter system to allocate production among commingled production facilities. • The MMS encourages the AOGCC to define or require BPXA to develop a quality assurance program by which these meter systems are evaluated for accuracy and reliability and that this information be submitted to the AOGCC on a reasonable schedule. TA KE INAMERMA- I� �r " 2 ® The application (page 3 of 11, Section 2) states that "In the event the proposed multiphase metering scheme does not produce the expected accuracy, we will revert to use conventional well testing techniques." The "expected accuracy" and exception criteria that would trigger reverting to conventional well testing techniques should be defined. • The application (page 10 of 11, Section 6) lists a proposed schedule for field maintenance and periodic calibration. The MMS encourages AOGCC to adopt a schedule under which BPXA would demonstrate and verify that this is an appropriate maintenance and calibration schedule and what changes should be considered for different fluid flow or other operational conditions. The MMS appreciates the AOGCC for including us in your review process. This technology has important applications for the OCS and for future development opportunities in the State. If you have questions, p cont act Mr. Jim Lusher at (907) 334 -5300. Sincerely, Je alker Re 'o al Supervisor Field Operations cc: Jane Williamson, AOGCC Jerry Brady, BPXA 416 rage i or i r Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, November 03, 2008 4:02 PM To: Colombie, Jody J (DOA) Subject: Concerning comments from DOR, DOG and MMS on BPXA Gen 2 application Attachments: Williamson, Mary J (DOA).vcf; Comments concerning BP's application for the use of the Weatherford Gen 2 MPFM system Jody, We received letters directed to Chairman Seamount from each agency providing comments related to the Gen 2, and you were asking whether a letter went out from the Commission requesting input from DOR, DOG and MMS concerning the BPXA Gen 2 application. BPXA gave a technical overview for all the agencies concerning the Gen 2 on August 11. BPXA's application was global (for all BPXA properties) and the DOG has royalty interests in the properties, MMS has royalty interests at Northstar. Because the agencies have their own requirements (royalty and tax accounting, etc), I individually asked the representatives to provide us with input regarding whether they have objections or comments regarding BPXA's application for our records. This was a verbal request. I do have an a -mail I sent to an MMS representative which I'm attaching, but I'm afraid I don't have any written documentation that I requested input from the other agencies. Jane 'WiCCiamson, PE AOGCC Senior Reservoir Engineer (907) 793 -1226 11/4/2008 Yage 1 of 1 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, August 25, 2008 5:31 PM To: Lusher, James A Subject: Comments concerning BP's application for the use of the Weatherford Gen 2 MPFM system Jim, As we discussed, by phone today, I would appreciate your thoughts or concerns related to BP's application for the use of the Weatherford Gen 2 MPFM system for use in well test allocation for the Northstar Unit. We had discussed that certain requirements for meter verification over time be included in any order (periodic meter verification tests, requirements for sampling, reporting requirements, etc). If you have specific criteria you would suggest, I would appreciate your input. Jane Williamson AOGCC Senior Reservoir Engineer, PE (907) 793 -1226 11/4/2008 #15 • ! (7i) Au- SARAH PAULA GOVERNOR ALA H 01% AND CIA 333 W. 7th AVENUE, SUITE 100 CONSMRQATION CO1r USSI0N ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 March 20, 2007 Mr. John Denis ACT East Performance Unit Leader BP Exploration (Alaska) Inc. 900 East Benson Blvd. P.O. Box 196612 Anchorage, AK 99519 -6612 RE: Conservation Order 402B - Badami Dear Mr. Denis: Attached please find Conservation Order 402B, revising previously approved pool rules for the Badami field development. This order is the product of the Commission's public notice and hearing to clarify safety valve system requirements. The public hearing was convened February 22, 2007. The Commission has amended CO 402A by including Rule 6 addressing the installation, operation and testing of safety valve systems for Badami production and injection wells. As requested, BP Exploration (Alaska) Inc. (`BPXA ") is authorized to perform a phased installation of subsurface safety valves at Badami to be completed by October 1, 2007. During the hearing, representatives of BPXA offered testimony consistent with February 20, 2007 written comments from Mr. John Garing (BPXA Alaska Consolidated Team, East Production Team Leader), addressing the operational status and challenges associated with the installation of subsurface safety valves in Badami wells. The phased installation of subsurface safety valves will provide BPXA time to optimize the functionality of these devices during the warmer months of the North Slope summer. rel , J K. N an Ch ' , GCC Attachment Cc: John Garing, ACT East Production Team Leader BP Exploration (Alaska) Inc. 900 East Benson Blvd. P.O. Box 196612 Anchorage, AK 99519 -6612 Inspectors �14 [Fwd: Badami Stabilization Information] I s 0 Subject: [Fwd: Badami Stabilization Information] From: James Regg <jim_regg @admin.state.ak.us> Date: Wed, 07 Mar 2007 15:22:20 -0900 To: Jody Colombie < jody _colombie @admin.state.ak.us> BP provided this info in response to request during Badami hearing jim -- - - - - -- Original Message -- - - - - -- Subject: Badami Stabilization Information Date: Wed, 07 Mar 2007 13:50:22 -0900 From: Younger, Robert O <Robert.Young @bp.com To: James Regg <jim regg @admin.state.ak.us> CC: Garing, John D <John.Gar.ing @BP.com > , Rossberg, R Steven < @BP.com > Engel, Harry R <Harry.Enge1 @BP.com > Bill, Michael L (Natchiq) <Michae @BP.com > Kirchner, Carolyn J <Carclyn.Kirchner @BP.com > END /BAD Area Manager <ENDBADAreaManager @BP.com >, Robinson, Bruce W <RobinsBW @BP.com > Barnes, Thomas J <ThoFuaa .Barnes @BP.ccm > , BAD, Operations Lead Tech <_B AD O perationsLeadTec @BP. > BAD, AES Supervisor <BADAESSupervisor @BP.com > Buckendorf, Randal < Randal.Buckend o rf @BP.com> Jim, Please see the attached PowerPoint highlighting Badami Stabilization information. • A 5 to 7 day window should be sufficient to allow for any stabilization or logistical issues that may arise • May need to revisit timing as Badami experience dictates «Badami Stabilization Information.ZlP>> Please let me know if you need any additional information. Thanks! Bob *Robert Younger* BP Exploration, Alaska Northstar /Badami Production Engineer 907 - 564 -5392 (Work) 907 - 677 -2599 (Home) 907 - 830 -4920 (Cell) yo urger2 @bp corn Jim Regg < jim regg(a,)admin. state. ak.us Petroleum Engineer AOGCC Badami Stabilization Information.ZIP Content -Type: application/x- zip- compressed Content - Encoding: base64 1 of 1 3/7/2007 3:53 PM Badami Stabilization Information Slide Format for Each Well • Production Information • Extended Pressure* &Temperature Trend � •Magnified Pressure* &Temperature Trend * No Pressure Data Available for B1 -15 rn boom o U 6 a a s aa8 — �o- - ---- - - - - -- -� --------- -------- -- - - - -- - -- - - - - -- - - - - -- { - -- - - - - - - - - - - - - - - - - - -- - - - r o T __ r __ __ f_1_1_ ----------- ------- _ _ ____ _____.____ _ --- - - - - -- - - -- r a. u I - ---- - - - - -- � -- -j- ----------- - - - - -Ir !�� w - _ _____ ___ _________ _ ________ _T__T____ -T ________________..{____ �y Y I I J •1 ___ __ __ __ __ _ _ _ _____ __ __________ _________ -- -- - - - --- - - - - -' -- - - - - -- _,__ - - - i O - - - - -- - - - -- ;_ __________ _fit _ - _L_1_ ----------- _ ________ _ 1 ___ __ ___- ______! « - - -- --�+�- '. 3 - - - ---------- +--- -- -- * x' - -- -- -- - - - - 44 '- ------ ------ - -' --- O y� - - - - - - - - - - - - - - - - - -- J - - - - - - - - - - - - - - - - F o ;- - --- -- - -- - - -- - -- - ', --- - - ---- ---- - -� � - o'r- I__T__r__ ----- r _ T _ T _ ______. ____ - -__.. __ _}_______ _ _____ _}_r__T__ HOT - ------ ----- -- # -- -- -- - - _ __ --- ___ ---- „ ... 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O OD N O O O O O N O OD O O O O 0 O O 0 • N A O) OD O N A O Oo O O O O O O O O O O 12/01106:00 12/01/06:12 cn =]7 ��► 12/03/06:16 e-t 1 12/04/06:04 ..,� CD C CD D v = D p 12/04/06:16 �CC N � G T m D r 00 N 12/05/06:04 co W N 0) 2 ( N � N 12/05/06:16 i 12/06/06:04 12/06/06:16 O n> w p cn rn v OD 0 0 0 o O o 0 0 -~13 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: John K. Norman, Chairman Daniel T. Seamount Cathy Foerster In the Matter of the Rules Governing ) Safety Valve System Requirements ) pursuant to Section 20 AAC 25.265 (c) ) pertaining to the Badami Field on ) the North Slope of Alaska ) ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska February 22, 2007 9:00 o'clock a.m. VOLUME I PUBLIC HEARING BEFORE: John K. Norman, Chairman Daniel T. Seamount, Commissioner Cathy Foerster, Commissioner R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 TABLE OF CONTENTS Opening remarks by Chairman Norman Testimony by Harry Engel R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 03 10 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 P R O C E E D I N G S Tape 1 0050 (On record - 9:00 a.m.) CHAIRMAN NORMAN: Good morning. I would like to call this hearing to order. This is a hearing being held before the Alaska Oil and Gas Conservation Commission. The time is 9:00 o'clock a.m. on the morning of Thursday, February 22nd. Present with me to my right is Commissioner Dan Seamount. To my left Commissioner Cathy Foerster and my name is John Norman. The three Commissioners being present we do have a quorum to proceed. I'll first indicate that if there are any persons present who have special needs that might need to be accommodated in order to participate in this meeting indicate to us and we will do our best to accommodate you in accordance with the requirements of the American with Disabilities Act. R & R Court Reporting will be preparing a transcript of these proceedings and following the proceedings any persons wishing a copy of the transcript may obtain one. I want to remind persons when you testify, of course, you'll need to come forward and there are two microphones in front of you and sometimes that's a bit confusing. One is for amplification within the room and the other one is for the convenience and transmitting to the Court Reporter so you will R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 3 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 need to speak into both microphones. The purpose of the hearing this morning is to proceed with the hearing initiated by the Commission on its own motion to clarifying safety value system requirements for the Badami Field on the North Slope of Alaska. The hearing specifically is governed by Section 20 AAC 25.265 (c) of the Alaska Administrative Code and I will briefly read that just as background. That section states; the Commission will in its discretion require an SSV system and SSSV system or both on a well with an onshore surface location after notice and an opportunity for hearing in accordance with the rules applicable to hearings before this Commission. A request for hearing was filed by BP on February 2nd and consequently we will proceed with this hearing this morning. I will ask Commissioner Foerster to at this point address specifically the subject and indicate how she would like to proceed? COMMISSIONER FOERSTER: Thank you, John. I would like for our petroleum engineer, Jim Regg -- our senior petroleum engineer, Jim Regg to give a brief description of what this safety valve system rule entails and then we can proceed with any comments that BP or others have. CHAIRMAN NORMAN: Mr. Regg, even though you're well known to the Commission we'll have to ask you to fully identify R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 1 2 3 4 5 6 7 8 9 10 11 12 13 14 j 15 !I 16 '~, 17 18 19 20 21j 22 23 24 25 yourself for the record. MR. REGG: Okay. My name is James Regg. I'm a senior petroleum engineer here with the Oil and Gas Commission. I have 24 years experience working both in Alaska and the Gulf of Mexico in oil and gas operations mostly evaluating technical issues that effect regulatory decisions and effect the oil and gas industry. Graduate of Penn State University in 1983 with a degree in Petroleum and Natural Gas Engineering and a concurrent degree with the Edinboro State University in Math and Sciences. This morning what I would like to do is just give you an overview of the safety valve systems rules that we've proposed for Badami. This is a Staff recommendation that has been noticed and answer any questions that you may have on that. 20 AAC 25.265 as you have entered into the record here, gives the Commission the discretion to require surface safety valves systems or safety valve systems on a well with an onshore location after noticing opportunity for a Public Hearing. Safety value systems are required for offshore facilities. All North Slope fields have safety -- some form of safety valve system requirement. Most currently require only a surface safety valve and a low pressure syst- -- low pressure pilot system. The subsurface safety valve requirements are in several R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 fields including the Alpine field Endicott, Northstar, a few pads at Prudhoe and Kuparuk and then also at the Niakuk location. Conservation 402 and Conservation Order 402A are silent on safety valve system requirements and that's normally the mechanism the Commission has used in the past to require safety valve systems for onshore facilities. Conservation Order 402 was developed for early spacing requirements at the Badami location to give BP the opportunity to gain some production experience and the record shows that BP had intended to come back to the Commission at some point later to seek additional rules governing completion and production practices. Conservation Order 402A waived the GOR requirements for limitations at Badami and was -- still remains silent on safety valve system requirements. It's my understanding that the Badami wells are equipped with actuated surface safety valves. The proposed rule that we have noticed would require all completed wells except water source wells, disposal injection wells and monitoring wells to have a fail safe, actuated surface safety value. Would also require a low pressure sensor or low pressure transmitter and a fail safe subsurface safety value in those wells that would demonstrate -- that could not be demonstrated as a no flow candidate (ph). R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 6 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 i 25 We would require testing every six months consistent with our normal practice on other safety valve systems throughout the state and reporting of those test results would be required within 14 days to the Commission. The question might be asked why safety valve system requirements now. Simply we're looking for consistency with other North Slope operations, the other North Slope fields, particularly those that are similarly positioned along the coastline. We're looking for clarity in safety valve system requirements, to establish performance expectat-ions and also establish a basis for us doing inspections. With that I'll be happy to answer any questions you might have or I can just turn it over to BP. COMMISSIONER FOERSTER: I have one -- I have one question for you, Mr. Regg. How does this proposed rule compare with the blanket safety valve system rules that we're planning on rewriting and proposing? MR. REGG: Yeah, the Commission has been working on a complete rewrite of the safety valve system requirements. This was an extraction of that. With some tailoring the -- maybe the noticeable difference is the regulations that are being proposed and that -- and consistent with what we have now requires a surface controlled subsurface safety valve. And we purposely in this rule have opened that up to all types of subsurface valves, surface controlled or subsurface controlled. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 7 1 2 3 4, 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 'I 22 23 24 25 COMMISSIONER FOERSTER: So when the new rules go into place will they supersede this rule or will this rule supersede them? MR. REGG: The regulations -- our intent would be that the regulations would supersede these unless there's some unique aspects that are required at Badami which, of course, we would explore here today. COMMISSIONER FOERSTER: Thank you, Mr. Regg. CHAIRMAN NORMAN: Commissioner Seamount? COMMISSIONER SEAMOUNT: I have none. Thank you, Mr. Regg. CHAIRMAN NORMAN: Mr. Regg, just a clarification for my understanding. The wells at Badami currently, I think you said, have actuated, surface safety valves and then later you indicated the proposed rule would require fail safe, actuated, surface safety vales, is there -- could you explain the distinction there for me, please? MR. REGG: There was no intended confusion there, I just dropped the fail safe. It should be -- it has to be fail safe, actuated, surface safety valve. CHAIRMAN NORMAN: Thank you very much. And we would ask that you remain in the hearing room in case we would need to recall you. MR. REGG: Thank you. CHAIRMAN NORMAN: Mr. Engel, is there representatives of BP now that wish to proceed? R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 8 1 2 3 41 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. ENGEL: Yes. CHAIRMAN NORMAN: Please come forward then. For each of you I will indicate again to the need to speak into both microphones which is confusing. And will expert testimony be presented by all of you, the three of you? MR. ENGEL: Well, Commissioner, I will be doing the testifying this morning, but I will have my colleagues, Mr. Barnes and Mr. Younger be available if they are needed for additional assistance. CHAIRMAN NORMAN: Very well. Maybe it would be efficient then for me to swear all three of you right now and we will get that out of the way and then Mr. Barnes and Mr. Miller (sic) can indicate for the record their names and so forth, but I -- we have in front of us Mr. Engel,..... COMMISSIONER FOERSTER: Mr. Younger. CHAIRMAN NORMAN: Younger, I'm sorry, Mr. Younger, I apologize and Mr. Barnes. And will the three of you, please, raise your right hand. (Oath Administered) MR. ENGEL: Yes, I do. MR. YOUNGER: Yes. MR. BARNES: I do. CHAIRMAN NORMAN: Good. The record should reflect that all three witnesses have sworn or affirmed. Mr. Engel, then if you would state your name, position and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 9 l 2' 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 experience, credentials for the record, please? TESTIMONY BY HARRY ENGEL MR. ENGEL: Yes. Good morning, Commissioners. My name is Harry Engel. I am currently the engineering team leader responsible for integrity and management in BP's Alaska drilling and wells organization. My responsibilities span all of BP's drilling wells operations in Alaska. I hold undergraduate degrees in Civil and Environmental Engineering and have over 26 years experience in the oil and gas industry primarily associated with drilling and wells activities. My assignments have included drilling and engineering assignments in Alaska and the Rocky Mountains, in China and Indonesia. I've also had various roles as a well site leader and health, safety and environmental management positions within BP. And I would also like to make a note that my current responsibility includes compliance with AOGCC regulations for BP Alaska drilling and wells. CHAIRMAN NORMAN: Very well. Without objection then the Chair will accept your credentials as an expert. Please proceed. MR. ENGEL: Commissioners, yesterday BP submitted some written comments and I wanted to ask if you received those comments yesterday? R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 10 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 COMMISSIONER FOERSTER: Yes, we did. MR. ENGEL: Great. Have you had a chance to look at those comments? COMMISSIONER FOERSTER: Yes, we did. MR. ENGEL: Okay. What I want to do this morning is go through those comments briefly and address the issues around Badami related to the proposed Rule 6 for Conservation Order 402. The comments we provided will be related to the background of the Badami field, it's current status, the safety valve system currently in place in Badami, paraffin issues affecting the wells and the potential operational impacts associated with the addition of subsurface safety valves at Badami. Today with me, as I mentioned earlier we have Mr. T. J. Barnes who is the area manager for Badami who is very familiar with the operations on site and also Mr. Bob Younger, a petroleum engineer with BP who works at the Badami field. Now, I'll get into some background on the Badami field historically. Badami is an onshore development field located approximately 40 miles east of Prudhoe Bay. The facility, which is one pad, is located on a single pad near the Beaufort Sea. The field is not connected with any roads to the main North Slope infrastructure and year round access is limited to air or roll-a-gon access with barge support as needed during the winter months. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 11 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We support the equipment in the field with people and crews that arrive in from Deadhorse when well work is needed in the field. The Badami field was discovered in 1990 and production began in August of 1998. The production was peaked at 17,000 barrels per day in August and it declined rapidly to about 5,000 barrels per day in December of that same year. In May of 2003 the field was placed in a warm shutdown status due to its low production rate. In June of 2005 the Department of Natural Resources approved BP's sixth plan of development and the field was restarted at that time. Badami is presently a marginal economic field due to low producing rates and the high cost of supporting this field in such a remote operation. Consistent with our current plan of development with the Department of Natural Resources BP will continue to review the potential for further warm shutdown periods to allow for reservoir recharge and also evaluation of the field and its economic status. Any questions related to the history of Badami before I go on? CHAIRMAN NORMAN: I don't believe there are. MR. ENGEL: Okay. The field right now has 10 wells in the field and the approximate production rate is 1,100 barrels of oil per day and 1.5 million cubic feet of gas per day with minimal water production. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 12 1 2 3 4 5 6 7 8 9 10 11 12 13' 14 15 16 17 18 19 20 21 22 23 24 25 I We have four wells currently producing that are on line with rates between 30 and 400 barrels of oil per day. Flowing tubing pressure in these wells range between 160 and 200 psi. We have one high gas to oil ratio well that is currently shut- in due to a compressor that is currently not on line at Badami. We have one low producer due to production and is currently shut-in. We have two producers with downhole mechanical issues that are shut-in and secured. We have one gas injector that is on-line and one Class I/Class II disposal well that is on-line. That well is a dual permitted well both Class I and Class II. A comment about the wells that are producing, we believe that most of these wells could flow to surface unassisted. However, we don't feel that these wells could flow in the facility due to the pressure in the flow line which is about 150 psi. The Badami wells were originally designed for production rates much higher than we are currently experiencing. And the wells are equipped with four and a half inch tubing which results in quite low velocities in the tubing. Two wells currently operate with gas lift operations. All wells at Badami are equipped with automatic surface safety valves. The wells are also equipped with hydraulic, actuated wing valves as part of our safety system at Badami. The actuated wing valves are actuated by the same low pressure R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 13 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 switch as the surface safety valve providing a redundant protection mechanism. Six of the wells currently producing at Badami have control lines to a downhole mandrel in our tubing string that's located about 2,000 feet and this mandrel allows for us to install a subsurface safety valve in the mandrel that's controlled by the surface control lines. The remaining three producers and the gas injection well are equipped with a profile nip (ph) tubing string at about 2,200 feet and this allows for the installation of a downhole valve that is run and pulled by wireline, not having to pull the tubing from the well to install that valve. The gas injection well is currently equipped and operating with a subsurface injection valve that is set in the profile in the tubing string and functioning. The condition of the control lines I mentioned in the three producers and the mandrel is unknown at this time because it has never been operated. As I'll get into a little later here, these wells operate with some paraffin deposition and there may be some issues with these control lines that may have been affected by the deposition of paraffin or wax in the well. Consequently it is possible that all the wells at Badami, piercing wells that is, may require K-valves and that will -- would require additional well work to equip the well with R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 14 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 functioning subsurface valves. I'll talk more about K-valves in a moment to let you know what that valve is and how they function. At Badami there are several unique circumstances that may affect the installation and operation of subsurface safety valve in our wells. Paraffin or wax deposition is one. And paraffin deposition at the field has been a major operational concern for the wells and the pipeline. Due to the wells low producing rates, low pressures and low temperatures four of the producing wells have required periodic downhole paraffin removal operations in the past. We call these operations to remove paraffin brush and flush operations. And basically we go in the well with a slick line tool and some hot oil and basically brush and clean out the deposited paraffin in the well to remove it from the wellbore. And paraffin deposition can occur down to about 4,000 feet at Badami. The frequency of these clean out jobs has been between five and six weeks in a couple of wells and can be as great at six months in the other two wells. As I mentioned earlier the subsurface valves, the profile for these valves are set at about 2,200 feet and would be located in the paraffin deposition zone in our tubing string. And that paraffin deposition could hinder the operation of these valves and the potential consequence of paraffin in a tubing string would inhibit the valve from functioning as R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 15 ',~; 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 designed thereby not giving us confidence that the valve would operate and function if needed. K-valves have been used on the North Slope for many years as an alternative to surface controlled, subsurface valves because these valves do not have a control line from the surface that operates the functionality of the valve itself. Basically a K-valve is run into the well on a slick line tool and it sits in the profile in a tubing string. And basically the K-valve closes when a predetermined pressure above the tubing string falls to a certain point thereby closing the valve and prohibiting flow coming up the valve -- up the tubing string. With this type of a design flowing conditions within a wellbore must be accurately known to select the correct combination of spring and dome pressure to allow the valve to function properly. Wellbore conditions in the well -- in a well prone to paraffin depositions may constantly change that environment in the tubing string. Based on our experience in high paraffin environments K-valves will be difficult to maintain and operate in several wells at Badami. At a minimum, K-valves in high paraffin wells will likely require increased well intervention and well downtime to maintain the reliability of those valves. As I mentioned in our letter considering this factor with paraffin and K-valves we believe a staged approach would be R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 16 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 appropriate to allow us enough time to look at the performance of a well or a valve in a well and then determine the proper. setting temperatures and so forth for the subsequent valves. Oil produced from Badami is exported through a single 25 mile, 12 inch pipeline to a connection point at the Badami -- pardon me, at the Endicott common carrier pipeline. Currently the Badami sales line is operating near the lower end of its operating range due to the low productivity of the field in its current status. It is possible that the additional downtime associated with the installation, maintenance and operation of subsurface valves at Badami, this may result in occasions where the total rate in the pipeline itself would not be adequate to allow the field to operate and keep that pipeline full and moving. Current crude oil temperatures at the point of connecting to the Endicott line near zero degrees fahrenheit and shutting down the pipeline in cold weather increases the risk of pipeline plugging and this consideration supports a summer installation campaign that would help reduce the risk of pipeline plugging. Considering the unknown facts or impacts we've talked about with the operation of K-valves in a high paraffin producing wells, coupled with the potential risks of pipeline operations, we believe the optimum time to install and test the functionality of subsurface values at Badami would be in the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 17 1 2 3 4, 5', 6 7 8 I 9'~, 10 11 12 ''' 13 14 15 16 17 18 19 20 21 22 23 24 25 warmer months of the year. Therefore, we would request a period until October 1st, 2007 to complete the phased installation of subsurface valves at Badami. And should we get into any significant operational issues during this process with things like paraffin we would notify the AOGCC and propose alternatives at that time. Before -- or after we address any questions that the Commission may have this morning I would like to make two specific comments about the proposed rule after we deal with any questions that you may have for us. At this time I'd be happy to address any questions that you may have. CHAIRMAN NORMAN: Very well, thank you. Commissioner Seamount? COMMISSIONER SEAMOUNT: I have a couple of questions, Mr. Engel and I hope the don't sound too dumb coming from a geologist, but one of my daughters is an engineer so there may be something genetic there to where I may understand your answer, okay? COMMISSIONER FOERSTER: Speak slowly and loudly. COMMISSIONER SEAMOUNT: Why do they call it a K-valve? MR. ENGEL: I couldn't tell you. Anybody know that answer? MR. BARNES: Yeah. MR. ENGEL: Okay, T. J. will help me out with that. MR. BARNES: Yeah, it's a -- it was a term proposed by -- R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 18 ~.~ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 '' 17 I 18 19 20 21 22 23 24 25 I think by Otis Engineering. It was either Otis or Camco (ph). It was a brand designation of the valve that they used in that application. It's a valve that has a nitrogen dome charge on it and their brand for the particular valve was K-valve and it stuck industry wide. COMMISSIONER SEAMOUNT: So it doesn't look like a K? MR. BARNES: No. COMMISSIONER SEAMOUNT: Okay. CHAIRMAN NORMAN: And could you please identify yourself for the record, too? MR. BARNES: My name is T. J. Barnes, B-a-r-n-e-s. I'm with BPXA, have been for coming up just on 30 years and oddly enough I'm a geologist by original training as well. I'm currently the Endicott/Badami area manager on the Slope responsible for production operations at Endicott and Badami. COMMISSIONER SEAMOUNT: It's good to know a geologist can understand this stuff, at least one. The next question, on the brush and flush..... MR. ENGEL: Yes. COMMISSIONER SEAMOUNT: .....is there actually a brush on the end of the tool? MR. ENGEL: Yes, there is. COMMISSIONER SEAMOUNT: And does it expand and contract as you go down or is it just -- just fits the tubing? MR. ENGEL: I think the analogy I would have to that, R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 19 1 21' 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Commissioner Seamount, would be a chimney brush. COMMISSIONER SEAMOUNT: That's the -- okay,..... MR. ENGEL: Similar. COMMISSIONER SEAMOUNT: .....I was envisioning it that way. MR. ENGEL: Yes. COMMISSIONER SEAMOUNT: So the problem with putting in some sort of subsurface control is you can't get beyond 2,200 feet without pulling it? MR. ENGEL: That's correct. The (indiscernible) tubing strings have a profile at around 2,200 feet that this K-valve would sit it and land and function at that depth. COMMISSIONER SEAMOUNT: How long does it take to do a brush and flush right now? MR. ENGEL: I'd say several hours. COMMISSIONER SEAMOUNT: And if you were to have to put in a restriction at 2,200 feet how long would it .take to do the job then? MR. BARNES: Yeah, nominally an additional two to three hours if everything went perfectly well. COMMISSIONER SEAMOUNT: Okay. So you'd double your time basically? MR. BARNES: Probably. COMMISSIONER SEAMOUNT: Okay. Okay, thank you. CHAIRMAN NORMAN: Commissioner Foerster. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 20 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 COMMISSIONER FOERSTER: You say there's four and a half inch tubing in all the wells? MR. ENGEL: yes. COMMISSIONER FOERSTER: Has any evaluation been done of putting a velocity string inside for -- you said that that inhibits the velocity and contributes to the (simultaneous speech)..... MR. ENGEL: Right, the -- the larger -- larger..... COMMISSIONER FOERSTER: Has an evaluation been done for a velocity string in these wells? MR. ENGEL: I'm going to ask Bob, if Bob is aware of any studies to that? MR. YOUNGER: No, I'm not aware of it. COMMISSIONER FOERSTER: If you did any -- if you did look at velocity strings you could run a velocity string that would have the ability to put a subsurface safety valve in at whatever depth you choose, I'm assuming? MR. ENGEL: Yes, that is correct,..... COMMISSIONER FOERSTER: Okay. MR. ENGEL: .....Commissioner Foerster, that would require a rig to run the tubing and the..... COMMISSIONER FOERSTER: Right. And I recognize that this is a marginal field and that workovers might be uneconomical here, but -- okay, I just wanted to know if you had done that evaluation. Thank you. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 21 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN NORMAN: Anything further, Commissioner Foerster? COMMISSIONER FOERSTER: Nope. CHAIRMAN NORMAN: I have just one question. The paraffin build up is the concern that might inhibit the functioning of the K-valve? MR. ENGEL: Yes. CHAIRMAN NORMAN: And on the brush and flush, what is the flushing agent? What does that consist of? MR. ENGEL: We have in conjunction with the brush, Commissioner Norman, is we use hot oil. We have a truck on site that heats the oil up, or diesel and we pump that down with the brush to actually help remove the paraffin from the well. CHAIRMAN NORMAN: And how could you quantify the success of the flushing agent in removal of the paraffin? Is it -- do you have a high success rate or it is..... MR. ENGEL: I would say yes. Yeah, high success rate. CHAIRMAN NORMAN: Proceed (ph). COMMISSIONER SEAMOUNT: Well, I had a question, but I forgot it so never mind. COMMISSIONER FOERSTER: I have one more. Have you all looked at fractured stimulation or anything like that to increase the productivity of these wells? MR. YOUNGER: A number of these wells have been frac'ed -- fractured (ph) . R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 22 1 2 3 4I 5' 61 ~I BIM 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 COURT REPORTER: I'm sorry, I didn't hear you. MR. YOUNGER: A number of these wells have been -- have been frac'ed. COMMISSIONER FOERSTER: And did that help? MR. YOUNGER: Marginally, I think, I presume (ph). CHAIRMAN NORMAN: Mr. Younger, would you also..... MR. YOUNGER: Sure. CHAIRMAN NORMAN: .....identify your full name and state your background and..... MR. YOUNGER: Right. CHAIRMAN NORMAN: .....credentials for the record? MR. YOUNGER: My name is Robert Younger. I have a degree in Chemical Engineering from Texas Tech University. I received that in 1998. I worked for ARCO in Southeast New Mexico and West Texas from '98 to 2001. I came to Alaska in 2001 and worked Prudhoe Bay until February of 2006 at which time I began working at Northstar and Badami. CHAIRMAN NORMAN: Thank you. Do you wish to present anything further? MR. ENGEL: Yes, I do, Commissioner Norman. I'd like to tall{ about two specific issues that we'd like to address related to the proposed Rule 6 for the Badami order. And the first one is Section (e) of the current draft and I'll ask you to refer to that, please. The last component of that rule states that -- and I'll R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 23 1 2 3 41 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 just read this part of it here. The subsurface valve must be made operable immediately after completion of well operations and tested within 48 hours, unless the well is shut-in. And I'm going to recommend that we add a few words here that would address the actual operation in the field. And after we do well work operations we like to flow the well to malce sure the well is stabilized from a temperature standpoint and typically we let the well flow for a period until that equilibrium is achieved and then we put the valve back in. So I'm recommending that we add within -- I mean, pardon me, after within 48 hours add in these following words, of stabilized production after well operations. Again, that would allow for us to let the well to flow and have the temperature equalize in the system. CHAIRMAN NORMAN: And could I ask you to repeat that suggestion again..... MR. ENGEL: Yes. CHAIRMAN NORMAN: .....verbatim, word for word? MR. ENGEL: Yes. In (e) of proposed Rule 6, after the word within 48 hours we recommend the addition of these words, of stabilized production after well operations. And then continuing on with, unless the well is shut-in. Any questions on that? COMMISSIONER FOERSTER: I have one. MR. ENGEL: Yes. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 24 1 21 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 COMMISSIONER FOERSTER: What if a well doesn't stabilize? MR. ENGEL: I think it would stabilize with time once you start flowing the well. I don't think we have any experience with that. T. J. or -- I don't really see that being an issue, Commissioner. If we didn't at least attempt to stabilize there would definitely be an issue with temperature differential, but with flowing it for a while we think it would stabilize. COMMISSIONER FOERSTER: Well, I understand that you need to attempt to let it stabilize, but if -- if you get a well with abnormal behavior then what would we do to keep it from stringing on (ph)? Hadn't stabilized yet, called you back in a year. MR. ENGEL: We'd have to monitor that specific case, Commissioner, and deal with it on a case by case basis. I don't ]snow of any wells that would -- I don't anticipate any well taking a year to stabilize. COMMISSIONER FOERSTER: Never say never. MR. ENGEL: Indeed. The second comment that I would like to address is I'm going to ask the Commission to reference a letter that AOGA has filed with the Commission on February lst, 2007. This is regarding the draft statewide regulations for safety valve systems. You may not have a copy with you, but I can share a copy with you. And it's language that the state proposed in that draft regulation and it's actually at 20 AAC 25.265 Section (e). R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 25 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN NORMAN: Yes, we have that in a different docket file and so I would appreciate it if you could provide us with a copy if you're going to refer to it, which is fine, for the record of this proceeding also. MR. ENGEL: Yes. Would you like it right now, Commissioner? CHAIRMAN NORMAN: No, you go ahead and..... MR. ENGEL: Okay, okay. CHAIRMAN NORMAN: .....then just after the hearing..... MR. ENGEL: Okay. And I'll read what the language that the state proposed is. It states that, wells that require a subsurface valve -- safety valve under this section, and that do not contain appropriate hardware to make subsurface safety valve installation possible, are exempt from the subsurface safety valve requirement until such time as the well undergoes tubing replacement. And we'd like to recommend that that same language be applied to Rule 6 for the Badami order. COMMISSIONER FOERSTER: So my question is what wells would that apply to? MR. ENGEL: Well, for example, Commissioner, if we had a well that we could put a K-valve in, but the profile would not allow the installation of the K-valve, where we'd have to pull the -- pull tubing to correct that, at that time we could change out to the appropriate style or design that would work for that well. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 26 ~' 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 COMMISSIONER FOERSTER: Are you saying that the profile wouldn't allow it because of the paraffin..... MR. ENGEL: No, profiles can get eroded with..... COMMISSIONER FOERSTER: Okay, got cha, got cha..... MR. ENGEL: So that would be the issue. COMMISSIONER FOERSTER: So what -- all you're saying is if we try to put a K-valve in and the profile has eroded or whatever has happened that we're unable to do that, that we not be forced to pull the tubing right then and fix the situation,..... MR. ENGEL: Yes. COMMISSIONER FOERSTER: wait until such time as a..... ....but that we be allowed to MR. ENGEL: Yes. COMMISSIONER FOERSTER: .....workover? MR. ENGEL: Yes. COMMISSIONER FOERSTER: And -- but. there are no wells that are currently configured in such a way that you would expect that -- there are no current wells that aren't configured to allow you to install something or attempt to install something? MR. ENGEL: That's correct. COMMISSIONER FOERSTER: All right. MR. ENGEL: That concludes our comment this morning. Any additional questions for us? CHAIRMAN NORMAN: Let me ask the two Commissioners and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 27 1 2 3 4 5i 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 then also I think what we would like to do is take about a five minute recess and just collect our questions so that we don't double up on you. I think that would be most efficient, but do you have anything at this time, Commissioner? COMMISSIONER SEAMOUNT: I have none. CHAIRMAN NORMAN: Commissioner Forester? COMMISSIONER FOERSTER: No (ph). CHAIRMAN NORMAN: Then we will recess, let's say for 10 minutes and come back on the record in 10 minutes. MR. ENGEL: Very good. (Off record - 9:40 a.m.) (On record - 9:45 a.m.) CHAIRMAN NORMAN: I'll call the meeting back to order. We've just finished a brief recess. We do have one question/comment that Commissioner Forester will address. Commissioner Foerster. COMMISSIONER FOERSTER: Mr. Engel, you said that you had a lot of experience with these wells stabilizing and so what we would like to get from you is the data that supports how long it takes these wells to stabilize so that we can put a time frame into our rule because we're not comfortable with just saying call us when they stabilize. We want -- we would like to narrow it down to a time frame. MR. ENGEL: From a thermal stabilization? COMMISSIONER FOERSTER: Flow rate stabilization. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 28 1 2 3 4 5 6 7 8 9 10 11 12 I 13 I 14 15 ~ 16 17 18 19 20 21 22 23 24 25 I MR. ENGEL: Okay, okay. COMMISSIONER FOERSTER: So that -- do you understand the question? MR. ENGEL: Yes. COMMISSIONER FOERSTER: Okay. MR. ENGEL: So just to verify, you'd like us to provide data to support a time frame for stabilization? COMMISSIONER FOERSTER: Right, so that we can put a time frame into our rule rather than say call us when it stabilizes. MR. ENGEL: Or perhaps a range of time, something like that? We'll have to look at the data. COMMISSIONER FOERSTER: Look at the data and then work with our technical staff and..... MR. ENGEL: Yes. COMMISSIONER FOERSTER: .....come up with something that is reasonable. MR. ENGEL: Very good. COMMISSIONER FOERSTER: Thank you. CHAIRMAN NORMAN: Are there any other persons present at this hearing that would like to be recognized to speak? The record should -- Mr. Engel? MR. ENGEL: I'd like to bring up another point if no one else is going to be offering any comments. CHAIRMAN NORMAN: Very well. MR. ENGEL: Okay. This is around the reporting R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 29 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 requirements in the new rule and I believe Mr. Regg mentioned during his comments earlier this morning a time of 14 days after the testing. Okay, is that what I heard? COMMISSIONER FOERSTER: Is that what you said, Mr. Regg? MR. REGG: I'm looking at my notes. I said report results within 14 days. MR. ENGEL: Okay. This is a comment related to the statewide safety valve regulations that we've looked at and commented through AOGA in the February 1st, 2007 letter which I'll give you as reference, Commissioner. And in that we requested some rewording that would allow for the submission electronically to the Commission within 14 working days of the completion of the pad or platform test cycle. And that recommendation is just to facilitate a more, I'd say, systematic approach to reporting with our other reports that we're doing for those wells. Instead of doing it one at a time, we do the whole pad or platform and then submit the reports at one time. That would just be a more efficient way to manage reporting requirements. So -- and those comments were submitted for the statewide regs, but we're asking for consideration for these -- for this Rule 6 for Badami. COMMISSIONER FOERSTER: We'll take that into consideration. CHAIRMAN NORMAN: And I am asking that you provide a copy R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 30 1, 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 because sometimes there are different versions or drafts and I want to be sure that in the record of this proceedings we have exactly what you're referring to there as opposed to something else that once in a while gets into the hearing record for the statewide regulations. The Chair now, again, will ask are there any other persons present who would like to offer any comments concerning the matter under consideration? The record should reflect that the Chair sees no one asking to be recognized and accordingly we will adjourn without opposition at the hour of 9:50 a.m. (END OF PROCEEDINGS) (Recessed - 9:50 a.m.) R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 31 1 C E R T I F I CAT E 2 UNITED STATES OF AMERICA ) )ss. 3 STATE OF ALASKA ) 4 I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R 5 Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing Public Hearing In the Matter of the Rules Governing Safety Valve System Requirements 7 pursuant to 20 AAC 25.265 pertaining to the Badami Field on the North Slope of Alaska, was taken by Suzan Olson on the 22nd day 8 of February, 2007, commencing at the hour of 9:00 a.m., at the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska; 9 THAT this Hearing Transcript, as heretofore annexed, is a 10 true and correct transcription of the proceedings taken and transcribed by Suzan Olson; 11 IN WITNESS WHEREOF, I have hereunto set my hand and 12 affixed my seal this 28th day of February, 2007. 13 ~-- C c-~---~_ 14 Notary Public in and or Alaska My Commission Expires: 10/10/10 15 16 17 18 19 20 21 22 23 24 25 R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing Rules Governing safety valve system requirements at the Badami Field February 22, 2007 at 9:00 am NAME -AFFILIATION (PLEASE PRINT) .~~~~ f ~ . __~ -;;~ =~ ~'~~. C~.~a ADDRESS/PHONE NUMBER w . !`s _~_ a~ _ TESTIFY (Yes or No) ` n~~ ~~~ -~12 by ~~ John D. Caring ACT East Production Team Leader Alaska Consolidated Team (ACT) February 20, 2007 RECEIVED FEB 2 1 2007 .,~ ; Alaska Oil & Gas Cons. Commission Anchorage Commissioner John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7t" Avenue, Suite 1~0 Anchorage, AK 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO Box 196612 Anchorage, AK 99519-6612 (907) 564-5111 Phone: (907) 564-5167 Fax: (907) 564-4441 Email GaringJDQbp.com Web: www.bp.com RE: Addition of Sub-Surface Safety Valves (SSSV) rules to Badami Field Conservation Order 402A Dear Mr. Norman: BP Exploration (Alaska) Inc. (BPXA), as the operator of the Badami Unit, welcomes the opportunity to provide information about the Badami field and its operation to the AOGCC in support of the proposed amendments to Conservation Order 402A. Background The Badami field is an onshore development located approximately 40 miles east of Prudhoe Bay. The wells, facilities and the camp are sited on a single pad near the Beaufort Sea coast. The field is not connected by road to the main North Slope infrastructure. Instead, year round access to the field is limited to air and roll-a-gon transportation with barge support as needed during the summer. A winter ice road is constructed only when necessary to move large equipment to the field. Well support equipment located in the field includes a slick line unit, a hot oil unit and various tanks and pumps. Crews are mobilized from Deadhorse when wellwork is required. The Badami field was discovered in 1990 and began production in August 1998. Field production peaked at 17,000 bopd and then quickly declined to Commissioner John Norman, Chair Alaska Oil and Gas Conservation Commission February 20, 2007 Page 2 5,000 bopd by December 1998. The Alaska Department of Natural Resources (DNR) approved the Fifth Plan of Development (POD) and a suspension of operations on May 27, 2003 under which the field was placed in warm shutdown mode due to its low production rate. On June 16, 2005 the DNR approved the Sixth POD and the field was restarted. Badami is presently a marginally economic field due to low producing rates and the high cost of supporting this remote operation. Consistent with the Sixth POD, BP will continue to review the potential for further warm shutdown periods to allow for reservoir recharge and evaluation. Current Operational Status The Badami field currently produces approximately 1100 bopd and 1.5 mmcfd with minimal water. A summary of the Badami wells is as follows: • 4 Producers - On-line current producing well rates range from 30 to approximately 400 bopd. • 1 High GOR Producer -Shut-in • 1 Low Productivity Producer -Shut-in • 2 Producers with Downhole Mechanical Issues -Shut-in & secured • 1 Gas Injector - On-line • 1 Class I/Class II Disposal Well - On-line The Badami wells were designed for well production rates much higher than current. The wells are equipped with 4-1/2" tubing resulting in the current low well velocities. Gas lift mandrels were installed in three of the currently producing wells and packoff gas lift mandrels have been installed in a fourth well. Two wells are normally operated with gas lift. All active Badami wells are equipped with automatic surface safety valves. The wells are also equipped with hydraulically actuated wing valves as part of the overall shut down system. The automated wing valves are actuated by the same low pressure switch as the surface safety valve providing redundant protection. Commissioner John Norman, Chair Alaska Oil and Gas Conservation Commission February 20, 2007 Page 3 Three of the six wells capable of production have control lines and a mandrel at about 2200 feet designed to allow the installation and operation of surface controlled subsurface safety valves. The remaining three producers and the gas injection well are equipped with a nipple at about 2200 feet, which may allow installation of a downhole controlled subsurface safety valve. The gas injection well is currently equipped with a subsurface injection valve set in the nipple. The condition of the control lines, mandrels and nipples in the producers is unknown since they have not been used since installation. It is possible that all producing wells will require K-valves or some may require additional wellwork to equip the well with functional subsurface safety valve equipment. In addition, the installation of K-valves will most likely require operating the wells with increased back pressure to facilitate testing and closure of the valves. This additional flowing tubing pressure will decrease production. Operational Considerations for Installation Schedule The following unique circumstances at the Badami field may impact the installation and operation of subsurface safety valves. 1. Paraffin and Potential Impacts on K-Valves Paraffin deposition has been a major operational concern in the Badami wells and pipelines. Due to low producing rates, pressures and temperatures, four of the producing wells require periodic downhole paraffin removal operations. These "brush and flush" jobs utilize slick line tools during the pumping of hot diesel or crude oil into the well to remove paraffin to about 4000 feet. The frequency of these jobs is every five to six weeks for two wells and around every six months for two other wells. Subsurface safety valves set at about 2200 feet will be located within the paraffin deposition interval of the wells (0-4000 feet) and paraffin deposition may hinder the operation of the valves, In addition, each "brush and flush" job will require additional operations and time to remove the paraffin from above the valve, Commissioner John Norman, Chair Alaska Oil and Gas Conservation Commission February 20, 2007 Page 4 retrieve the valve using slick line, and to resume operations below the mandrel or nipple, K-Valves have been used on the North Slope for many years as an alternative for surface controlled subsurface safety valves when control lines have failed. The valves are designed with a spring and nitrogen dome charge to close when the pressure above the valve reaches the set point. During uncontrolled flow, the flowing pressure decreases to a point where the valve will close. The valve is re-opened by pressuring the fluid column above the valve. With this design the flowing conditions within the well must be accurately known to select the correct combination of spring and dome pressure. The wellbore conditions in wells prone to paraffin deposition will be constantly changing. Based on experience in high paraffin environments, K-valves will be difficult to maintain and operate in several of the Badami wells. At a minimum, K-valves in high paraffin wells will likely require increased well intervention and well downtime to maintain the reliability of the valve. Therefore, a staged approach to installation would be prudent in order to identify potential issues. 2. Pipeline Considerations The Badami sales line is operating near the lower end of its operating range. Oil produced from Badami is exported through a 25 mile 12" pipeline to a connection point with the Endicott common carrier pipeline. It is possible that the additional downtime associated with the installation, maintenance, and operation of subsurface safety valves may result in occasions where total rate is not adequate to allow the field to operate. Currently crude oil arrives at the Endicott connection point near zero degrees F. Shutting down the pipeline in cold weather increases the risk of pipeline plugging; therefore, a summer installation campaign would help reduce the risk of pipeline plugging. ~- Commissioner John Norman, Chair Alaska Oil and Gas Conservation Commission February 20, 2007 Page 5 Implementation Considering the unknown impacts on the operation of K-valves in paraffin producing wells coupled with the potential risks to pipeline operations, BPXA believes the optimum time frame to test the functionality of SSSVs is in the warmer months. Therefore, BPXA requests until October 1, 2007 to complete the phased installation of SSSVs at Badami. Should significant operational issues associated with K-valves arise, BPXA will inform the AOGCC and propose alternatives. BPXA personnel will be available at the February 22 hearing to answer any questions concerning the above information. Should you have questions prior to that time, please contact me at 564-5167. Sincerely, John D. Caring cc: Badami File X11 by _ John R. Denis Acting Perfonrance Unit Leader Alaska Consolidated Team (ACT) -East ACr East Resource Manager ~~~ V February 2, 2007 Alaska Oil & Gas Gnns. G~rr~missinn Anchorage Commissioner John Norman, Chair Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 ,~ BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO Box 196612 Anchorage, AK 99519-6612 (907) 564-5111 Phone: (907) 564-5049 Fax: (907)564-4441 Email denisjr@bp.com Web: www.bp.com RE: Public Hearing Notice, Badami Field Rules Governing Safety Valve System Requirements Dear Mr. Norman: The AOGCC has published a notice of a public hearing to clarify safety valve system requirements for the Badami field, tentatively scheduled for February 22, 2007. The notice indicates a request to hold the hearing should be submitted to the Commission by February 5. BP Exploration (Alaska), Inc. (BPXA) as operator of the Badami field hearby requests the hearing be held as tentatively scheduled. BPXA intends to provide written comments and operational information for the Badami field ar~d wells by the required deadline. BPXA will be prepared to discuss these written materials at the hearing as well as answer any questions the Commission may have. Should you have questions, contact me at 564-5049. Sincerely, ~~~~~ ~ ~~ ~~ -- John Denis cc: R. Buckendorf B. Fackrell J. Garing R. Younger S. Rossberg H. Engel M. Bill Badami File ~o y Alaska it and Gass®ciati®n February 1, 2007 121 W. Fireweed Lane, Suite 207 Allorage, Alaska 99503-2035 Phone: (907)272-1481 Fax: (907)279-8114 Email: Crockett@aoga.org Marilyn Crockett, Deputy Director Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 W. 7`h Avenue, Suite 100 Anchorage, Alaska 99501 Dear Mr. Regg: AOGA Comments on Draft Safety Valve System Regulations (20 AAC 25.265). AOGA appreciates the opportunity to provide you with comments on the working draft of the safety valve regulations. Our detailed comments are attached, and we offer general comments and observations below. To facilitate a clear understanding behind the intent of these comments, we'd like to request an opportunity to meet with you and Commissioner Foerster. AOGA representatives are available beginning the week of February 5 to meet at your convenience. General comments/observations: - Will the revised regulations modify or replace the current requirements in the AOGCC Policy on SVS Failures and in existing Pool Rules conservation orders? It could be a significant burden to re justify all Pool Rule orders related to SVS. For instance, CO 390 exempts Milne Point wells from SSSV in ESP wells, and CO 458A allows for Northstar SSSV to be set above the permafrost. - Once the regulations are adopted, what will be the timeframe for compliance? It is critical that sufficient lead time be provided so that operators can make necessary modifications to avoid being out of compliance. -The draft regulations do not address several areas cited in the Safety Valve System Task Force final report, in particular, the calculation of pad failure rates and the consequences of high pad failure rates. - What is the overall benefit the Commission is intending to achieve by increasing the number of wells required to install and maintain surface SVS systems and subsurface safety valves? Has there been an increase in well control incidents that would have been prevented by safety valve systems? In some cases additional risk due to well interventions associated with subsurface safety Alaska Oil and Gas Association Detailed Comments on Draft Well Safety Valve Systems Regulations (20 AAC 25.265) February 1, 2007 (Note: the proposed regulatory language is shown in black, and AOGA's comments on each section are shown in blr.~e.) 20 AAC 25.265 Well Safety Valve Systems (a) All completed wells, except water source wells, disposal injection wells (wells used for disposal of oil field wastes), and monitor wells must be equipped with a commission approved safety valve system, except when the well's production or injection zone is mechanically isolated from the atmosphere or during well workover or interven- tion operations under (i). - Since the AOGCC definition of "complete" is to equip and condition a well as an oil, gas or service well so that it is capable of producing or injecting fluids, these regulations may apply to shut-in as well as active wells, which is not warranted. - Clarify that mechanical isolation from the production or injection zone includes a closed master valve, surface safety valve, wing valve andlor manifold valve would be acceptable consistent with the requirements of these regulations. The AOGCC definition of "shut-in" is to close a well's surface, wellhead, or subsurface valves to halt flow from or into the well, with the completion interval remaining open to the tubing below the closed valves. - What constitutes a "commission approved safety valve system" and how will this approval occur? - Water injection wells are not specifically excluded. for the SV5 requirement. Since the AOGCC does not currently require testing of surface safety valves for wells injecting water, there will be a significant increase in the number of required tests. (b) The safety valve system must have a surface safety valve with actuator, and a low-pressure pilot or aloes-pressure transmitter with the capability to shut in the well when the flow line pressure drops below the required system actuation pressure. - Revise as follows: Unless a commission approved, functionally equivalent system is utilized, the safety valve system must have a surface safety valve with actuator, and aloes-pressure. pilot, slow-pressure transmitter or switch, with the capability to shut in the well when the flow line pressure drops below the required system actuation pressure. (c) In addition to (b) of this section, the following requirements also apply to the safety valve system: (1) the surface safety valve must be located above the master valve in the vertical run of the production tree or be on the flow line immediately adjacent to the production tree; - Insert "if utilized" following "the suirface safety valve". AOGA Comments on S`,,,_..-Draft Regulations ~~ February 1, 2007 Page 3 __ (10) the system actuation pressure of a low pressure pilot or low pressure transmitter installed on a development well must be at least 50 percent of the inlet separator pressure or 25 percent of the flowing tubing pressure, whichever is greater; (11) the system actuation pressure of a low pressure pilot or low pressure transmitter installed on an injection well must be greater than 50 percent of the in- jection tubing pressure or 50 percent of the compressor discharge manifold pres- sure, whichever is less; (d) In addition to meeting the requirements in (a), (b) and (c) of this section, the following completed wells must also be equipped with afail-safe automatic surface con- trolled subsurface safety valve system capable of preventing an uncontrolled flow from the tubing, unless another type of subsurface safety valve with that capability is approved by the commission prior to the alternate valve's installation: (1) a gas injection well; (2) a well that is capable of unassisted flow of hydrocarbons to surface and with an offshore surface location; (3) a well that is capable of unassisted flow of hydrocarbons to surface and with an onshore surface location that is within one-quarter mile of a perma- nent dwelling (billeting camp or residence), commercial building occupied full time, public road, railroad, commercial airport, coast line, or navigable waterway excluding wetland areas; and - 1/, mile seems arbitrary. The regulations should allow for exceptions. - Clarify the definition of "navigable waterway" that will apply to these regulations. Each agency seems to have its own definition. Some definitions include lakes, sloughs, streams and uses such as trapping or hunting waterfowl. The definition could exclude waters if public access is restricted. - Clarify the definition of a "commercial building". Buildings directly associated with field E&P operations should be excluded. - Clarify that a re-locatable rig camp is excluded from the "perma- nent dwelling" definition. (4) a well that the commission determines, after notice and an opportunity for hearing in accordance with 20 AAC 25.540, must be equipped with a subsur- face safety valve system. (e) Wells that require a subsurface safety valve under this section, and that do not contain appropriate hardware to make subsurface safety valve installation possible, are exempt from the subsurface safety valve requirement until such time as the well un- dergoes tubing replacement. (f) The subsurface safety valve must be installed in the tubing string and located below the mudline datum, or if permafrost is present, below the permafrost. AOGA Comments on S'~~,r, Draft Regulations February 1, 2007 Page 5 (6) at least 24 hours (48 hours if remote from the nearest AOGCC office) notice of safety valve system testing must be provided to the commission so that a commission representative can witness the test; - Revise wording to read: "unless another timeframe is required by the commission, the operator shall provide at least 24 hours notice of safety valve system testing to the commission so that a commission representative can witness the test". (7} when the low pressure pilot or low pressure transmitter actuates, the surface safety valve must close with no detectable leakage in two minutes or less. No detectable leakage is defined as showing a stabilizing trend on a calibrated pressure gauge near the wellhead; - Insert "Unless a commission approved functionally equivalent sys- tem is utilized" at the beginning of this subsection. Revise wording in second sentence to read: " ... showing a stabilizing trend on a cali- brated pressure gauge near the well head or an electronic monitoring system." (8) when the low pressure pilot or low pressure transmitter actuates, the subsurface safety valves, where required by regulation, must close with no detect- able leakage in four minutes or less. No detectable leakage is defined as showing a stabilizing trend on a calibrated pressure gauge near the wellhead. - Revise wording to read: " ... showing a stabilizing trend on a cali- brated pressure gauge near the well head or an electronic monitoring system." (9) a safety valve system component test is considered a failure when it does not pass the component specific test criteria on the first attempt; (h) If a component of the safety valve system fails a test, the component must be repaired or the well shut-in as follows: (1) if the low pressure pilot or low pressure transmitter fails to actuate or actuates below the required pressure setting, it must be repaired or replaced im- mediately and tested, or the well must be shut-in; - Revise to read: "if the low pressure pilot, low pressure transmitter or switch fails to actuate...". - Clarify for consistency: Allow operation of the well if the pad is con- tinuously manned as in (i)(2}. The current requirement of "24 hours to repair so long as the pad is manned" is well known and works. - Allowance should be made to allow time for a safe shut-in. (2) for a well equipped with only a surface safety valve, (A) if the surface safety valve fails to function, it must be repaired or replaced immediately and tested after installation, or the well must be shut-in; or AOGA Comments on S`~~Jraft Regulations February l , 2007 Page 7 __ he made operable immediately after completion of well operations and tested within 48 hours, unless the well is shut-in; - The testing requirements in this subsection are redundant with the requirements in (g)(4). - Clarify if the test results after well work require inspector notifica- tion and reporting of results. This could add a significant number of tests to the reports. - The test requirement should be "tested within 48 hours of restoring the well to stabilized flow after well. operations ..." to give time to as- sess the results of the well work and warm up the well before re- setting the SSSV. (2) the surface safety valve and the low pressure pilot or low pressure transmitter may be removed or defeated; however, unless otherwise authorized by the commission, the well pad or platform must be continuously manned or the well shut in until the surface safety valve and low pressure pilot or low pressure transmitter are made operable; and - At the beginning and end of this paragraph, change to read: "...low pressure pilot, low pressure transmitter or switch...". - Clarify for consistency: See notes for (h)(1) and (h)(2). (3) well pads, platforms, islands or similar groups of wells will be consid- ered manned if a responsible person trained in well operations appropriate to the location is physically on-site at all times to shut in a well. (j) An operator may demonstrate by a no-flow test that a well is incapable of un- assisted flow of hydrocarbons to the surface. A no-flow test must be performed accord- ing to commission-approved procedures and requires a commission witnessed three hour period of no-flow. At least 24 hours (48 hours if remote from the nearest AOGCC office) notice must be provided to the commission so that a commission representative can wit- ness the test. Well work activities that have the potential to impact a well's flow capabil- ity will invalidate the well's no flow status, and require either a no flow retest or installa- tions of a subsurface safety valve. - Revise wording to read: "... Unless another timeframe is required by the commission, the operator shall provide at least 24 hours notice of safety valve system testing to the commission so that a commission representative can witness the test". (k) For purposes of (d) of this section, a well is incapable of unassisted flow of hydrocarbons to the surface when: (1) a witnessed no-flow test demonstrates that either (A) the measured liquid production is not greater than 6.3 gallons per hour and the measured gas production is not greater than 900 standard cubic feet per hour, or; (B) well pressure is discharged within five minutes, after a three hour charted pressure build-up period; and C" J 1 H 1 C yr /-~L/1Jr~r~ 9V~lJ 0 A`So~ A'~d ~ ~drL7~oa~e ev_na AQ@/ERTISING QRDER INVOICE`w.d3T BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO~'tRTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE p~ ~®Leq~ ~®~ ~4 GEE BOTTOM FOR INVOICE ADDRESS ~ R AOGCC ~ Ste 100 333 W 7th Ave aGEVCV Oc~~TA~T Jod Colombie DATE ar:..a. Jan 17 2007 ° tit , Anchorage, AK 99501 PHONE PCN _ DATE5 ADVERTISEMENT REQUIRED: o Anchorage Daily News January 18, 2007 RINTED IN ITS THE 41ATERIAL BETWEEN THE DOUBLE LINES fKUST BE P ENTIltETY ON THE DATES SHOWY. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legai® ^ Display Classif ied ^®ther (Specify) SEE A'T~'ACI~D SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TOTAL OF TO Anchora e AK 99501 2 PAGES ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 Axe 02910 3 4 C PGM LC ACCT FY NMR FIN AMOUNT SY C DIST L!Q ~ OS 02140100 73451 2 3 4 " ' 1N1 ~DDR(1\/AI : I I°E^~aU:v~T~'L":° °Y' \ ~ ~ I fIIVICI( "1 i l 1 F` i ~~ `~ L., . ,....,.. 1 ~, I I ~-~, I ~~"V/ U I~ UV I i 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM ~~ Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Rules governing safety valve system requirements at the Badami Field The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to clarify safety valve system requirements for the Badami Field on the North Slope of Alaska. Safety valve system requirements, according to 20 AAC 25.265 will be established for wells with onshore surface locations at the discretion of the Commission upon public notice and opportunity for hearing. The Commission is proposing to amend Conservation Order 402A to address safety valve system requirements for all producing and hydrocarbon injection wells. The proposed safety valve requirements for Badami are available on the Commission's website at ~n~v.aogc .alasa~a.go~~ and at the Commission's office. Copies are available upon request. The Commission is vacating the January 25, 2007 hearing and has tentatively rescheduled public hearing on this proposed action for February 22, 2007 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7~` 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 February 5, 2007. If a request for a hearing is not timely filed, the Commission will consider the issuance of orders without a hearing. To learn if the Commission will hold the public hearing, please cal1793-1221. In addition, a person may submit written comments regarding these proposed actions to the Alaska Oil and Gas Conservation Commission at 333 West 7`~ Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on February 20, 2007, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on February 22, 2007. If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221. ~~~~ ~~ -~P~ John K.~Norman U Chairman Published Date: January 18, 2007 ADN AO# 02714016 .~~~ 1Zule 6 Auta-matic Shut-in Equipment a. Ali completed wells except water source wells, disposal injection wells (wells used for disposal of oilfield wastes), and monitor wells must be equipped with a commission approved safety valve system, except when the well's production or injection zone is mechanically isolated from the atmosphere or during well workover or intervention operations. b. The safety valve system must include: 1. A fail-safe surface safety valve with actuator, and aloes-pressure pilot or low- pressure transmitter with the capability to shut in the well when the flow line pressure drops below the required system actuation pressure (for a development well, the required system actuation pressure is at least 50 percent of the inlet separator pressure or 25 percent of the flowing tubing pressure, whichever is greater; for gas injection wells, the required system actuation pressure is 50 percent of the compressor discharge pressure). 2. A fail-safe subsurface safety valve, installed in the tubing string below the base of the permafrost and capable of preventing uncontrolled flow from the tubing. A well passing a no-flow performance test (no flow of hydrocarbons to surface) witnessed by a Commission representative is not required to have a subsurface safety valve. 3. A safety valve system control unit placed in a location that is readily available to human intervention. c. Safety valve systems must be maintained in good operating condition at all times and must be protected to ensure reliable operation under the range of weather conditions that may be encountered at the well site; d. Safety valve systems must be tested at intervals of six months, not to exceed 200 days between tests unless the commission prescribes a different test interval. The commission must be given at least 48 hours notice for an opportunity to witness the tests. Results of the tests must be provided to the commission within 14 days in an electronic format. e. When well workover or intervention operations require it, the subsurface safety valve may be blocked or removed; however, unless otherwise authorized by the commission, the subsurface safety valve must be made operable immediately after completion of well operations and tested within 48 hours, unless the well is shut in. f. The surface safety valve and the low pressure pilot or low pressure transmitter may be removed or defeated only when the well is shut in or pad is continuously manned by a person trained in well operations. Updated: 1/18/2007 STOF0330 r..~.„ , #111622 $199.20 AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Christine Clark being first duly sworn on oath deposes and says that he/she is an 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 January 18, 2007 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 priv 'te individuals. ~'^ ~ ,~_- ~~ Slpy"l~cJ-. ~` .. ~, /~ , Sutiseribed and~worn to before me this ~ 3 day of 20 rrrr~~~ ',: .~~~ Notar P lit in and or~ .' •+~~~~y•sS. The Slate of Alaska. ` ~ ' ~^„ Third Division ~ ~ w,~,~ Anchors c., Alaska ,~'' r "'~ ~~ MY COMMISSION EXP[i~,, yati ,„ •e^°~ ,. ~~~~11111111•i1}~, Notice of Public Hearing. STATEAEALASKA Alaska'.Oil and Gas Gonseryation.Gommissioh - Re: Rules ggverning safety-valve system - -requirements at the Bgddfhi~Field The Alaska Oil a'nd Gas Conservation Commission ("commission")-, on_its own motion, proposes~To clarify°safetvvdtve svsteni requirements for the. ~8adami'Field on ihe_N9rth Slope of Alaska. Safety valve svstemrequi.rements, according to 20 AAC 25:265 will lie established fdr wells with onshore sur- 'face IgcaTions aT The discretion of the Commission-: bpon .public notice and ouuortuiiity for hearing. The! COmmis5la^ is-proposing to amend COnSBryp TiOh Order 402A To dddress safety valve system require- mehts for all'pi-oducing anti I>,vdrocarbon infection wells. The proposed safety valve requireinents'fdr: Badami are avaiiphle.gn the Commission's wedsite at' www:aoscc.alaska.soy and aT fhe Commission's` office: Copies dre available uuon request. The Commission is vaczrting the January 25, 2007'. hegrins and-has tentptively rescheduled pvblis hear- - ins on this proposed action for Febrriarv 22, 2007 at' 9;Op am at The Alaska Oil and Gas Consetvptidh' .Commission at333W.est 7th Avenue,.SuiTe 100; An- chgrage, Alaska99501, P, person may7equesT'ThpT~ ThetentaTively scheduled hedging-tie field by;filins d written request w.ifh the Commissionno later3hbn 4:30 bm on:Februarv 5, 2007: -~ -~ If a eequesT for ahearins is not Timely filed, the Commission svill'COnsider the issuance of'orders: -wiThouTa-.heprin@. To learn if the.Com rriission will. hold the public hearing, pleasecall 793-1221_ In-addition, a person mdv submit-written comments re5ardine These proposed actions To khe Alaska Oil :and Gas Conservdtion Cdrrlmissibnat.333 Wesf7ih Avenue, Suite 100,'Anchdi'age, Alaska 9950}. Writ- ten comments must be received no later than 4:30 pm on February 20, 2007, except that if :the Commfs- sion decides tb hold a uublic hearing, 4vritten coin- menu drust be received. no later than 9:00 am qn February 22, 2002 If you are a person with a disability who may need special accommodations in order to comment or To aftend the public hearing, please contract Jodv Co- lombie pt 793-7221. /s/ John K. Norman Chairman ADN AOb 027140M - Published Date: Jgnuarv 16- 2007 STATE OF At.AS~A JBDVERTISINf~ ORDER SEE 80TTOM FOR INVOICE ADDRESS N®TSCE °f® P~.J~~.I~FiER AILDVIEIKrIJI1VCr~Ii%JC.Yd:v~. INVOICc+.'~1ST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO yERTIFtED AFFIDAVIT OF PUBLICATION {PART 2 OF THIS FORM) WITH ATTACHED COPY OF A®m®2~1 ~®~ `w ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ~ A®GC;G R 333 ~fJest 7`~' A~'enue. Suite 100 ° Anch~ra~e. AK 99501 `'I 907-793-1221. An Anchorage Daily News cho AGE\CY' CONT:IC'T I DATE OF a.0. PHONE ~PCN I y~ // I / 7 7 ~ L G G I _ DATES ADVERTISEMENT REQUIRED: 3anuary 18, 2007 TAE MATERLU. BE'IWEEN'I"HE DOUBLE LINES NtUST BE PRINTED CY ITS ENTIRETY ON TAE DATES SHOWN. SPECL4L INSTRUCTIONS: Advertisement to be published was e-mailed AFFIDAVIT OF PUBLICATION United states of America State of division. ss Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that 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 r,.. ,... IVIy I+vl~11I IISjIVI l1 2%~plr~J REMINDER 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. UBLISHER ',~..~ Subject: Public Notice and Attachment From: Jody Colombie <Jody_colombie@admin.state.ak.us> Date: Thu, 18 Jan 2007 11:32:35 -0900 To: undisclosed-recipients:; BCC: Christine Hansen <ahansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjrl@aol.com>, jdarlington <jdarlington@forestail.com>, nelson <knelson@petroleumnews.com>, cboddy <eboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinacom>, 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 <bbriteh@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>, DanBross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerF@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, " Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <P1attJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gcinet>, 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 <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nad@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones~urorapower.com>, dapa <dapa@alaska.net>, jroderick <jroderick@gci,net>, eyancy <eyancy@seal-tite.net>, "James 1VI. 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>, 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@dnratateak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, many <marty@rkindustrial.com>, ghamrnons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd.Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnratate.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 <Bil1 Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, n1617@conocophillips.com, Tim Lawlor <Tim Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda .Kahn@fwsgov>, 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@conocophillps.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@dnrstate.ak.us>, Ken <krlyons@suddenlink.net>, Steve Lambert <salambert@unocal.com>, Joe Nicks mews@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>,.Bll Walker <bill-wwa@ak.net>, Iris Matthews <Iris_Matthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough <admin@aleutianseast.org>, Marguerite kremer 1 of 2 1/18/2007 11:32 AM <marguerite_kremer@dnr.state:2a~.us>, Mike Mason <mike@kbbi.org>,~iarland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <Camille Taylor@law.state.ak.us>, T'hornas 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 <jim_regg@admin.state.ak.us>, Catherine P Foerster <Cathy_foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <Laura_silliphant@dnr.state.ak.us>, David Steingreaber <david.eateingreaber@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>, Mike Stockinger <Mike.Stockinger@anadarko.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Gaging <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegarner <jimwinegarner@brooksrangepetro.com> Please disregard yesterdays e-mail with regards to the Public Notice and attachment for "Rules governing safety valve system requirements at the Badami Fields". I inadvertently e-mailed the wrong version of .the attachment. I apologize for any inconvenience this may of caused. Jody Colombe Jody Colombie <~ody colombie(a,admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: applicaton/pdf Public Notice Badami.pdf Content-Encoding: base64 2 of 2 1/18/2007 11:32 AM Mary Jones '`e-' David McCaleb XTO Energy, Inc. IHS Energy Group Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 George Vaught, Jr. Jerry Hodgden PO Box 13557 Hodgden Oil Company Denver, CO 80201-3557 408 18th Street Golden, CO 80401-2433 John Levorsen Kay Munger 200 North 3rd Street, #1202 Munger Oil Information Service, Inc Boise, ID 83702 PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Schlumberger Halliburton Drilling and Measurements 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Land Department 9649 Musket Bell Cr.#5 PO Box 93330 Anchorage, AK 99507 Anchorage, AK 99503 Gordon Severson Jack Hakkila 3201 Westmar Cr. PO Box 190083 Anchorage, AK 99508-4336 Anchorage, AK 99519 James Gibbs Kenai National Wildlife Refuge PO Box 1597 Refuge Manager Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin PO Box 60868 PO Box 70131 Fairbanks, AK 99706 Fairbanks, AK 99707 North Slope Borough Williams Thomas PO Box 69 Arctic Slope Regional Corporation Barrow, AK 99723 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 e~ ~\~~~I~1~C1~G'l ~~ STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRE F AOGCC R 333 W 7th Ave, Ste 100 ° Anchorage, AK 99501 M o I~Anchorage Daily News (Type of Advertisement PHONE IPCN DATES ADVERTISEMENT REQUIRED: January 18, 2007 TIIE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN TTS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Display Classified SEE ATTACHED SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TO Anchor e AK 99501 tEF TYPE NUMBER AMOUNT DATE 1 VEN 2 A1tD 02910 3 4 CC PGM LC FIN AMOUNT SY 1 Og 02140100 z 3 ~ ~ 4 a"' j \ IJ ,` NOTICE TO PUBLISHER ADVERTisIlVC ORDER No. u INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A 0_02714016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM} WITH ATTACHED COPY OF !1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AGENCY CONTACT DATE OF A.O. (Specify) PAGE 1 OF I TOTAL OF 2 PAGES ALL PAGES ACCT FY NMR o~sr 73451 AO.FRM 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving hTotice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Rules governing safety valve system requirements at the Badami Field The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to clarify safety valve system requirements for the Badami Field on the North Slope of Alaska. Safety valve system requirements, according to 20 AAC 25.265 will be established for wells with onshore surface locations at the discretion of the Commission upon public notice and opportunity for hearing. The Commission is proposing to amend Conservation Order 402A to address safety valve system requirements for all producing and hydrocarbon injection wells. The proposed safety valve requirements for Badami are available on the Commission's website at vrv~nv€r.~~~~~,.~1%sbc~.~~>> and at the Commission's office. Copies are available upon request. The Commission is vacating the January 25, 2007 hearing and has tentatively rescheduled public hearing on this proposed action for February 22, 2007 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7t" 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 February 5, 2007. If a request for a hearing is not timely filed, the Commission will consider the issuance of orders without a hearing. To learn if the Commission will hold the public hearing, please ca11793-1221. In addition, a person may submit written comments regarding these proposed actions to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on February 20, 2007, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on February 22, 2007. If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact Jody Colombia at 793-1221. ~~~~ ~ John K Norman Chairman Published Date: January 18, 2007 ADN AO# 02714016 Rule 6 Automatic Shut-in Epuinment a. All completed wells except water source wells, disposal injection wells (wells used for disposal of oilfield wastes), and monitor wells must be equipped with a commission approved safety valve system, except when the well's production or injection zone is mechanically isolated from the atmosphere or during well workover or intervention operations. b. The safety valve system must include: 1. A fail-safe surface safety valve with actuator, and aloes-pressure pilot or low- pressure transmitter with the capability to shut in the well when the flow line pressure drops below the required system actuation pressure. 2. A fail-safe automatic surface controlled subsurface safety valve (SSSV), installed in the tubing string below the base of the permafrost and capable of preventing uncontrolled flow from the tubing, unless other types of subsurface valve are approved by the Commission. A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no flow" performance test witnessed by a Commission representative, is not required to have SSSV. 3. A safety valve system control unit placed in a location that is readily available to human intervention c. Safety valve systems must be maintained in good operating condition at all times and must be protected to ensure reliable operation under the range of weather conditions that may be encountered at the well site; d. Safety valve systems must be tested at intervals of six months, not to exceed 200 days between tests unless the commission prescribes a different test interval. The commission must be given at least 48 hours notice for an opportunity to witness the tests. Results of the tests must be provided to the commission within 14 days in an electronic format. e. When well workover or intervention operations require it, the subsurface safety valve may be blocked or removed; however, unless otherwise authorized by the commission, the subsurface safety valve must be made operable immediately after completion if well operations and tested within 48 hours, unless the well is shut in. f. The surface safety valve and the low pressure pilot or low pressure transmitter may be removed or defeated only when the well is shut in or pad is continuously manned by a person trained in well operations. Anchorage Daily News ~~ lilyi2a'7 Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD # DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 111622 01/18/2007 02714016 STOF0330 $199.20 $199.20 $0.00 $0.00 $0.00 $0.00 $0.00 $199.20 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 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 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 ublication is not in excess of the rate charged private individu~~s. and s`~worn to me before this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY OMMISSION EXPIRES: ~ C ww~ + ~~ ~ '~'~~~3':~^ ~wjl w+e yq . _ wqw a~~ / ,.LS' ~f 1~d~ ~~1~1I1S>>~' Nofice•of Public Hearing e $TATE.OF:ALASKA Alaska Oil and Gas COnserva}ion-Commission Re,: Rules governing safety valveSYStem ' -:reciuiremenis at tfie Badami'Field ~TheAlaska Oil andGas Conservafioti Commission ("Commission"), on its own motion, proposes-to~ clarify safety valve system requirements for The -Badami F.ieldon:lheNorth Slope of Alaska. Sateiv 'valve system rAquirements, according to 20 AAC 25.265 willbeestablished for wells-witbonshore sur- face-locations at the discretion. of; the Commission -upon public notice and opportunity for hearing. The: 6oinmisslan iS prapO5i n9 10 gmerld.COn52rvaTiOn -0rder 402A to address safefv vdlve system require- ments for all'producuig and hydrocarbon inieciion wells. The-proposed safety valve requirements for .Badami are available on the Commission's website at www:ao9cc.dlaskn,.gov and atfihe Commission's .offi~C: -Copies are available upon request. - The"COmmissiohis vacatine the January 25, 2007 hearing and has tentatively rescheduled public hear- `ing On this. proposedaction for Februbrv 22, 2007 at ?9:00 amat`the Alaska Oil and Gas Conservation Commissionat,333 West 7th Avenue, Suite 1p0, An- chora9e, Alaska 995Q1; A'person may request that iheteritativelY scheduledhedring be:heldby fifin9.a written request with the Commissioq no later"than 4:30 pm"onFebruarv 5,2007:. If a request fora hearingis-not Timelvfiilea, the -Cgmmiss'ton willconsi(~er_the issuance of orders -witliouf a,hearing. To'learn~if'ffie Gorrimission will ~haldttie publichecrring, please call 793-1221. " In addition,. a person may submit written comments re9gr•ding these proposetl actions?o the Alaskti Oil and:Gas Conservation Commission at 333-We4T 7.Th' '.Avenue, Suite 100,~Aiichorage, Alaska'9950L Wdit- Ten comments-must be;received no IaTer than. 4:30 pm on February 20, 2007, except thdt if'the Commis-` Sion tlecides to hold a public hearingi.writterrcOm-' meets must. be received.no later than 9::00 amt on .February 22, 2087. If you are a person with a disability who may need; .Special atCOm mOdati0n5 in order to com nle nT or t0 -dttend the public hearing, please contact Jodv Co-- 'lombie at 793-7221. /s/:John K. Norman .Chairman -ADN AO# 02714016 ' 'PUblishedDate: January;18,: 2007 Subject: RE: Public Notice From: "Ads, Legal" <legalads@adn.com> Date: Wed, 17 Jan 2007 11:32:19 -0900 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: 111622 Publication Date(s): January 18, 2007 Your Reference Number: 02714016 Total Cost of Legal Notice: $199.20 Thank You, Kim Kirby Legal Classified Representative E-mail: lcgalads(aadn.com Phone: (907) 257-4296 Fax: (907) 279-8170 -----Original Message----- From: Jody Colombie [mailto:_jody colombie@admin.state.ak.us] Sent: Wednesday, January 17, 2007 10:28 AM To: Ads, Legal Subject: Public Notice Please publish tomorrow. Jody Colombie 1 of 1 1/17/2007 12:38 PM NOTICE TO PUBLISHER '~ ADVERTISING ORDER NO. STATE OF ALASKA _ IFIED AO-02714016 O I R ~ I O F COP H ATTACHED W T (PART 2OF THIS ORM ADVERTISING AFFI DAVI OF PUBLICATON ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS AGENCY CONTACT DATE OF A.O. F AOGCC R 333 West 7~' Avenue. Suite 100 PHONE PCN ° Anch~raae_ AK 995(11 M 907-793-1221 DATES ADVERTISEMENT REQUIRED: An Anchorage Daily News January 18, 2007 cho THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed AFFIDAVIT OF PUBLICATION United States of America .REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 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 My commission expires UBLISHER Subject: Public Notice From: Jody Colombie <Jody_colombie@admin.state.ak.us> Date: Wed, 17 Jan 2007 10:27:32 -0900 To: Legal Ads Anchorage Daily News <legalads@adn.com> Please publish tomorrow. Jody Colombie Jody Colombie <joc~iy colombie(u),ad-niu.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/msword Ad Order form.doc Content-Encoding: base64 Content-Type: application/msword badami svs_hearing_notice_revised.doc - Content-Encoding: base64 1 of 1 1/17/2007 12:15 PM Subject: Public Notice Badami SVS From: Jody Colombie <Jody_colombie@admin.state.ak.us> Date: Wed, 17 Jan 2007 12:15:08 -0900 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen@iogcastate.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjrl@aol.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews:com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinacorn>, Shannon Donnelly. <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnratate.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" <Ski11eRL@BP.com>, "Deborah J. Jones" CTonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospsG@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" <P1attJD@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 <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fredateece@state.sd.us> rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, daps <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>, 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>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx:rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, many <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.akus>, 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 <Bi11 Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@mmsgov>, n1617@conocophllips.com, Tim Lawlor <Tim Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, Crockett@aoga.org, Tamers Sheffield <sheffield@aogaorg>; Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belmar <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 <krlyons@suddenlink.net>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews <Iris Matthews@legisstate.ak.us>, Paul Decker: 1 of 2 1/17/2007 12:15 PM < aul decker dnr.state.ak.us>, Aleutians East Borough <admin@aleutian east.org>, Marguerite kremer p _ @ <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <Camille_Taylor@law.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 <jim_regg@admin.state.ak.us>, Catherine P Foerster <Cathy_foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.ne~, Laura Slliphant <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@dnrstate.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner<twaggoner@nrginc.com>, Mike Stockinger <Mike.Stockinger@anadarko.com>, John Spain yps@statesde.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegarner <jimwinegarner@brooksrangepetro.com> Jody Colombie <jody colombie cr,admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf Badami svs.pdf Content-Encoding: base64 2 of 2 1J17/2007 12:15 PM ~ Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Kay Munger Michael Parks 200 North 3rd Street, #1202 Munger Oil Information Service, Inc Marple's Business Newsletter Boise, ID 83702 PO Box 45738 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Seattle, WA 98119-3960 Mark Wedman Schlumberger Baker Oil Tools Halliburton Drilling and Measurements 4730 Business Park Blvd., #44 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Jill Schneider Land Department 9649 Musket Bell Cr.#5 US Geological Survey PO Box 93330 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough Williams Thomas PO Box 69 Arctic Slope Regional Corporation Barrow, AK 99723 Land Department PO Box 129 Barrow, AK 99723 ~~% '(/ ~1~ ~~ U . s U ~ 7 \~, AOGCC Memorandum Date: January 17, 2007 To: From: Jim Regg, Petroleum Engineer ~ I1~1~1 ~ `~~ Subject: Badami SVS -Proposed Rule Teleconference held this date to discuss the proposed Badami safety valve system (SVS) rule (addition to CO 402A}. As background, CO 402A is silent on SVS requirements and statewide regulations require SVS for a well with an onshore surface location at the Commission's discretion but only after notice and opportunity for hearing. Representing BP during the teleconference were Mike Bill, John Garing, Bob Younger, and Carolyn Kirchner; I was the only AOGCC representative. A draft of the proposed rule was sent to BP on January 12 for comment. Mike Bill led the discussion for BP and advised of only 2 concerns after review: (1) Test results submission requirements; (2) Requirement to install SSSV. Test Results BP suggested changing the time to submit test results from 7 days to 14 days (also suggested that . they currently do this monthly). I explained that the draft wording was copied directly from the proposed statewide regulations, and that was based on experience from Prudhoe and Kuparuk. I agreed to change the requirement to 14 days. SSSV Requirement The requirement for SSSV's in all wells at Badami is BP's biggest concern. Bob Younger stated that there are only 3 producers that have control lines for SCSSV -all other wells only have nipple profile for K-valve. I expressed confusion since info we have shows only the gas injector as having an actuated valve. Mr. Younger indicated that he did not think the gas injector had a SCSSV. Told BP reps that the discussion about surface controlled subsurface safety valve was moot point since we wrote the rule to be flexible enough (silent on control). Badami wells apparently have high paraffin content that requires "brush & flush" down to 4000 ft as frequent as every 5 weeks. This is a problem regardless of the type of SSSV; with a K-valve it would mean frequent pulling and reinstalling the valve -interventions always involve risk. BP is also not certain of the condition of the SSSV profile in the wells. A slickline unit is staged at Badami but there is no dedicated crew. An alternate offered by BP for consideration is the actuated wing valve downstream of the SSV. They were curious if the Commission would consider this; I told them I would discuss with Commissioner Foerster but suspect this is something that needs to be part of the public record the Commission will use for its decision. [This was confirmed in discussion with Commissioner Foerster following the teleconference]. The actuated wing valve is configured to ,~; close when the SSV closes; they could not confirm if the wing has been tested. This would not represent an equivalent to the SSSV but does provide another surface barrier in the event of a flowline failure. Other points discussed regarding SSSV requirements were the no flow test criteria (BP reps indicated the wells will flow to surface and thus would not meet the no flow criteria for excluding the SSSV) and the installation of a SSSV will create a backpressure condition that would restrict the already low flow rates. BP also mentioned the subject of administrative approvals regarding safety valves. I explained that we could only grant an administrative approval to something that exists in the Conservation Order. Sensing a desire from BP to avoid a hearing, I used this opportunity to explain that the Commission is convinced that a SVS requirement is necessary for Badami. The public hearing is the only way the Commission can institute SVS rules at Badami. The hearing is intended to provide the forum to gather the information the Commission needs to make awell-informed decision about SVS requirements at Badami. BP should be prepared to discuss concerns about the. proposed SSSV requirements, risks and alternatives. The Commission will consider the information BP wishes to enter into the public record that supports adjusting the proposed rule. ~~ . ~ ~ •~.: Subject: Re: Badami SVS Hearing J~rom: JamesRE~g <jii~~_regg~~a~min:state.ak.tl Date: -Fri; 12 Jan 2007 15:27:5b -0900. Ta' ,'Bi~1, Michael L (Natchiq)"`<Mici~acl.Bill~« hp.cun~ CC: "Engel, HarrgR" <Harry.Engel(~i'hi~.con~-=. "C;.u-in~~-John U" "Jc~hn.Garin~ crhh.cc~rl~~ Here's the proposed Badami SVS rule for your review; our intent is to notice this next week. As indicated in email yesterday, we will be vacating the 1/25 hearing in the notice for the 2/22 hearing. Final outcome would be CO 402B, superceding C0 402A. The SVS rule is Rule 6 (only part included in this email). I'd appreciate comments back no later than Wednesday since we have to notice this no later than Friday, 1/19. Jim Regg AOGCC Jim Bill, Michael L (Natchiq) wrote: Jim, From our discussion last week, I understood the Badami SVS hearing would be postponed until about 2/22. The current hearing calendar on the AOGCC website still shows the hearing date as 1/25. Please confirm that the hearing will indeed be held on or about 2/22. Also, I've been asked if you will still be able to provide the "straw man" rule for Badami. Thanks for you help, Mike Bill GPB Wells Group 907-564-4692 office 907-564-5510 fax __ __ Content-Type: application/msword badami~roposed_SVS_rules_(C0402B).doc Content-Encoding: base64 ___ __ 1 of 1 1/12/200'7 3:28 PM Rule 6 Automatic Shut-in Equipment a. All completed wells except water source wells, disposal injection wells (wells used for disposal of oilfield wastes), and monitor wells must be equipped with a commission approved safety valve system, except when the well's production or injection zone is mechanically isolated from the atmosphere or during well workover or intervention operations. b. The safety valve system must include: 1. A fail-safe surface safety valve with actuator, and aloes-pressure pilot or low- pressure transmitter with the capability to shut in the well when the flow line pressure drops below the required system actuation pressure (for a development well, the required system actuation pressure is at least 50 percent of the inlet separator pressure or 25 percent of the flowing tubing pressure, whichever is greater; for gas injection wells, the required system actuation pressure is SO percent of the compressor discharge pressure). 2. A fail-safe subsurface safety valve, installed in the tubing string below the base of the permafrost and capable of preventing uncontrolled flow from the tubing. A well passing a no-flow performance test (no flow of hydrocarbons to surface) witnessed by a Commission representative is not required to have a subsurface safety valve. 3. A safety valve system control unit placed in a location that is readily available to human intervention. c. Safety valve systems must be maintained in good operating condition at all times and must be protected to ensure reliable operation under the range of weather conditions that maybe encountered at the well site; d. Safety valve systems must be tested at intervals of six months, not to exceed 200 days between tests unless the commission prescribes a different test interval. The commission must be given at least 48 hours notice for an opportunity to witness the tests. Results of the tests must be provided to the commission within 7 days in an electronic format. e. When well workover or intervention operations require it, the subsurface safety valve may be blocked or removed; however, unless otherwise authorized by the commission, the subsurface safety valve must be made operable immediately after completion of well operations and tested within 48 hours, unless the well is shut in. f. The surface safety valve and the low pressure pilot or low pressure transmitter may be removed or defeated only when the well is shut in or pad is continuously manned by a person trained in well operations. Subject: R;E Badami SVS Hearing From: "Bi1~; Michael L {Natchiq)" <Michael.Bill~r~bp:co111> Date: Thu, 11 Jan 2007 15:57:16 -0900 To: JainesRegg<jinn_regg~r~,adinizi.stat~.~~k.u~ Thanks Jim Mike Bill GPB Wells Group 907-564-4692 office 907-564-5510 fax From: James Regg [mailto:jim_regg@admin.state.ak.us] Sent: Thursday, January 11, 2007 3:30 PM To: Bill, Michael L (Natchiq) Cc: Engel, Harry R; Garing, John D Subject: Re: Badami SVS Hearing The 1/25 hearing will be vacated in the public notice for the 2/22 hearing. That should be published next week. I have a draft rule that will be sent to you for review in next day or so. Jim Regg AOGCC Bill, Michael L (Natchiq) wrote: Jim, From our discussion last week, I understood the Badami SVS hearing would be postponed until about 2/22. The current hearing calendar on the AOGCC website still shows the hearing date as 1/25. Please confirm that the hearing will indeed be held on or about 2/22. Also, I've been asked if you will still be able to provide the "straw man" rule for Badami. Thanks for you help, Mike Bill GPB Wells Group 907-564-4692 office 907-564-5510 fax 1 of 1 1/12/2007 3:28 PM Im ",.~.,~ AOGCC Memorandum Date: To: From: Subject 12/27/2006 Commissioners Jim Regg, Petroleum Engineer Badami Hearing -Safety Valve System Requirements We sent a letter to BP dated 12/21/2006 advising that the Commission will not take enforcement action for failure to test well safety valve systems on a 90 day frequency following an excessive failure rate at Badami. AOGCC witnessed safety valve system tests in Apri12006 and found a failure rate in excess of 37%. Instead, we announced to BP that a hearing has been scheduled to address safety valve system requirements. Harry Engel (BP; 564-4194) called today asking what motivated the letter and the call for a hearing (as if it were not obvious in the letter). I explained the history of high safety valve system failure rates, the wells with repeat failures, and the lack of specific rules addressing safety valve systems at Badami. I also referred him to 20 AAC 25.265(c) which says the Commission will impose safety valve system requirements for wells with onshore surface locations only after notice and opportunity for hearing. Mr. Engel said BP would prefer to work this out without hearing; I don't see how that is possible. He asked about a delay of the January 25 hearing so appropriate BP staff can prepare and suggested a meeting before the hearing to make sure they know what should be addressed. I told him that a delay was a decision the Commissioners must make. He suggested meeting the first week of February and a hearing the end of the month. While it would be possible to clearly outline the issues in another letter, I recommend accommodating BP with a meeting before the hearing to discuss our expectations so they can properly prepare. I do not agree with his suggested timeline. We should target a meeting thew week of January 22 and reschedule the hearing no later than February 10. 1 f ~t ~~aa~p1 1~~~ ~~ w~v 1aT December 21, 2006 MAILED CERTIFIED MAIL 7005 1160 0001 5753 9394 Mr. Craig Wiggs Badami Performance Unit Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Badami Automatic Shut-in Equipment Dear Mr. Wiggs: saR~H ~.a~rr~, GOVERArOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 The Alaska Oil and Gas Conservation Commission ("Commission") advised BP Exploration (Alaska) Inc. ("BPXA") of an ongoing investigation regarding Badami operations. The Commission's November 2, 2006 letter identified the installation, operation and testing of automatic wellhead shut in equipment as the focus of this investigation. BPXA's response dated November 16, 2006 provided additional information about the Badami testing that triggered this investigation. Wellhead safety valve system ("SVS") test performance beginning in April 2006 was the specific focus for this investigation. The Commission has completed its review of SVS testing at Badami and will not take any enforcement action for the high component failure rate. Instead, a hearing will be convened to address the proper requirements for SVS's at Badami. Safety valve system ("SVS") testing witnessed by a Commission Inspector on April 6, 2006 resulted in a component failure rate of 37.5 percent. When factoring in test results of 3 additional wells brought on line April 28, May 24, and July 23, 2006, the SVS component failure rate decreases to 20 percent. Retest results are not factored into the failure rate calculations. Commission requirements for SVS testing call for the pad test frequency to be increased to every 90 days when the component failure rate exceeds 10 percent. Based on information provided, Badami SVS tests were next performed in October 2006 giving the appearance of a violation of Commission requirements to test every 90 days. Amore detailed review of Badami operations indicates the pad has a ice, • Mr. Craig Wiggs December 21, 2006 Page 2 of 2 history of poor SVS performance since initial production began in 1998 and more recently since production restart in 2005 after a 2-year shut in. Regulations, statutes, individual well permits, rules contained in conservation and injection orders, and plans of development have been reviewed to determine what SVS requirements have been established for the Badami Field. It appears the Commission has remained silent on SVS requirements. This is inconsistent with all other North Slope Fields where SVS requirements include at a minimum an actuated surface safety valve system that is tested every 180 days for each producing well. There is no apparent reason why Badami should have less stringent requirements except for references in the hearing record for Conservation Order 402 that BPXA will seek additional rules governing, among other things, completion and production practices prior to Badami startup. Subsequent Area Injection Order 17 and Conservation Order 402A (both August 1998) failed to address SVS requirements. Safety valve system regulations (20 AAC 25.265(c)) specify the following: "The Commission will, in its discretion, require an SSV system, an SSSV system, or both on a well with an onshore surface location, meter notice and an op rtunit~ for hearing in accordance with 20 AAC 25.540. " [emphasis added] The Commission will convene a hearing on January 25, 2007 to establish clear SVS requirements for the Badami Field. BPXA will be given the opportunity to testify before the Commission and provide recommendations. You may be aware that the Commission is currently preparing a draft revision of the safety valve regulations in 20 AAC 25.265. Several key BPXA personnel have had an opportunity to review early drafts and to provide comments for Commission consideration; an early draft was offered for comment and discussed informally at the Commission's monthly public hearing held September 27, 2006. Some of the requirements in the draft SVS rule may be applicable. to Badami operations, notably requirements for safety valve systems that include both surface and subsurface safety valve systems for all producing and hydrocarbon injection wells. Testing of the SVS would occur every 180 days consistent with Commission-imposed requirements statewide where wells require a SVS. Attached is a copy of the public notice for the hearing. Should you have any questions about this process, please feel free to contact Jody Colombie, Special Assistant to the Commission at (907) 793-1221. Attach. Chairman t ~ i ~"' ~'n~nce ~f J'u~la~ l~earang S'J'AT~ ®F A~.A~~ Alaska did and has ~oa~se¢~aga®an Com~flssg®n lie: Mules governing safety valve system requirements at the Badami Field The Alaska Oil and Gas Conservation Commission ("Commission"), on its awn motion, proposes to clarify safety valve system requirements for the Badami Field on the I~Torth Slope of Alaska. Safety valve system requirements, according to 20 A.~LC 25.26 will be established for wells with onshore surface locations at the discretion of the Commission upon public notice and opportunity for hearing. The Commission is proposing to establish safety valve system requirements that include both surface and subsurface safety valve systems for all producing and hydrocarbon injection wells. Testing of the SVS would occur every 1~0 days consistent with Commission-imposed requirements statewide where wells require a SVS. The Commission has tentatively set a public hearing on this proposed action for January 23, 2007 at 9:00 am at the Alaska OiL and Gas Conservation Commission at 333 Nest 7`h 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 January 10, 2007. If a request for a hearing is not timely filed, the Commission will consider the issuance of orders without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit written comments regarding these proposed actions to the Alaska Oil and Gas Conservation Commission at 333 West 7`h Avenue, Suite 100, Anchorage, Alaska 99501. `Vritten comments must be received no later than 4:30 pm on January 23, 2007, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on January 25, 2007. If you are a person with a disability who comment or to attend the public hearing, I accommodations in order to Colombie at 793-1221. N Published Date: December 22, 2006 AD;\+ Afl# 02714014 MLI STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING ORDER 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 A 0-02714014 /'"~ SEE BOTTOM FOR INVOICE ADDRESS F R AOGCC Ste 100 333 W 7th Ave AGENCY CONTACT Jod Colombie DATE OF A.O. December 21 2006 ° M , Anchorage, AK 99501 _ PHONE PCN DATES ADVERTISEMENT REQUIRED: o The Anchorage Daily News December 22, 2006 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classif ied ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 Anchor e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN s ARD 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIQ ~ OS 02140100 73451 2 3 4 , ...._ .., r , REQUISITIONED B ;' ?'' ~~ ,. '' DIVISION APPROVAL: 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM i ,~ Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Rules governing safety valve system requirements at the Badami Field The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to clarify safety valve system requirements for the Badami Field on the North Slope of Alaska. Safety valve system requirements, according to 20 AAC 25.265 will be established for wells with onshore surface locations at the discretion of the Commission upon public notice and opportunity for hearing. The Commission is proposing to establish safety valve system requirements that include both surface and subsurface safety valve systems for all producing and hydrocarbon injection wells. Testing of the SVS would occur every 180 days consistent with Commission-imposed requirements statewide where wells require a SVS. The Commission has tentatively set a public hearing on this proposed action for January 25, 2007 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7m 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 January 10, 2007. If a request for a hearing is not timely filed, the Commission will consider the issuance of orders without a hearing. To learn if the Commission will hold the public hearing, please ca11793-1221. In addition, a person may submit written comments regarding these proposed actions to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on January 23, 2007, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on January 25, 2007. If you are a person with a disability who comment or to attend the public hearing, f accommodations in order to Colombie at 793-1221.. N~ Published Date: December 22, 2006 ADN AO# 02714014 Anchorage Daily News ~~~~~''10i Affidavit of Publication 1001 Northway Drive. Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD # DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 59201 '12/22/2006 027740"14 STOF0330 $186.44 $186.44 $0.00 $0.00 $0.00 $0.00 $0.00 $186.44 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 published in the English language continually as a daily newspaper u1 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 a>nount of the fee charged for the foregoing publication is not in excess of the rate charged nrivaTv inrlivirlualc. Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: ~ _ crrr~ `~,`.j.~. • • •~• • . O r. ~, ~ . .~- G .~, V .~ •. ,~• 1 J'JJJ~~IJIlIJ~111~~~,~1 Notice of Public Hearing STATE OF ALASKA - Alaslld Qif and :Gas Conservation:commission ~.. Re:~ Rules eoverning safety valve system requirements of TheBadami Field The Alaska Oil and Gas Conser~atlorr_Commission ("Commission"), on its owo motion; proposes To Clarify safety valve system I;equ.'IrCmEnts for the 8adaml Field on the North Slope of Alask-a. Safety valve system requirements, accordirtgto 20 AAC 25.265 will be established for wellswithonshore sut'- face locations at the discretion of the Commission upon public notice and opportunity for hearing. The Commiss.ion is proposing to establish safetvvalve system requirements that include both surface and subsurface safety valve systems for all producing' and hydrocarbon infection wells. Testing of the SVS would occur every 180 davscbhsistent with CorrSrttl~s-• Sion-imposed requirements statewide whera.well~,. require a SXfS. ' _ i f The Commission has tehTatively. set a public heigr,, ing on this proposed action for Jcinuary 25, 2007 pf 9:004tn:atdthe'-Alaska OH'-and Gas<Conservatoti Commission at 333 West 7Th Avenue, Suite 100, An- chorage, Alaska 99501. A person mas°regoestthat the Tentatlvelv.54heduled hearing be heldbv fil(ng a~~ written`r•equesYwith the Commission no later than. 4:30 pm on January 10, 2007. If a request fora hearing is not timely filed, the Commission will consider the issuance of orders without a hearing: To learn if.the Commission will hold the public hearing,-please call 793-1221. In addition,a person may sutimiT written comments regarding these proposed actions to the Alaska.0il and Gas Conservation Commission at 333 West 7th Avenue, Suite-100, Anchorage, Alaska 99501. 'Writ- ten comments must be received no later Than 4:30 pm on Jdriuarr23, 2007, except that if The Commis- sion decides to'hold a public hearing, written com- ments must, be received no later than 9:00 am on January 25, 2007. If'YOU are a persahwlth a disability who may need SpeClal gCWntmad ClYiarlS In OrdeY t0 COm meat OrtO attend the public hearing, please contact Jodv Co- lombie aT 793.122E /s/: John K. Norman Chairman ADN AO#92714014 P.ubllshed Date: December 22 2006 Subscribed a/nd sworn to me before this date: STATE OF ALASKA , ,. NOTICE TO PUBLISHER ADVERTISING ORDER NO. ~~ ~ ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /f, O_02714014 /'1 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRES3 F AOGCC AGENCY CONTACT DATE OF A.O. R Suite 100 333 West 7~' Avenue ° . Anch~raue_ AK 9A5~1 PHONE PCN "' 907-793-1221 - DATES ADVERTISEMENT REQUIRED: o The Anchorage Daily News December 22, 2006 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN TfS ENTIItETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed AFFIDAVIT OF PUBLICATION United states ofAmerica REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2006, and thereafter for consecutive days, the last publication appearing on the day of , 2006, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This ,day of 2006, Notary public for state of My commission expires UBLISHER Subject: Public Notice From: Jody Colombie <Jody_colombie@admin.state.ak.us> Date: Thu, 21 Dec 2006 15:07:08 -0900 To: Legal Ads Anchorage Daily News <legalads@adn.com> Please publish tomorrow. Jody Jody Colombie <jody colombie~admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/msword Ad Order form.doc Content-Encoding: base64 Content-Type: application/msword badami svs_hearing_notice.doc Content-Encoding: base64 ~ „f ~ 12/21/2006 3:07 PM George Vaught, Jr. Jerry Hodgden i .Richard Neahring PO Box 13557 ~'~ Hodgden Oil Company °^"' NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Kay Munger Michael Parks 200 North 3rd Street, #1202 Munger Oil Information Service, Inc Marple's Business Newsletter Boise, ID 83702 PO Box 45738 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Seattle, WA 98119-3960 Mark Wedman Schlumberger Baker Oil Tools Halliburton Drilling and Measurements 4730 Business Park Blvd., #44 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Jill Schneider Land Department 9649 Musket Bell Cr.#5 US Geological Survey PO Box 93330 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough Williams Thomas PO Box 69 Arctic Slope Regional Corporation Barrow, AK 99723 Land Department PO Box 129 Barrow, AK 99723 i~~ ~a ~~~ ~ Subject: RE: Public Notice From: "Ads, Legal" <legalads@adn.com> Date: Thu, 21 Dec 2006 15:22:50 -0900 To: Jody Colombie <jody_colombie@admin.state.ak.us> Hello Jody: Following is the confirmation information on your legal notice. Please revierw and let me know if you have any questions for need additional information. Account Number: STOF 0330 Legal Ad Number: 89201 Publication Date(s): December 22, 2006 Your Reference Number: 02714014 Total Cost of Legal Notice: $186.44 Thank You and Happy Holidays, Kim Kirby Legal Classified Representative E-mail: l~alads@adn.com Phone: (907) 257-4296 Fax: (907) 279-8170 -----Original Message----- From: Jody Colombie [mailto:jody colombie@admin.state.ak.us] Sent: Thursday, December 21, 2006 3:07 PM To: Ads, Legal Subject: Public Notice Please publish tomorrow. Jody 1 of 1 12/21/2006 3:55 PM 3 S~4RAhl P.4LlfV, GOVERiVOR ~e ~~11 ~~ ~+ December 2 I , 2006 MAILED CERTIFIED MAIL 7005 1160 0001 5753 9394 Mr. Craig Wiggs Badami Performance Unit Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Badami Automatic Shut-in Equipment Dear Mr. Wiggs: 333 W. 7th AVENUE, SUITE 100 ANCHORAGE,AIASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 The Alaska Oil and Gas Conservation Commission ("Commission") advised BP Exploration (Alaska) Inc. ("BPXA") of an ongoing investigation regarding Badami operations. The Commission's November 2, 2006 letter identified the installation, operation and testing of automatic wellhead shut in equipment as the focus of this investigation. BPXA's response dated November 16, 2006 provided additional information about the Badami testing that triggered this investigation. Wellhead safety valve system ("SVS") test performance beginning in April 2006 was the specific focus for this investigation. The Commission has completed its review of SVS testing at Badami and will not take any enforcement action for the high component failure rate. Instead, a hearing will be convened to address the proper requirements for SVS's at Badami. Safety valve system ("SVS") testing witnessed by a Commission Inspector on April 6, 2006 resulted in a component failure rate of 37.5 percent. When factoring in test results of 3 additional wells brought on line April 28, May 24, and July 23, 2006, the SVS component failure rate decreases to 20 percent. Retest results are not factored into the failure rate calculations. Commission requirements for SVS testing call for the pad test frequency to be increased to every 90 days when the component failure rate exceeds 10 percent. Based on information provided, Badami SVS tests were next performed in October 2006 giving the appearance of a violation of Commission requirements to test every 90 days. Amore detailed review of Badami operations indicates the pad has a ~~, Mr. Craig Wiggs December 21, 2006 Page 2 of 2 history of poor SVS performance since initial production began in 1998 and more recently since production restart in 2005 after a 2-year shut in. Regulations, statutes, individual well permits, rules contained in conservation and injection orders, and plans of development have been reviewed to determine what SVS requirements have been established for the Badami Field. It appears the Commission has remained silent on SVS requirements. This is inconsistent with all other North Slope fields where SVS requirements include at a minimum an actuated surface safety valve system that is tested every 180 days for each producing well. There is no apparent reason why Badami should have less stringent requirements except for references in the hearing record for Conservation Order 402 that BPXA will seek additional rules governing, among other things, completion and production practices prior to Badami startup. Subsequent Area Injection Order 17 and Conservation Order 402A (both August 1998) failed to address SVS requirements. Safety valve system regulations (20 AAC 25.265(c)) specify the following: "The Commission will, in its discretion, require an SSV system, an SSSV system, or both on a well with an onshore surface location, meter notice and an ~portunil~ for hearing in accordance with 20 AAC 25.540. " [emphasis added] The Commission will convene a hearing on January 25, 2007 to establish clear SVS requirements for the Badami Field. BPXA will be given the opportunity to testify before the Commission and provide recommendations. You may be aware that the Commission is currently preparing a draft revision of the safety valve regulations in 20 AAC 25.265. Several key BPXA personnel have had an opportunity to review early drafts and to provide comments for Commission consideration; an early draft was offered for comment and discussed informally at the Commission's monthly public hearing held September 27, 2006. Some of the requirements in the draft SVS rule may be applicable to Badami operations, notably requirements for safety valve systems that include both surface and subsurface safety valve systems for all producing and hydrocarbon injection wells. Testing of the SVS would occur every 180 days consistent with Commission-imposed requirements statewide where wells require a SVS. Attached is a copy of the public notice for the hearing. Should about this process, please feel free to contact Jody Colombie, Commission at (907) 793-1221. you have any questions Special Assistant to the Attach. Chairman ^ Complete items 1, 2, and 3. Also complete A. Signature item 4 if Restricted Delivery is desired. X ~~Agent ^ Print your name and address on the reverse _ ~ ^ Addressee so that we can return the card to you. B. Receiv by (Print a~ C. Date of Delivery ^ Attach this card~fo the back of the mailpiece, or on the frog space permits. - Z 1. Article Addressed to: D. Is d ivery address different from item 1? ^ Yes // / If YES, enter delivery address below: ~No ~/'C~ l G~/~~~ 3. Se ice Type i~~~ ~ ~/,) ~ ~ ~ ~ertified Mail ^ Express Mail ~V c.~ ~ ^ Registered ~(ieturn Receipt for Merchandise /~/I~ ~~ ,i /,- ^ Insured Mail ^ C.O.D. '/~~ G~ i / '~ f/~ (//f 4. Restricted Delivery? (Extra Fee) ^ Yes 2. Article Number (rransferfiomservic~ 7p05 11,60 0001 5753 9394 PS Form 3811, February 2004 Domestic Return Receipt ..,.,~..~ ,,., .. ,..._ -J O D IJ1 ~~.'' ~~ 5lV•~i J. ~~ f- d1a ' H ' 5$`~$ i ~ a sod "~ ~ ~ . j~ ~~~~~ LC) saed +g a6Etsod IElol ~ (paimbay ~uewesiopu3) ~' aad Nanllep petautsed O (pailnbat{ tuawas~opug) ~ sed>dlaoaawnled ~ O aad peUlUa3 ~ e6E;sod 1.r1 -~.l ~s~`, iW :e~~i, ~jj~p;ll~ w MMM ~E,(,a~ISC~~`Jn0 3151A ,uoljt±wav;u i..r _.tl~~. ~ s•. ,, ., : sus a ~ to 6eaano~ aaue~~au1~41~ `~~u0 pe/~,~-L~•~, ~ 4',~ ~ ~_' ~(a ;~.<'`~~ d~1;~33 `"'~1}I!.~.`-.1~111r~®~~~ll~l~. f. ~._ ~ ~ ~ _ - `'~..; lei®tic¢ ®P PulBlic Hea¢°ing STATE ®F AIt.ASKA Alaska ®il a~ad Gas ~®nservati®n ~o~na~aaissi®n Re: Rules governing safety valve system requirements at the Badami Field The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to clarify safety valve system requirements for the Badami Field on the North Slope of Alaska. Safety valve system requirements, according to 20 AAC 25.265 will be established for wells with onshore surface locations at the discretion of the Commission upon public notice and opportunity for hearing. The Commission is proposing to establish safety valve system requirements that include both surface and subsurface safety valve systems for all producing and hydrocarbon injection wells. Testing of the SVS would occur every 180 days consistent with Commission-imposed requirements statewide where wells require a SVS. The Commission has tentatively set a public hearing on this proposed action for January 25, 2007 at 9:00 am at 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 January 10, 2007. If a request for a hearing is not timely filed, the Commission will consider the issuance of orders without a hearing. To learn if the Commission will hold the public hearing, please ca11793- 1221. In addition, a person may submit written comments regarding these proposed actions to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on January 23, 2007, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on January 25, 2007. If you are a person with a disability who comment or to attend the public hearing, I accommodations in order to Colombie at 793-1221. Published Date: December 22, 2006 ADN AO# 02714014 L174 by ~- Craig L. Wiggs Performance Unit Leader - Northstar/EndicottlBadami ~~., ~ ~•~~ gP Exploration (Alaska) Inc. Alaska Consolidated Team (ACT) RR II ~~11 900 East Benson Boulevard EVV~ ~ ~~1~.,.3 AnOc o~age,Alaska99519-6612 (907) 561-5111 ~I~~~~ ~~ ~` ~ '' '~ ~"` !' ~~ione: (907) 564-5107 Fa~6$3~§a#~~~~ Fax: (907) 564-4441 Email wiggscl1 @bp.com November 16, 2006 Web: www.bp.com Mr. John K. Norman State of Alaska Alaska Oil and Gas Conservation Commission 333 W. 7t" Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: Badami Automatic Shut-in Equipment Dear Mr. Norman: In response to your letter dated November 2, 2006, BP has completed a review of the Badami SVS test reports dating back to September, 2005, and the results indicate we are compliant with 20 AAC 25.265. Today, BP has 6 active wells with a total of 13 SVS components. There have been a number of tests and retests on the SVS system during the past 14 months, including some witnessed test/retest periods that were completed within a one month period. For instance, on April 6, 2006 there were 8 components tested and 3 of those components failed the witnessed test, yet by the end of the day all components passed. Then on April 28, 2006 these wells and others were retested, resulting in a failure rate of 10%. Per 20 AAC 25.265, these wells were retested within the required 90 days with a failure rate allowing resumption of a 180 day test schedule. As requested, the test data dating back to September, 2005 is attached. We recognize that not all SVS test reports have been sent to the commission in a timely manner. This has been corrected. In addition, we have taken the following action to improve the reliability of the SVS components on the Badami wells: • Replaced the hydraulic pilot on well B1-14 with an electric pilot to improve reliability • Rebuilt the SSV on well B1-14 to improve reliability • Increased SVS valve greasing frequency to every 6 months ,. Mr. John K. No,.~..~an State of Alaska Alaska Oil and Gas Conservation Commission November 16, 2006 Page 2 • SVS valves will be stroked every 5 to 8 weeks during wellbore paraffin clean-out procedures • Maintain Badami SVS testing on a 90-day frequency for several quarters until reliability of the system is demonstrated Review of the data internally, and with Alaska state inspectors has cleared our confusion regarding SVS test results. For instance, BP operations assumed that test results on a component that had a "fail" and "pass" on the same day were interpreted overall as "pass". The state inspectors have now clarified that a "pass" and "fail" on a component test completed on the same day should still be counted as a "fail" for the failure rate calculation. Overall, BP believes that the actions taken will improve the Badami SVS test results to an acceptable pass rate. Clarification of test data, and improvements in our reporting processes have been implemented. As requested, the following supporting documentation has been included for your review: Attachment 1: Copies of all SVS tests beginning September 2005 Attachment 2: Documents relating to repairs to SVS components Attachment 3: BPXA's policies and procedures at Badami If you have any questions regarding the content of this letter, or require additional information on the Badami SVS system, please contact John Caring at 564-5167. Sincerely, Craig Wiggs Attachments: cc: John Caring Badami File ~~, Attachment l: Copies of all SVS Tests Beginning September 2005. • Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPX Submitted By: Melody Broacha Date: 9/19/2005 Operator Rep: Bruce Clemens Field/Unit/Pad: Badami/B 1 AOGCC Rep: Waived Separator psi: LPS HPS Well Data Pilots SSV SSSV est /Retest /SI Date Well Type Well Permit Separ Set UP Test Test Test Date Tested and or oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed Retest or SI GAS, CYCLE, si BI-01 1971570 B1 -14 1980630 4500 2000 2000 P P P 9/19/2005 GINJ Wells: 1 Components: 3 Failures: 0 Failure Rate: 0.00% ❑ 90 Day Remarks: B1 -14 9/19/2005: Pilot would no reset on startup, replaced and retested same day RJF 09/19/02 Page 1 of 2 SVS BAD B1 9- 19- 05.xis SVS Test Event Edit Page 1 of 2 SVS Test Event Edit • Badami -> Pad 1131 Test Date Test Type 19- SEP -05 Routine , AOGCC Representative [add] BP Representative [add] None Bruce Clemens High Pressure Low Pressure 172 Test Event Comments B1 -14 wouldn't take the SSSV code when I first entered it, so it defaulted to failed. I changed it today 09/23/05. Well Well Sep. Set Trip Pilot SSV SSSV Skip Name Status Pre PSI PSI Test Test Test Retest Well Test Comments Code Code Code B1 -01 OIL P P M M ❑ B1 -03 OIL P P ® ■ ❑ 125 120 P ®P ® ❑ Tested before being brought online Bl-11 OIL OF180 B1 -14 GIN] 4500 2000 2000 P M P ■ P 0 ITested before being brought online B1 -15 OIL 180 125 125 P ® P ■ M ❑ ITested before being brought online B1 -16 OIL P ® P ® M ❑ B1 -18 OIL ® 58 - 6 -- T - 2 - 5 -- ] 116 P M P M 0 ❑ ITested before being brought online B1 -21 OIL P P ® ® ❑ B1 -23 OIL ■ P i P ® . ❑ B1 -25 OIL P M P M ■ ❑ B1 -28 OIL ® 0 0 0 P i P M ■ ❑ B1 -36 OIL ® 172 125 100 P P ® ❑ BADAMI- OIL P P ❑ 01 BADAMI- OIL P P , ❑ 02 BADAMI- OIL P ® P ■ ❑ BADAMI- OIL 05 P P ❑ Update Delete Generate Report Cancel Notes: • Enter date, participating parties, and separator pressures as needed. • Press the Save button to post your changes to the database. • Press the Delete button to remove this Test Event and all test values recorded for this event from the http: / /apps2- alaska. bpweb .bp.conVsst %5Fdrilling %5Fwells / safety_ valves2 /frmTestEventEdit.asp ?PadTes... 11/14/2006 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPXA Submitted By: Melody Broacha Date: 10/5/2005 Operator Rep: Bruce Clemens Field/Unit /Pad: Badami/B 1 AOGCC Rep: Waived Separator psi: LPS HPS Well Data Pilots SSV SSSV est /Retest /SI Date Well Type Well Permit Separ Set UP Test Test Test Date Tested and or oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed Retest or SI GAS, CYCLE, SI BI-01 1971570 B1 -21 1971740 200 125 125 P P OIL Wells: 1 Components: 2 Failures: 0 Failure Rate: 0.00% ❑ 90 Day Remarks: B1 -21 shut in pressure 1000 psi. Line bled off to 255 psi. No leakage on SSV. Badami producing wells have no SSSV's. RJF 09/19/02 Page 1 of 2 SVS BAD B1 10 -05 -05 MISC.xls 0 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPXA Submitted By: Melody Broacha Date: 10/20/2005 Operator Rep: Bruce Clemens Field/Unit/Pad: Badami/B 1 AOGCC Rep: Lou Grimaldi Separator psi: LPS HPS Well Data Pilots SSV SSSV est /Retest /SI Date Well Type Well Permit Separ Set UP Test Test Test Date Tested and or oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed Retest or SI GAS, CYCLE, sI BI-01 1971570 B1-11A 1980340 200 1251 110 P P 011L B 1 -15 1980740 200 125 120 P P OIL, B1 -18 1980120 200 125 120 P P OIL B1 -36 19823201 200 125 120 P P JOEL Wells: 4 Components: 8 Failures: 0 Failure Rate: o.00% ❑ 90 Day Remarks: Badami producing wells have no SSSV's. RJF 09/19/02 Page 1 of 2 SVS BAD B1 10 -20 -05 MISC.xls Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPXA Submitted By: Melody Broacha Date: 10/21/2005 Operator Rep: Bruce Clemens Field/Unit/Pad: Badami/B 1 AOGCC Rep: Lou Grimaldi Separator psi: LPS HPS Well Data Pilots SS V SSS V est /Retest /SI Date Well Type Well Permit Separ Set UP Test Test Test Date Tested and or Oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed Retest or SI GAS, CYCLE, SI BI-01 1971570 B1 -14 1980630 3700 2000 1900 43 P GINJ B1 -15 1980740 2001 500 460 P P OIL B1 -18 1980120 200 500 485 P P OIL B 1 -21 1971740 200 125 120 P P OlL Wells: 4 Components: 8 Failures: 1 Failure Rate: 12.50 -C 90 Day Remarks: B 1 -14 Pilot frozen, thawed and retested ok. B 1 -15 passed first test with pilot set at 125 p! Grimaldi recommended 2nd test at 500 psi. B 1 -18 passed first test with pilot set at 125 psi Grimaldi recommended 2nd test at 500 psi. B1 -21 passed all three tests, Grimaldi recomme new downstream sensor. RJF 09/19/02 Page 1 of 2 SVS BAD B1 10 -21 -05 MISC.xls Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: Submitted By: Date: Operator Rep: Field/Unit/Pad: AOGCC Rep: ..Latj Separator psi: LPS HPS. Z 1 .. . .. ...... Well Permit Separ Set UP Test Test Test Date Tested and or Oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed Retest or SI GAS, CYCLE, S1 B1 -11A 1980340 17S 0//'5 v/ JP�Y .131-�14 1980630 & o 300 , 0 -15 1980740 125 t o B1 -16 1980800 NIA BI-18 1980120 125 B1 -21 1971740 3000 BI-25 1981530 125 BI-28 1981300 125 BI-36 19823201/7 125 /;ZD 1 77 Wells: 9 Components: 0 Failures: 0 Failure Rate: #DIV/OCI 90 Day Remarks: Well B -16 has been shut-in since 1999 due to low productivity. a-11 A_1qPjL6 5c]�: '5SV 4.Egueb C ZC4f J�! C-5 1 k> t dD RIF 09%119/ P a V- 1 Lis-jec Form 2002PS.I.xls f T Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPX Submitted By: Melody Broacha Date: 4/28/2006 Operator Rep: Bruce Clemens Field/Unit/Pad: Badami/B 1 AOGCC Rep: Lou Grimaldi Separator psi: LPS HPS Weil lata� : '`Fcldts _ S,5'S. esli etest/S Well Permit Separ Set UP Test Test Test Date Tested and or Oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed Retest or SI GAS CYCLE SI BI-01 1971570 B1-11A 1980340 165 100 85 P P OIL B1 -14 1980630 4800 2750 2000 3 P WAG B 1 -15 1980740 165 100 105 P P B1 -16 1980800 a 12/21/2005 SI B1 -18 1980120 165 100 95 P B 1 -21 1971740 12/7/2005 SI B1 -25 1981530 7/29/2003 SI B1 -28 1981300 7/29/2003 SI B1 -36 1982320 165 1251 125 P P Wells: 5 Components: 9 Failures: 1 Failure Rate: 90 Day 1 0 7o Remarks: B 1 -14 4/28/2005: Work order submitted to change "P" pilot ti 01'f T o S5 v' T,j WHJA) r� 5 fqf f7 W 5 F /l.£ 0- �ci p 615 4 /L ✓r-V -V ?`H� L.,, t,J 4 5 ro RJF 09/19/02 Page 1 of 2 SVS BAD B 4- 28- 06.xls 00 Safety Va1Ve & well Pressures Test Repoit Pad: BADAM Insp Dt 4/29/2006 Inspected by Lou Grimaldi interval 129PNO sysL0060429110446 Related Insp. Field Name BADAMI Operator BP EXPLORATION (ALASKA) INC Operator Rep Schumway Reason Retest Src: Inspector W V WA li Well Permit Sqw Set 1R Test Test Ted Date SI OiLWAG.01M, Inur Outer Tubing Number Number —PSI PSI Trip ..Code• Code code_ GAS.CYCLE, SI PSI PSI PSI Yes/No Yes/No B1 -11A 1980340 1651 100 1 85 P P I-OIL 1000 150 170 Yes No BI-14 1980630 480q 30 P IGINJ 600 250 5000 No No Old style T" pilot presently used Work order has been submitted to use electronic transmitter on injection line BI -15L1 1980750 165 100 105 P P I-OIL 900 500 190 yes No for LP trip. B1 -18 1980120 165 100 95 P P 1-OIL 1400 350 170 Yes No B1 -36 1982320 165 125 125 P P 1-011, 1000 0 190 Yes No Comments Performance Good tcAL LP pilot on B1 -14 had to be cycled 4 times to bring up to 2750 psi trip. Work order in system to Change to electronic transmitter on flow line, sbould make a more reliable LPS. Wells Components Failures Failure Rate 0 0 0 Friday, April 28, 2006 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPX Submitted By: Melody Broacha Date: 4/28/2006 Operator Rep: Bruce Clemens Field/Unit/Pad: Badami/B 1 AOGCC Rep: Lou Grimaldi Separator psi: LPS 4800 HPS Well Permit Separ Set UP Test Test Test Date Tested and or Oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed Retest or SI GAS, CYCLE, SI B 1 -01 1971570 B 1 -14 19806301 4800 27501 2750 P P GINJ Wells: 1 Components: 2 Failures: 0 Failure Rate: 0.00% ❑ 90 Day Remarks: B1 -14 Passed retest same day as failure RJF 09/19/02 Page 1 of 2 SVS BAD B1 4 -28 -06 RETEST.xls Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPX Submitted By: Melody Broacha Date: 5/24/2006 Operator Rep: Bert Green Field/Unit/Pad: Badami/B 1 AOGCC Rep: Waived Separator psi: LPS 170 HPS Well Permit Separ Set UP Test Test 7Cod7ePassed. Date Tested and or Oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Retest or SI GAS, CYCLE, SI B 1 -01 1971570 B 1 -21 1971740 170 125 1251 P P P 011- Wells: 1 Components: 3 Failures: 0 Failure Rate: 0.00% ❑ 90 Day Remarks: RJF 09/19/02 Page 1 of 2 SVS BAD B1 5 -24 -06 MISC.xls Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPX Submitted By: Melody Broacha Date: 7/23/2006 Operator Rep: Burnett Stuteer Field/Unit/Pad: BadamiB 1 AOGCC Rep: Waived Separator psi: LPS 169 HPS Well Permit Separ Set UP Test Test Test Date Passed Retest oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Or Date Shut In GAS, CYCLE, SI B 1 -01 1971570 B1 -16 1 1980800 169 125 123 P P OIL Wells: 1 Components: 2 Failures: 0 Failure Rate: 0.o0% ❑ 90 Day Remarks: B 1 -16 POP 7/23/06 RJF 12/21/04 Page 1 of 2 SVS BAD B1 7 -23 -06 MISC WAIVED.xls Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPX Submitted By: Melody Broacha Date: 8/6/2006 Operator Rep: Bruce Clemens/ Field/Unit/Pad: Badami/B 1 AOGCC Rep: Waived Separator psi: LPS 40 HPS Well Permit Separ Set UP Test Test Test Date Passed Retest oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Or Date Shut In GAS, CYCLE, SI BI-01 1971570 B1 -16 1980800 481 40 381 P OIL I 2i t I I I Wells: 1 Components: 1 Failures: 0 Failure Rate: 0.00% ❑ 90 Day Remarks: B 1 -16 Pilot test only after LPP lowered to 40 psig RE 12/21/04 Page 1 of 2 SVS BAD B1 8 -06 -06 MISC WAIVED.xls Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPXA Submitted By: Melody Broacha Date: 11/2/2006 Operator Rep: Bert Green Field/Unit/Pad: Badami/B 1 AOGCC Rep: John Crisp Separator psi: LPS 125 HPS Well Permit Separ Set UP Test Test Test Date Passed Retest oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Or Date Shut In GAS, CYCLE, SI BI-01 1971570 B1-11A 1980340 168 125 125 P P OIL B 1 -14 1980630 4400 2700 2700 P 4 P GINJ B1 -15 1980740 168 125 115 P P OIL B1 -16 1980800 9/25/2006 SI B 1 -18 1980120 168 125 122 P P OEL B 1 -21 1971740 168 125 115 P P 011L B1 -25 1981530 7/29/2003 SI B1 -28 1981300 7/29/2003 SI B1 -36 1982320 168 125 1151 P I 43 IL Wells: 6 Components: 13 Failures: 2 Failure Rate: 15.38 °/,E] 90 Day Remarks: B1 -14 SSV failed test after cycling valve B1 -36 Failed 1st SSV test, recycled & Passed Note: This report has not yet been sent. It would normally be sent in early December as part of the normal end of month reporting. RJF 12/21/04 Page 1 of 2 SVS BAD B 1 11- 02- 06.xls Alaska Oil and Gas ons ry i n i C e at o Comm ' ssion Safety Valve System Test Report Operator: BPXA Submitted By: Melody Broacha Date: 11/5/2006 Operator Rep: Bertram Greene Field/Unit/Pad: Badami/B 1 AOGCC Rep: Waived Separator psi: LPS 168 HPS Well Permit Separ Set UP Test Test Test Date Tested and or oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed Retest or SI GAS, CYCLE, SI B1 -11A 1980340 125 B 1 -14 1 19806301 168 1 27001 P Passed Retest GINJ Wells: 2 Components: 0 Failures: 0 Failure Rate: #DIWOII 90 Day Remarks: Repair B1 -14 SSV and then Did a State Test on the SSV It Passed. Right to witness waived by John Crisp Note: This report has not yet been sent. It would normally be sent in early December as part of the normal end of month reporting. RJF 09/19/02 Page 1 of 2 SVS BAD B1 11 -05 -06 RETEST.xls Attachment 2: Documents Relating to Repairs to SVS Components Well Maintenance History Field BAD Unit al Well# 14 Well Head Type FMC 1 OM Badarni Close Form J Manufacture C1W BPV Profile ClW HPLUG 4-1116 Size 04-1 OK Wing Actuator BAK E R LLS SSV Actuator AR R Q Annulus Master SSV Wing Swab Companion Performed By Comments Parts Required Dat Greased F Greased HOLT, MAY REBUILT SSV, INLIN' REPAIR, FAILED — STATE' '�RJ SEAT, - d7Aik7E — T. - k4ifki& : 11WC0 TEST, GAS INJ., ALSO REPLACED BAKER !STEM PACKING Stroked F F F F f IiCHMET PACKING. Facility : ENS nit BAD WIO Title : REMOVE P-PILOT ON B1 -14 Wyrk Order Package WIO Type : PC W/O Priority: R Short Form Planner : LUCHINSM W/O Status : COMPLETE 36319449 01 Project No.: PM Frequency: Task Title : BMS - REMOVE P-PILOT ON B1 -14 Job Type : CO Task Priority : R Date: 11/08106 W/R Originator: Task Status : COMPLETE Due By Date 07/31/06 Task Discipline: Crew(s): BMS Resource (s) PERS NOP1 Page 1 Work Order I*a.vA- Written To Facillty : ENS Unit BAD Area System: ww Division : Class: Equip Grps: .fork item : Equip List: Equipment : WELL B1-14 Component Equip Name: GAS INJECTION WE 1 1jL Equip Tag WELL-8I-14 UTC Plant Cnd Location Permit Rqd: Code Rlzd Tb' , /Brkdlvn: (past 12 months) Mfr Code Model No Safety Class: Critical Equip: Work -Order Task Instruction ORIGINATOR: BRUCE CLEMENS 907-659-1321 09-APR-06 (CLEMENBD):PLEASE INVESTIGATE THE POSSIBLITY OF REIMOVING THE LOW PRESSURE P-PILOT ON B1 -14 FROM SERVICE AND USE PI-S14-D AND PI-S14--E FOR SHUTTING DOWN THE WELL ON LL PRESSURE. Completion Comments COMPLETED 10/25/06 11/08/06 LUCHINSM E N D 0 F R E P 0 R T Attachment 3: BPXA's Policies and Procedures at Badami ' BPX Alaska, Badami Area: Wellhead Procedure Number: BPOP -52 System Name: Well Operations STATE TESTING OF PRODUCTION WELLHEAD SAFETY SYSTEMS REVIEWED /DATE: Jack Martin /Mike Goodwin, 5/20/99 Ken Tibbett 12/23/01 SCOPE: To safely perform a State Test of the Well Safety Systems. PREREQUISITES / CONDITIONS: • Schedule to have valve PM's done prior to State testing. • Schedule to have sealant/grease available and ensure greasing equipment is in good condition. • Notify AOGCC representative of upcoming State testing. (State Rep. needs to witness 25% of producing wells). REFERENCE DOCUMENTS: P &ID's PI- 130-CO- 0001 -3 -001 PI- BO -CO- 0002 -3 -001 PI- BO -CO- 0002 -3 -002 PI- BO -CO- 0002 -3 -003 BMP -05 HEALTH & SAFETY PRECAUTIONS: • Refer to the MSDS for crude oil, benzene, and methane • Refer to ASH for proper PPE • Check and ensure that all tools to be used have correct pressure ratings (example: manifold & high pressure hoses for testing gas injectors need to be rated for at lest 5000 psi service) WARNING: H2S is not presently a concern at Badami. In the future an appropriate warning needs to be added to this procedure. Date Completed: Authorised by: M. E. Goodwin Revised: 11/02/06 Revision #2 Page Number 1 STATE TESTING OF WELLHEAD SAFETY SYSTEMS No. Task No. Steps Initials 1. Test Procedure 1.1 Ensure that the well you are testing is not in the test separator. 1.2 Notify the control room that you will be testing the well /wells. NOTE: If the well is shut in you will 1.3 Verify that the SSV is open, then go to the Tree need to get a reset and close the Whitey valve at the top of Tree. Bleed the pressure off the gauge Verifying that the g auge will go to 0 psi. Replace if necessary. 1.4 Open the swab valve and record wellhead p ressure. Leave swab valve open. 1.5 Verify that the well your going to be testing is in the p roduction mode. 1.6 Hook up the test manifold to the connection on the PSL Pressure Switch Low upstream of the choke. NOTE: Check on the 1 stage 1.7 Check with the control room to make sure that the separator pressure and record this well is out of bypass and in production mode. Also pressure let the control room operator know your going to be shutting in the well 1.8 Close the choke by approximately 75 %. 1.9 Verify that all the valves on your test manifold are shut. 1.10 Open valve #1 to the test manifold slowly and p ressure up to valve #2. 1.11 Open valve # 2 slowly to pressure up your test g auge. 1.12 Close (Isolate) the # 3 valve to the PSL. NOTE: This should shut the SSV and 1.13 Slowly open valve # 4 (bleed off the pressure from the SDV 10 seconds later, at 125 psi the manifold and note at what pressure the panel trips out. Record this pressure. 1.14 Close valve # 1 and De- pressure test manifold and remove the test manifold. 1.15 Open valve # 3 to PSL. 1.16 Contact the control room and get a reset on the well. Close the choke. NOTE: High differential pressure 1.17 Leave the Wing valve closed and open the SSV across the gate valve is a key to monitor the wellhead pressure (WHP) at the Tree successful testing. At least 1,000 psi you will need to approximately 1,500 psi to perform differential ressure is recommended. the test on the SSV. 1.18 Close the SSV and open the wing (SDV) then open the choke. Slowly de- pressures the line from the SSV to the choke leaving about 300 psi up stream of the choke then shut the wing valve (SDV) and then the choke. 1.19 Monitor the pressure gauge at the top of the Tree for pressure build up. If no increase in pressure then the SSV has passed. Record all pressures on the test report. 1.20 Normal up the well. Revised: 11/02/06 Revision #2 Page Number 2 STATE TESTING OF WELLHEAD SAFETY SYSTEMS No. Task No. Steps Initials 2 DOCUMENTATION 2.1 Record all data gathered in the field on a blank hard copy of the AOGCC Ball Valve Test Form.xls 2.2 Turn this field copy of the data into the LMO or the OTL. It will be transferred to an electronic copy of the form. A copy will be maintained on the server and a copy will be e- mailed to the AOGCC. 4� F X � Q 2 Revised: 11/02/06 Revision #2 Page Number 3 ,~ ,,~, ~~hl~~~~ The purpose of this. Standani is to establish ~ procedure to authorize~ record and mon'rtbr all Defeated Safbty Devices, objectives Ensure adequate communication during times when safety devices are inoperative, Defeated Safetr~~yi+ce ~.~ A Defeated Safety Device Log (DSD Logy shall be maintained in the designated facility location specifying date, tag number, device defeated, how defeated., reason and suthorizatian. Items #hat are under the continuous direct control of the ,~„ authorized person and are returned to service prior to the -end of the shift are no# required to be entered on the Defeated Safety Device Log, Rest©nsibilities unit Operator: 1. At the beginning of each ,shift, initial the, master log to acknowledge awareness of the devices being defeated and length of tune ~ of service. 2. Shall notify Supervis©r, defeat or give permission to defeat the safety device, and record in the master log as soon as passible. 3. Attach a "Danger -- loo Not C?perate" tag to the device or control panel. Tag shall iden#ify the defeated device, reasons why defeated, c~peratv~s name, and dots. When instrumentation readouts. or indicators are affected, a "Danger - do Not Qperate" tag shall also be posted at those locations. 1 ~7` 4. inform the persons doing the vvartc on the status of tfie defeated device. 5. Ensure all safety devices are retur~d to normal Qperating condition prior to completing the job. 6, Reoord the date when tl~e safety device was returned to service on the Defeated Safety twice Log. Control Room Opera#or or Drilf~itellfV~llpad Operator: Be aware of the status of any defeatdd sa#ety dec+~res and hc~ it may affect the overall operation. Operations Firat-Lune SupervlsQr: t . Initial the DSD Log dally to indic~a:#e awareness +~# the devices being defeated and length of time out of service. 2. 8e responsible for operating with a safety device vwhch has been defeated. Ensure that impact to process safety as well as personnel sa#e#y and heal#h is acceptabld. Duration The Operations Manager's signature Shall bas required on the DSD Log if a device is defeated for 90 days, and will be required every 90 days thereaifter. The Field/Seniar Level Manager's signature shall be required on the DSD Log after 120 days, and every t 20 days ~nereafter. Specie! corlslderati~n~ Short term operation of a facility without Halon pratsction requires the approval of the t~era~ons first-I~no Supervisor except during :routine fire and .gas system maint~ance or PMs. '1 ~8 Corinuous oper~on ~ a fa#I~jr w-~t a clefieate~i one s~pprss- sionldetection systemlatarm system such as Halon, has de- tection, etc., requires the approvvat of the appropriate manger. Nate: Continuous vperatan is caned as any iwe1~-hour period from the ttt»e the system became lnc~perable. Jumpers that impact safety devtoes shat( be r~orded on the DSD Log. '138 TIMD082 PREDfFINE~ LOOK AHfA[? ],ifAB.~D~ ~.7.2Z Ph1R~ : a0t}52~45 O1 _ Status ~ ACTIVE Ti tl.e 1~Jf1.1. SAFETY SYSTEM Sft1I-ANNt9AL PM Freq Int 3 Usage Interval MQ ~utag Current f3ue: 02/01lD7 Last Performed 1'11~~5146 Last Read Complete qt. Usage at Complete:: C€~mpi try W10 ; Deferred ` deferred By: Deferred Date Range Start: range End Revised Rue Dt Rea Cd 1 De s c : ~ __,w,.a~,m _,._ Stark Finish Gen W14 Early pt Uue Ut Late (Jt Next, Uue Outage D ~ R X2101107 N h~ Y More: Use Execute witi~ Select to access date changes, ~~ ~? ~ P i ! 1 i r r ~ ~ ~ µ ' r ' ' ~ _, ij ~ ~ ~ 1 } 1 1 ~,` f"~ i~ FRANK H. MURKOWSK/, GOVERNOR ~.....~ i_.I s«~ L.~ I.J _.._:1 ,,... ~_.. I..r E..~ ~.-. T 2..~ w1 ..=.. S..j ~~J ~..i ~t~~7~~T ~~ ~D ~ ~ 333 W. 7`" AVENUE, SUITE 100 C01~5~RVAiiQls CU1~II-TjSSijpj~T ~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 November 2, 2006 CERTIFIED MAIL - RETURN RECEIPT REQUESTED 7005 1 160 0001 5754 0024 Mr. Craig W iggs Badami Performance Unit Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Badami Automatic Shut-in Equipment Dear Mr. W iggs: The Alaska Oil and Gas Conservation Commission recently initiated an investigation of BP Exploration Alaska Inc. ("BPXA") operations at the Badami field. Specifically, the Commission is seeking to determine whether the installation, operation and testing of the well safety valve systems ("SVS") are in accordance the requirements of 20 AAC 25.265. Additional guidance about the SVS is provided in the document titled "AOGCC Policy -SVS Failures" and a letter dated November 14, 1995 addressing SVS failure rates. Triggering this investigation was BPXA's apparent lack of response to SVS failures noted during April 2006 testing witnessed by the Commission. A combined failure rate for tests, excluding retests, conducted from April 6 through July 23, 2006 indicates a SVS component failure rate of 20 percent. That failure rate should have triggered testing the SVS on a 90-day frequency effective April 6, 2006. BPXA is requested to provide the Following information no later than November 17, 2006: - Copies of all SVS test reports documenting the results of tests performed on Badami wells beginning September 2005; include 6-month SVS tests, miscellaneous tests, and retests after failures; - Documents confirming the completion of repairs to SVS components that failed a test; this should include a description of the failure and repair, and the date completed; - BPXA's policies and procedures at Badami regarding installation and removal of safety devices, lock-out/tag-out provisions, maintenance practices and schedules, testing, and response to failures, and if different, responses to repeat failures. Please contact Jim Regg at 793- f 236 should you have an~ji estions about this request. Chai Norman Attachment cc: Inspectors A. Signatu Mr. Craig Wiggs BP Exploration (Alaska) Inc. P.O. Box 196612 3. Service Type Anchorage, AK 99519-6612 ^ Certified Mail ^ Express Mail ^ Registered ^ Retum Receipt for Merchandise ^ Insured Mait ^ C.o.D. 4. Restricted Delivery? (Extra Fee) ^ Yes 2. Article Number (Transfer from service ~aneq 7 0 5 116 0 ~ 0 ~ 1 5 7 5 4 ~ ~ 2=4 ^ Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. ^ Print your name and address on the reverse so that we can return the card tq you. ^ Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to: PS Form 3811, February 2004 Domestic Return .~ ~- 1 ru ~ ~ • ~. ~ .•• p ~• O _ ~ .~ u~i A ~ • ~ Postage $ $0.3~ 053-- ,~ ~ ~A~ ~ ~ ~ Certified Fee #2.40 ar~ ~ ~ Postmark ~ Retum Receipt Fee ~ ` ~ Here ~~ ~ (EndorsementRequlred) $1.13v ~ Fr, f~ RestrlctedDeliveryFee ~O•00 ~ ; „~ (Endorsement Required) '~ :, - r-l 'P .; . '~ Total Postage & Fees ~ ~4•c,4 11F02!~'006 %~~ O Sent To Mr. Craig Wiggs r~~- -sireer,Apr: ivv.i- BP Exploration (Alaska) Inc. '---'-------------- orPOSoxNo. P.O. Box 196612 -°--------------- ciry,-sia~e; ziP+4 Anchorage, AK 99519-6612 X ~ ^ Agent.: ^ Addressee .B. Rec by e) C: Datebf Delivery ,,. D. Is de ivory address ifferen ' .. em 7 ^ If YES, enter delivery address'below; No y__., ~; ~.! ,-, .--t T' `..,ice, co~rs~~Qo c°orrn,~s°sio~ November 14. 199 Eric Walker/Monte Townsend P E Supervisors BPX Prudhoe Bay P 0 Box 19G6I2 Anchorage, AK 99519-G6I2 Dear Messrs. Walker and Townsend: TONY KNOWCE$ GOVERNOR ANCHORAGt:,'NA1.AgfCA 889501.3192 pHONH: (907) 278-1433 FAX: (907) 276.7542 A safety valve system (SVS} is required by regulation in alI offshore welts and by Conservation Order in wells in onshore fields. The Commission considers the 5VS critical for safe and prudent production operations; therefore, it is the Commission's view that SVS should be tested at 6-month intervals. It is the Commission's goal io witness at (cast 25% of these tests. The Commission anticipates some failures will occur, even when an SVS is properly maintained. The Commission considers that a reasonable failure rate on a platform/pad/drilisite basis for all SVS components including the LPS, SSV and SSSV is 10%or less. The Commission Holes that for platforms/pads/drillsltes: • A lU"/o or less SVS component failure rate is acceptable and no further action beyond normal testing and repair procedures tivitl be e~~pected. • An SVS component failure rate greater than IO% may be considered negligent and a penalty may be assessed and a retest should be scheduled within 3 months. Should the retest failure rate be greater than 10% another retest in 3 months will again be required and a penalty may be assessed. In addition, the Commission expects the SVS repair and maintenance records for all wells on the site over the past I2 months to be a e viewd possible investigation. `ter. ~~~/f ~~ !~-~`-- / Johnston t; ~~ Russell A. Dougl Tuckerman $abcack Commissioner Commissioner Listing of Recent SVS Failures faillist.svs Listed below are the results of SVS tests for the fast 3 months - Dec~Feb 97. Field/Unit Pad Test Date Failed ys Tested Failure Rate INo. of Wells) PBU/BPX "F" 12/1 1196 0 of 6 0.0 "F" 12!12196 1 of 6 16..7 "X" 12/30/96 1 of 7 14,3 Niakuk 01 /20/97 1 of 2 50.0 "A" 01 /25/97 0 of 1 1 0.0 "A&B" 02/06/97 4 of 38 10.5 "Z" 02/09/97 1 of 22 4.6 "W" 02/13/97 1 o„~f 10~ 10.0 TOTALS 9 OF 102 $,$ % KRU/ARCO 1 A&3Q 12/06/96 4 of 17 23.5 "2V" 12/15/96 1 of 5 20.0 " 2M" 12/21 /96 1 of 1 1 9.1 " 2A" 01 /17/97 2 of 13 15.4 "2W" 01 /19/97 5 of 13 38.4 "30" 01 /31 /97 4 of 10 40.0 " 2B" 02/02197 1 of 8 12.5 "2E" 02/04/97 0 of 5 0.0 3J&3R 02/23/97 1 of 15 6.7 TOTALS 19 of 97 19.6 PBU/ARCO " 3" 01 /24/97 1 of 10 10.0 NGI & WGI 01 /27/97 3 of 10 30.0 "AGI" 01 /28/97 4 of 5 $0.0 "13" 02/02/97 1 of 11 9.1 "4" 02/08/97 3 of 18 16.7 Lis/PM D96&J97 0 of 3 0.0 TOTALS 12 of 57 21.0 Note: These totals are different than those listed in the inspection reports. These totals are the number of wells tested and failed whereas the totals in the inspection reports represent the number of components tested and failed. From a safety stand point, the number of wells with non-operable SVS systems is the important consideration. Eric Walker/Monie Totivnscnd P E Supervisors BPX Prudhoe Bay P O Box 19G612 Anchorage. AK 99519-6612 Hal Stevens/Jo1rn Hendrix Production Supervisors BPX Milne Point P O Box I9G612 Anchorage, AK 99519-GG 12 Gary McBride/Steven Kimmett BPX Endicott P O Box I9G612 Anchorage, AK 99519-GG 12 Joe Tieaskie Plant Superintendent Phillips Petroleum Company Drawer GG Kenai, AK 99G I I Chuck Beaucamp Field Superintendent UNOCAL 260 Caviar Street Kenai, AK 9961.1 Bill Patterson/Frank Roach (PRB 15) Flo-v Stations Area Opcradons Superintendent ARCO Alaska Inc. P 0 Box 100360 Anchorage, AK 99510 Barry Sossamon/Jim Stewart GPMA Superintendent ARCO Alaska Inc. P 0 Boxl003G0 Anchorage, AK 99510 Mark Eck (P12B G9) Wcl[s Superintendent ARCO Alaska Inc. P O Box l003G0 Anchorage, AK 995I0 Douglass Marshall Field Foremen Steel! Western E&P Inc. 130 Trading Bay Rd, Ste 310 Kenai, AK 99611 ~,~, AOGCC POLICY SVS FAILURES ( Amended 3/94) svsdir03 This document sets forth the Commission's policy regarding the testing of production/injeetion well safety valve systems (SVS), this includes low pressurc sensor (LPS) with pilot valve, surface safety valve (SSV), and subsurface safety valve (SSSV). Wells must be tested by platform, pad, or drill site every 6 months unless a shorter period is designated by the Commission. The Commission intends to witness at least 25%, by facility, of all SVS tests; the Inspector must be given 24 hours notice prior to testing. All test results must be signed by an authorized representative of the operator and submitted to the Commission. Each field operator must maintain a "single-point-of-contact" for SVS monitoring, testing, and data. handling. 2. Wells that have neither produced nor injected during the preceding 6 months need not be tested, but must be tested -vithin 48 hours after being returned to production or injection. The inspector is to be given 24 hour notice prior to the test. 3. !f a SSV or a SSSV fail, production injection may continue, but the valve must be repaired and ready for a witnessed rc-test within 2 wccks. (f the valve fails the rc-test, the wet! must be shut-in until the valve has been repaired or rcplaccd and passes a test. 4. [f both the SSV and the SSSV fail, the well must be shut-in until at Icast one of the valves is repaired or rcplaccd and passes a test. The other valve must be repaired and ready for re-test within two wccks as in ~3 above. 5. LPSs will be tested as part of the SVS. tf the pressurc at which the pilot trips during the test is less then 50% of the primary separator pressurc, or 25% of the flowing tubing pressure, or the designated minimum LPS pressurc, ~vhichcvcr is greater, the LPS fails. 6. If the LPS trips at a pressurc not Icss than 20% below the required trip pressure, at the Inspectors discretion, the well may be shut-in until repaired and rc-tested or must be repaired and re-tested within 24 hours. If the LPS fails to trip, or trips at Icss than 20% of the required trip pressure, the well must be shut-in until it has been repaired and re-tested demonstrating the LPS and at feast one of the safety valves are working properly. 7, Velocity type (differential pressurc) valves, locally called "K valves", are to be flow tested tike any other valve except that only 10%, by primary separation facility, need be tested each 6 months. Different wells must be tested each 6 months so that all "K" valves are tested at least every 5 years. Departures, if any, to the above requirements arc to be recommended by a petroleum inspector and must be approved by their supervisor or a commissioner. BY ORDER OF THE COMM1SS10 DA~IiD W. JO Com issioncr,