The URL can be used to link to this page

Home My WebLink AboutCO 362 A2. 3. 4. 5. 6. 7. 8. 9. INDEX CONSERVATION ORDER NO. 362A PRUDHOE BAY FIELD LISBURNE POOL October 14, 2002 BPXA request to Commingle Production fro Lisburne Area with IPA Production November 14, 2002 Notice of hearing, Affidavit of publication, bulk mailing list for the Anchorage Daily News September 11, 2006 13PXA request for Prudhoe Bay IPA Production Metering Changes to Accommodate EOA Facility Resumption at FS -3 Due to Shut -In Oil Transit Lines April 2, 2007 BPXA request to Commingle Production from the Initial Participating Area with Lisburne Participating Area (C0362A-003) April 12, 2007 DNR's decision to BPXA April 13, 2007 E-mail from DNR to AOGCC Various e-mail regarding operators request for Temporarily waving the requirement of Rule 1 (C0362A- 004) September 27, 2007 BPXA request for Administrative Approval (C0362A- 005) February 20, 2020 BPXA's request for Amin Approval for Conforming PBU Greater Pt. McIntyre Area Satellite Pool Rules for Consistency (CO 362A.006) e e STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. commingle Lisburne Well (K-317B) production with Prudhoe Bay Oil Pool Production ) Conservation Order No. 362A ) ) Prudhoe Bay Field ) Lisburne Oil Pool ) ) ) January 15,2003 It Appearing That: 1. By letter dated October 14, 2002, BP Exploration (Alaska) Inc. (BPXA) requested authorization to allow commingling of production from a proposed well (K-317B) to be drilled and completed within the Lisburne Oil Pool with production from the Prudhoe Oil Pool utilizing Prudhoe Oil Pool facilities. 2. The Commission published notice of the request on November 14, 2002 and scheduled a tentative public hearing on this application for December 17, 2002. 3. No protests or request for hearing was received and the hearing was vacated. Findings: 1. BPXA proposes to drill a Lisburne Well K-317B from Prudhoe Oil Pool Drill Pad K, and to allocate its Lisburne production (oil, gas, and water) in accordance with the Prudhoe Bay Unit Western Satellite Metering Plan (PBU WSMP) outlined by letter to the Commission on April 23, 2002, and approved by the Commission through August 31, 2003 per Conservation Order 471. 2. The planned bottom-hole location of the K-317B cannot be cost effectively reached from existing Lisburne Oil Pool Drill Sites. 3. Production from Lisburne Oil Pool wells is normally processed within the Lisburne Production Center. Conservation Order No. 362 sets forth the procedures for allocation of production from pools processed at the Lisburne Production Center ("LPC"). 4. Production from Well K-317B will be periodically metered using Prudhoe Bay K Pad well test equipment and production will be processed at Prudhoe Bay Gathering Center 1 ("GC 1 "). e e Oil, gas and water production from well K-317B will be reported as Lisburne Oil Pool production. 5. BPXA has requested that any NGLs resulting from well K-317B production be accounted as Prudhoe Oil Pool Gas. Gas produced from well K-317 will be injected into the Prudhoe Oil Pool. 6. The volume ofNGLs will be small due to K-317B's location far from the gas cap. The current yield ofNGLs is approximately 8.8 BBL/MMscf. 7. By letter dated December 23,2002, the Department of Natural Resources, Division of Oil and Gas conditionally approved commingling of production from well K-317B with PBU IP A production in surface facilities before custody transfer. The PBU WSMP was accepted for determining and allocating well K-317B production. For the K-317B well only, the Division approved reporting NGLs as Initial Participating Area ("IP A") fluids, and approved injection of residue gas into the Prudhoe Oil Pool. 8. There are no ownership or royalty differences between the Lisburne Oil Pool and Prudhoe Bay Oil Pool. Conclusions: 1. Commingling of production on the surface from Lisburne Well K-317B with production from Prudhoe Oil Pool facilities prior to custody transfer is appropriate, will not cause waste, reduce ultimate recovery or jeopardize correlative rights. 2. Allocation production to well K-317B utilizing the Prudhoe Bay Unit Western Satellite Metering Plan under the same terms and conditions as set forth in Conservation Order 471, Rule 4, is appropriate and meets the requirements of 20 AAC 25.215(a). Further review of allocation results will be required for extension of the PBU WSMP beyond August 31, 2003 as set forth in Conservation Order 471. NOW THEREFORE, IT IS ORDERED that this Conservation Order supersedes Conservation Order 362, dated September 12, 1995. The findings, conclusions and administrative record for Conservation Order 362 are adopted by reference and incorporated in this decision. Rule 1: Lisburne Production Facilities Produced fluids from the Lisburne Oil Pool, West Beach Oil Pool, North Prudhoe Bay Oil Pool, Niakuk Oil Pool, Pt. McIntyre Oil Pool and Stump Island Oil Pool may continue to be commingled on the surface for processing at the Lisburne Production Center. Production from each pool may be assigned on the basis of twice monthly well tests using procedures described in individual conservation orders for those pools or in this order. The Commission may approve a different test frequency for individual wells upon application. Conservation Order 362A Page 2 of3 January 15,2003 e . Rule 2: Lisburne Well K-317B BPXA's request to commingle Lisburne Oil Pool production from Well K-317B with Prudhoe Bay Oil Pool production is approved. Oil, gas, and water from this Lisburne K- 317B well must be reported as Lisburne Oil Pool production in accordance with 20 AAC 25.230. Production allocation methodology will be in accordance with the Prudhoe Bay Western Satellite Metering Plan, or such plan that is later adopted by the Working Interest Owners and approved by the Commission. Rule 3: Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into treshwater. DONE at Anchorage, Alaska and dated January 15, 2003. {k/(~' ~~L Cammy Oec li Taylor, Chai ~commiSSion Daniel T. SeamotûÍt, Jr., Commissioner Alaska Oil and Gas Conservation Commission ~~~ Mike Bill, P. E. Commissioner Alaska Oil 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 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days 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., 10th day after the application for rehearing was filed). Conservation Order 362A Page 3 of3 January 15,2003 Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 FI. Worth, TX 76102-6298 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Corry Woolington Chevron Texaco Land-Alaska PO Box 36366 Houston, TX 77236 W. Allen Huckabay Phillips Petroleum Company Exploration Department PO Box 1967 Houston, TX 77251 Shelia McNulty Financial Times PO Box 25089 Houston, TX 77265-5089 James White Intrepid Prod. Co.lAlaskan Crude 4614 Bohill SanAntonio, TX 78217 . e John Katz State of Alaska Alaska Governor's Office 444 North Capitol St., NW, Ste 336 Washington, DC 20001 SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 Alfred James 200 West Douglas, Ste 525 Wichita, KS 67202 Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Conoco Inc. PO Box 1267 Ponca City, OK 74602-1267 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 Michael Nelson Purvin Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 G. Scott Pfaff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 William Holton, Jr. Marathon Oil Company Law Department 5555 San Fecipe SI. Houston, TX 77056-2799 T.E. Alford ExxonMobilExploration Company PO Box 4778 Houston, TX 77210-4778 Texico Exploration & Production PO Box 36366 Houston, TX 77236 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 Donna Williams World Oil Statistics Editor PO Box 2608 Houston, TX 77252 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 Shawn Sutherland Unocal Revenue Accounting 14141 Southwest Freeway Sugar Land, TX 77478 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio. TX 78216 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 e Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 tit Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,lD 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Williams VanDyke Cammy Taylor Tim Ryherd State of Alaska 1333 West 11th Ave. State of Alaska Department of Natural Resources Anchorage, AK 99501 Department of Natural Resources 550 West 7th Ave., Ste 800 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Anchorage, AK 99501 Susan Hill Ed Jones Richard Mount State of Alaska, ADEC Aurora Gas, LLC State of Alaska EH Vice President Department of Revenue 555 Cordova Street 1029 West 3rd Ave., Ste 220 500 West 7th Ave., Ste 500 Anchorage, AK 99501 Anchorage, AK 99501 Anchorage, AK 99501 Jim Arlington Duane Vaagen Robert Mintz Forest Oil Fairweather State of Alaska 310 K Street, Ste 700 715 L Street, Ste 7 Department of Law Anchorage, AK 99501 Anchorage, AK 99501 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Julie Houle Trustees for Alaska Mark Wedman State of Alaskan DNR 1026 West 4th Ave., Ste 201 Halliburton Div of Oil & Gas, Resource Eva!. Anchorage, AK 99501-1980 6900 Arctic Blvd. 550 West 7th Ave., Ste 800 Anchorage, AK 99502 Anchorage, AK 99501 Ciri John Harris Rob Crotty Land Department NI Energy Development CIO CH2M HILL PO Box 93330 Tubular 301 West Nothern Lights Blvd Anchorage, AK 99503 3301 C Street, Ste 208 Anchorage, AK 99503 Anchorage, AK 99503 Schlumberger Mark Dalton Jack Laasch Drilling and Measurements HDR Alaska Natchiq 3940 Arctic Blvd., Ste 300 2525 C Street, Ste 305 Vice President Government Affairs Anchorage, AK 99503 Anchorage, AK 99503 3900 C Street, Ste 701 Anchorage, AK 99503 Mark Hanley Baker Oil Tools Judy Brady Anadarko 4730 Business Park Blvd., #44 Alaska Oil & Gas Associates 3201 C Street, Ste 603 Anchorage, AK 99503 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503 Anchorage, AK 99503-2035 Arlen Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 e Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 e Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,lnc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jim Ruud Phillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw - MS 575 Anchorage, AK 99515 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 BP Exploration (Alaska), Inc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Dudley Platt DA Platt & Associates 9852 Little Diomede Cr. Eagle River, AK 99577 Bob Shavelson Cook Inlet Keeper PO Box 3269 Homer, AK 99603 Shannon Donnelly Phillips Alaska, Inc. HEST -Enviromental PO Box 66 Kenai, AK 99611 Peter McKay 55441 Chinook Rd Kenai, AK 99611 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 Penny Vadla Box 467 Ninilchik, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Claire Caldes US Fish & Wildlife Service Kenai Refuge PO Box 2139 Soldotna, AK 99669 e Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 e . John Tanlgawa Evergreen Well Service Company PO Box 871845 Wasilla, AK 99687 Chartes Boddy Usibelli Coal Mine, Inc. 100 Cushman Street, Suite 210 Fairbanks, AK 99701-4659 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 131 Fairbanks, AK 99707 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 Kurt Olson State of Alaska Staff to Senator Tom Wagoner State Capitol Rm 427 Juneau, AK 99801 Senator Loren Leman State of Alaska State Capitol Rm 113 Juneau, AK 99801-1182 . ~1r~1rŒ lID~ ~~~~[(~ . · AIfASIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRA TIVE APPROVAL NO 362A.00l Mr. Dwight Warner Interim GPMA Resource Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Warner: · By letter dated January 29, 2004, BP Exploration (Alaska), Inc. ("BPXA") requested authorization to temporarily commingle production from the Well L2-14A in the Lisburne Oil Pool ("LOP") with production from the Prudhoe Oil Pool ("PBOP"). This will allow initial testing of this new sidetrack completion for approximately one month until surface equipment modifications have been made to allow production into the Lisburne facilities. LOP well production is normally processed within the Lisburne Production Center. The Prudhoe Bay Unit ("PBU") Western Satellite Metering Plan ("WSMP") was adopted by the Commission for allocation of production for the certain satellite oil pools per the following orders dated August 19,2003; Borealis Oil Pool (CO 471.02), Aurora Oil Pool (CO 457A.Ol), Polaris Oil Pool (CO 484.02) and Midnight Sun Oil Pool (CO 452.02). The WSMP is described in the letter from BPXA to the Commission dated April 23, 2002 and detailed within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan - Policies and Procedures Document" dated August 1, 2002. Commingling of Lisburne Well K-317 production with production from the PBOP was approved by the Commission by C0362A dated January 15, 2003, and required allocation in accordance with the WSMP. BPXA has requested similar treatment for allocation of L2-14A production. · Production from Well L2-14A will be periodically metered using three-phase meter test equipment on pad (used for testing PBOP wells on the same pad) and will then flow to Flow Station 1. BPXA has requested that any natural gas liquids ("NGLs") resulting from well L2-14A production be accounted as indigenous to the PBOP. The volume ofNGLs will be small due to the short duration of the commingled production. There are no ownership or royalty differences between the LOP and PBOP. CO 362A.00 1 February 3,2004 Page 2 of2 . . . The Commission approves BPXA' s request to commingle production from Lisburne Well L2-14a with production rrom the Prudhoe Bay Oil Pool with the following terms and conditions. · L2-14A production must be allocated in accordance with the Prudhoe Bay Western Satellite Metering Plan. · Oil, gas, and water rrom well Lisburne L2-14A must be reported as Lisburne Oil Pool production in accordance with 20 AAC 25.230. · NGLs resulting from well L2-14A production will be accounted as Prudhoe Bay Oil Pool gas. · This approval will expire on March 1, 2004. , Alaska and dated February 3, 2004. ø Daniel T. Seamount, Jr. Commissioner . .. . e e FRANK H. MURKOWSKI, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'H AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 341E.Ol ADMINISTRA TIVE APPROVAL CO 559.02 --AD-M-INISl'-RA1'-I\lE-AJ!-P·RO¥ AL-CO-J62A.02.- Ms. Nancy C. Foust Projects and Engineering Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Re: BPXA's request for production metering changes to accommodate production resumption at FS-3 and temporary amendment to production allocation procedures for the Prudhoe, Put River, Lisburne, Point McIntyre, Niakuk, Raven, West Beach, North Prudhoe Bay Oil Pools. Dear Ms. Foust: On September 11, 2006, BP Exploration (Alaska) Inc. (BPXA) as operator of the Prudhoe Bay Unit, requested authorization from the Alaska Oil and Gas Conservation Commission (Commission) and the Department of Natural Resources, Division of Oil and Gas, to alter the metering configuration utilized in the Prudhoe Bay Initial Participating area (IP A) and the Greater Point McIntyre Area (GPMA) in order to restore production from the Eastern Operating Area (EOA) of the Prudhoe Bay field. The proposed metering changes affect the location of the Lease Automatic Custody Transfer (LACT) meters for the production from the Prudhoe and Put River oil produced at Flow Station 3 (FS-3) and require changes to the individual FS-3 and Lisburne Production Center (LPC) facility volume allocation procedures. The Commission grants temporary approval of BP Exploration (Alaska) Inc. (BPXA) request to alter the metering configuration and facility allocation methodology used to determine production from the Prudhoe and Put River Oil Pools processed at Flow Station 3 and from pools processed within the Lisburne Processing Center ("LPC"). These changes are being sought due to the shutdown of the Eastern Operating Area Oil Transit Line which is undergoing repair and replacement. A new FS-3 bypass will re- route oil production from a point downstream of the FS-3 shipping pumps and meters to CO 34[E.0[, CO 559.02, C~A.02 September [5,2006 Page 2 of2 e the Lisburne Sales Oil Pipeline at a point downstream of the LPC shipping pumps and upstream of the Lisburne LACT meter at Pump Station 1. The metering changes require changes to individual FS-3 and LPC facility volume allocation procedures, but do not affect current well testing or well allocation procedures. The proposed facility allocation process for FS-3 and LPC is consistent with current methodology approved by the Commission for all pools within the Prudhoe Bay Field. In accordance with 20 AAC 25.230 production from the Prudhoe and Put River Oil Pools --------- -processedwiffi-in Prudhoe Flo\v--Stafion 3 may be commingled with production from Lisburne, Point McIntyre, Niakuk, Raven, West Beach, and North Prudhoe Bay Oil Pools processed within the LPC prior to custody transfer. Production shall be allocated in accordance with the procedures described in BPXA's application dated September 11, 2006. All other well testing and reporting requirements for the Prudhoe Bay Field shall be in accordance with applicable Commission regulations and orders and are not affected by this order. This order expires on October 1, 2007. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DONE at Anchorage, Alaska and dated September 18, 2006. The Alaska Oil and Gas Conservation Commission ~ Daniel T. Seamount, Jr. Commissioner various AdminIstratIve Urders e e Subject: Various Administrative Orders From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 19 Sep 2006 14:27:54 ~0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Robert E Mintz <robert_mintz@law.state.akus>, Christine Hansen <c.hansen@iogcc.state.okus>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjrl@aol.com>,jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton _. __'9nark~dal1on@hdrinc.cD.m2-,-.S.hannon.nonnelly-<::::shannon~donnelly:@wnüCüphillips..co.m2-,...'.'Mark.E..____ Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.akus>, tjr <tjr@dnr.state.akus>, bbrìtch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah 1. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_ schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shel1.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>,jah <jah@dnr.state.akus>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, 10ren_Ieman <loren_Ieman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.akus>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobi1.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@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.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>,jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, nI617@conocophillips.com, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_ Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unoca1.com>, Todd Kratz <ToddKratz@chevron.com>, Gary Rogers <gary Jogers@revenue.state.akus>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <ken@secorp-inc.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews lof2 9/1 9/20062:28 PM VarIOUS AdmmIstratIve Urders e e <Iris_Matthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, Rob Dragnich <rob.g.dragnich@exxonmobil.com>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Alicia Konsor <alicia_konsor@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <Camille_Taylor@law.state.ak.us>, Winton GAubert <winton_aubert@admin.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoil.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg <j im _ regg@admin.state.ak.us>, Catherine P Foerster <cathy _ foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <laura _ silliphant@dnr.state.ak. us>, David Steingreaber <david.e.steingreaber@exxonmobi1.com>, --akpratts@acsataska:net;-Rohert-eampbeH-<:-R-obert~eampbeH@reuters~com¿.;-S-teve-Moothart------_·_·- <steve_moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paul_ bloom@ml.com>, Sonja Franklin <sfranklin6@blomberg.net>, Meghan Powell <Meghan.Powell@asrcenergy.com> Content-Type: application/pdf C0341E.02 and CO 559.03.pdf b 64 Content-Encoding: ase Content-Type: application/pdf CO 341E.Ol, CO 559.02 and CO 362A.02.pdf b 64 Content-Encoding: ase 20f2 9/19/20062:28 PM Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 e David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 e Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen ---~'..~-,_...__..- ..--- 200 North 3rd Street, #1202 Boise. 10 83702 ~axr.t1unge~~__ ____ __ Munger Oil Information Service, Inc PO Box 45738 Los Angeles. CA 90045-0738 Michael Parks --_.,--~~--'_".._._..-_',.._---._-'- Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, W A 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage. AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage. AK 99503 Baker Oil Tools 4730 Business Park Blvd, #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jill Schneider US Geological Survey 4200 University Dr. Anchorage. AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage. AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna. AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna. AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks. AK 99706 Cliff Burglin PO Box 70131 Fairbanks. AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks. AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . ~ 1f iÃ\ 1f Œ (ill ~ iÃ\ ~ iÃ\ ~ [(iÃ\ . AIfA~1iA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 362A.003 ADMINISTRATIVE APPROVAL NO. 341E.003 SARAH PALIN, GOVERNOR Mr. Mark C. Weggeland GPMA Resource Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Weggeland: The Alaska Oil and Gas Conservation Commission ("Commission") authorizes BP Exploration (Alaska) Inc. ("BPXA") to commingle production from six Prudhoe Bay Unit ("PBU") Initial Participating Area ("IP A") wells on the Lisburne L2 pad with production from the Lisburne Participating Area and other Greater Pt. McIntyre Area ("GPMA") pools subject to the conditions set out below. By letter dated April 2, 2007, BPXA requested that the Commission authorize it to commingle production from six PBU IP A wells on the Lisburne L2 pad with production from the Lisburne Participating Area and other GPMA pools. The subject PBU wells are L2-03A, L2-07A, L2-08A, L2-11, L2-13A, and L2-18A (collectively the "L2 IPA wells"). Due to gas-handling constraints at Flow Station 1 ("FS 1 "), these wells are not produced continuously. Rerouting the L2 IP A well fluids, which have a relatively high gas-oil ratio, would enable the wells to maintain full-time production because the Lisburne Processing Center has unused gas-handling capacity. Production from the L2 IP A wells is piped to PBU Drill Site 18 ("DS-I8") and then to FSI for processing. Because FS1lacks sufficient gas-handling capacity, fluids from the L2 IP A wells must compete for space at FS I with fluids from lower gas-oil ratio wells. BPXA proposes to install piping that would enable production from the L2 IP A wells to be commingled with production from the Lisburne Participating Area wells on the Lisburne L2 pad. The commingled well fluids would be sent to the Lisburne Processing Center, which also handles production from other GPMA pools. Production from the L2 IP A wells could still be sent to FS I, and production from each well could still be tested separately. In addition to the benefit of continuous production, GPMA production would benefit because more injection gas (i.e., from the L2 IPA well fluids) would be available to . . CO 362A.003 CO 341E.003 April 13,2007 Page 2 of2 enhance oil recovery. The amount of gas available for voidage replacement in the IPA would not be adversely affected because FSI is at its gas-handling capacity. BPXA proposes to measure production from the L2 IP A wells and allocate that production to the IP A in accordance with GPMA metering and allocation procedures. Conservation Order ("CO") 362, dated September 12, 1995, established GPMA metering and allocation procedures. These procedures were modified by CO 362A on January 15, 2003. There are no ownership differences between the GPMA and IP A The Commission conditionally approves BPXA's request to commingle production from the L2 IP A wells with production from the other pools in the GPMA so long as the following terms and conditions are met: · This administrative approval does not exempt BPXA from obtaining any other approvals that may be required by other governmental agencies and does not authorize commingling of production from the L2 IP A wells with production from any pools in the GPMA until all required approvals have issued. · Production from the L2 IP A wells must be metered and allocated in accordance with the process described in BPXA's letter, dated April 2, 2007, and the GPMA metering and allocation procedures of CO 362 and CO 362A. · Oil, gas, natural gas liquids and water from the L2 IP A wells must be reported as IPA production in accordance with 20 AAC 25.230 and AS 31.05.170(8). · BPXA must notify the Commission in a timely manner before routing production back to FS 1. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DONE at Anchorage, Alaska and dated April 13, 2007. ~;;:~/ Commissioner ... }" ;,;":}t' · - " ,.,. ~. CO 362A-003, AI03-017, C034IE·003 Adm.PProVaIS Prudhoe Bay . Subject: CO 362A-003, AI03-0I7, C034IE-003 Admin Approvals Prudhoe Bay From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Fri, 13 Apr 2007 14:45:40 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, trmjrI <trmjrI@aol.com>,jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, , Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjne1son <tnjnelson@purvingertz.com>, Charles O'Donnell <char1es.o'donnell@veco.com>,·"Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@in1etkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "NickW. Glover" <GloverNW@BP.com>, "DarylJ. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <tnckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesnoI@gci.net>, gspfoff <gspfoff@aurorapower.com>,Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <bl@mapalaska.com>,jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark _hanley@anadarko.com>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@alaskadc.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <tnarty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <tnkm7200@aol.com>, Brian Gillespie <itbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, ToddDurkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, James Scherr <james.scherr@mms.gov>, nI617@conocophillips.com, Tim Lawlor <Tim_Law10r@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Gary Rogers <gary _rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur_Copoulos@dnr.state.ak.us>, Ken <k1yons@otsintl.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough <admin@aleutianseast.org>, Matquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson lof2 4/13/20072:46 PM co 362A-003, AI03.j)17, C0341E.j)03 A~Va1s Prudhoe Bay . <gbrobinson@marathonoi1.com>, Cammy Taylor <cammy_taylor@dnr.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoi1.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg <jim_regg@admin.state.ak.us>, Catherine P Foerster <cathy_foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <laura _ silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@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 <pau1~bloom@ml.com>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple_davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, , John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John.Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegamer <jimwinegarner@brooksrangepetro.com>, Matt Rader <matt_rader@dnr.state.ak.us>, carol smyth <caro1.smyth@shell.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoil.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@intemational.gc.ca>, Cary Carrigan <cary@kfqd.com>, Sonja Frankllin <sfranklin6@bloomberg.net>, Mike Bill <Michael.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, "Alan Birnbaum <\"\"Alan J Birnbaum \">" <alan _birnbaum\"@law.state.ak.us> Jody Colombie <jody colombie(tI}admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: applicationJpdf C0362A..oo3.pdf Content-Encoding: base64 AI Content-Type: app1icationJpdf 03-017.pdf Content-Encoding: base64 C03 -00 Content-Type: applicationJpdf 41E 3.pdf Content-Encoding: base64 20f2 4/13/2007 2:46 PM Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bemie Kart K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 À . Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201·3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahñng NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Mark Wadman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 . ~~/Æ~Œ mJ~ /Æ~/Æ~[{/Æ . AItASIiA. OIL AlO) GAS CONSERVATION COMMISSION 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRA TIVE APPROVAL NO. 362A.004 SARAH PALIN, GOVERNOR Mr. Mark C. Weggeland GPMA Resource Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Weggeland: The Alaska Oil and Gas Conservation Commission ("Commission") temporarily waives the requirement of Rule 1 of Conservation Order ("CO") 362A to test wells twice monthly for allocation purposes for all wells on the Pt. McIntyre 2 ("PM2") pad. By email from Ms. Jessie L. Carr of BP Exploration (Alaska) Inc. ("BPXA") to Mr. Dave Roby of the Commission on July 10,2007, BPXA requested that the Commission waive the twice monthly well testing requirement for wells on the PM2 pad until the PM2 pad test separator is returned to service following the completion of facility modifications. The PM2 pad test separator must be shut in for safety reasons while final tie-ins for the new 24-inch common line to the Lisburne Production Center are made. The pressure safety valve ("PSV") on the PM2 pad test separator is designed to relieve pressure to the 24-inch common line in case the test separator pressure becomes too high. The PSV is now needed as a second barrier for energy isolation between process fluids and the 24- inch common line and must remain closed until the tie-in work is completed. Therefore, no fluids may enter the PM2 test separator in case the PSV opens to relieve vessel pressure and violates the "double block and bleed" required to conduct the tie-in operations safely. The PM2 test separator was removed from service on June 27, 2007. BPXA anticipates completion of the tie-in work and return to service of the PM2 test separator in late July or early August 2007. The Commission temporarily waives the twice monthly well testing requirements of Rule 1 of CO 362A for the wells located on the PM2 pad with the following conditions: . Regular twice monthly well testing must resume at the PM2 pad as soon as the 24-inch common line tie-in work is completed and the PM2 test separator can be returned to service. . . CO 362A.004 July 11, 2007 Page 2 Of2 . This Administrative Approval expires on August 31, 2007, if the PM2 test separator will not be returned to service by this date BPXA must provide an update on the 24-inch common line tie-in work and request an extension from the Commission. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. nc orage, Alaska and dated July 11, 2007. Daniel T. Seamount, Jr. Commissioner Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 SOldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 ,~ 0 . . Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, July 13, 2007 11 :37 AM Subject: Corrected CO 559-004 and CO 362A-004 PBU Attachments: Colombie, Jody J (DOA).vcf; Corrected CO 559-004.pdf; CO 362A-004.pdf Jody J. Colombie Special Assistant to the Commission I State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Tel: (907) 793-1221 Fax:(907)276-7542 7/13/2007 Page 1 of I LJ _ ~~;;~ _ - ~7 '~ ~ a ~ ~ a ~ ,~ a3 _ - ~1 ' ? 3 ; . a ` t>~aSA OIL A11TD G~.S COI~TSERVA~'I011T CODIIriISSIOI~T SARAH PALIN, GOVERNOR ,~ 333 W. 7th AVENUE, SUITE 100 ~' ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 570.004 -Raven Oil Pool ADMINISTRATIVE APPROVAL C0362A.005 -Greater Pt. McIntyre Area Ms. Diane Richmond GPMA Resource Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Ms. Richmond, Based on discussions with BP Exploration (Alaska), Inc. ("BPXA"), the Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, administratively amends the surface commingling and production allocation provisions for the Raven Oil Pool. The Commission does so to make those provisions consistent with the provisions in other conservation orders that cover oil pools with surface commingling and the use of the Lisburne Production Center (``LPC"). For this same reason, the Commission also administratively amends the definition of the Greater Pt. McIntyre Area ("GPMA") to include the Raven Oil Pool. Rule 6 of Conservation Order ("CO") 570 authorizes commingling of production from the Raven Oil Pool and other pools in the Prudhoe Bay Unit ("PBU") and specifies that the production allocation must be done in accordance with the PBU Western Operating Metering Plan ("PBU WOMP"), ``described in the letter dated April 23, 2002 subject to ongoing review." The PBU WOMP specifies the allocation methodology for satellite oil pools in the western portion of the PBU that are processed through Gathering Center ("GC") 1 and GC 2. Given that the Raven Oil Pool is in the eastern portion of the PBU and production is processed through the LPC, the PBU WOMP does not specify the correct allocation methodology for Raven Oil Pool production. The correct methodology is specified in CO 362A (the actually methodology was described in the findings of CO 362, which were incorporated by reference into CO 362A). Rule 1 states: production fora "pool may be assigned on the basis of twice monthly well tests using procedures described in individual conservation arders for those pools or in this order." The rule also identifies the pools that may be commingled on the surface for processing at the LPC. Accordingly, the rule must be amended to include the Raven Oil Pool to ensure that all of the produced fluids commingled on the surface for processing at the LPC are allocated in the same manner. Rule 14 of CO 570 and Rule 3 of CO 362A authorize the Commission to administratively waive or amend any rule in the orders as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Based on the facts stated above the CO X70.004 • • CO 362A.005 October 9, 2007 Page 2 of 3 Commission finds that administratively amending CO 570 and CO 362A so that surface commingling and production allocation provisions are consistent is appropriate under these rules. Accordingly, on its own motion, the Commission administratively amends CO 570 and CO 362A as follows: Rule 6 of CO 570 is repealed and readopted to read• Rule 6: Common Production Facilities and Surface Commin~lin~ a. Production from the Raven Oil Pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats. i. Conduct well tests to determine production rates for each well. ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. iii. Sum the TMP volume for all wells in all pools. iv. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP) v. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor c. NGL's will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the Commission. d. Each producing well will be tested at least twice each month. Wells that have been shut in and cannot meet the twice monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. f. Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. CO 570.004 CO 362A.005 October 9, 2007 Page 3 of 3 g. API gravity will be determined for each producing well annually by an API/MPMS approved method. h. Gas samples will be taken and analyzed for composition from each non gas lifted producing well yearly. i Quarterly allocation process reviews will be held with the Commission. __ Rule 1 of CO 362A is repealed and readopted to read: Rule 1: Lisburne Production Facilities Produced fluids from the Lisburne Oil Pool, West Beach Oil Pool, North Prudhoe Bay Oil Pool, Niakuk Oil Pool, Pt. McIntyre Oil Pool, Stump Island Oil Pool, and Raven Oil Pool may continue to be commingled on the surface for processing at the Lisburne Production Center. Production from each pool may be assigned on the basis of twice monthly well tests using procedures described in individual conservation orders for those pools or in this order. The Commission may approve a different test frequency for individual wells upon application. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. To be timely, the application must be received by 4:30 p.m. on the 23rd day following the date of this decision, or on the next working day if the 23rd day falls on a state holiday or weekend. A decision may not be appealed to the Superior Court unless the Commission has received a timely, properly filed application for reconsideration. end dated October 9, 2007. Daniel T. Seamount, Jr. Commissioner /; ' ~~ ~ ~' ~, , ~ ~~. ~J ~ f ~' q . , ~y :`~ ~ .~, • Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks ~,... ~~~. Mark Wedman --- --~ nn noo-.:o;i:--3rd~eet-#T~ Boise, ID 83702 ~ p 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation ~ I Land Department t ~/ PO Box 129 ~ ~ 111 ~ ~`~ Barrow, AK 99723 V ~~ • rage i or i Colombie, Jody J (DOA) ___ __ From: Colombie, Jody J (DOA) Sent: Wednesday, October 10, 2007 10:27 AM Subject: CO 570-004; CO 362A-005 and CO 3298-003 PBU Attachments: CO 574-004 and CO 362A-005.pdf; CO 3296-003.pdf 10/ 10/2007 TI IL STATE ALASKA GOVERNOR MICHAEL J. DUNLEA\Y Ms. Katrina Garner Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 207D.001 CONSERVATION ORDER NO. 311B.003 CONSERVATION ORDER NO. 317B.003 CONSERVATION ORDER NO. 329B.005 CONSERVATION ORDER NO. 345.002 CONSERVATION ORDER NO. 362A.006 CONSERVATION ORDER NO. 570.010 PBU Area Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -20-003 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Request for Administrative Approval for Conforming Prudhoe Bay Unit (PBU) Greater Point McIntyre Area Satellite Pool Rules for Consistency Prudhoe Bay Unit Lisburne Oil Pool — Conservation Order (CO) 207D West Beach Oil Pool — CO 311B Pt. McIntyre and Stump Island Oil Pools — CO 317B Niakuk Oil Pool — CO 329B North Prudhoe Bay Oil Pool — CO 345 Greater Point McIntyre Area — CO 362A Raven Oil Pool — CO 570 Dear Ms. Garner: By letter dated February 20, 2020, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to amend the pool rules in the above referenced orders to bring conformity and consistency to the rules governing operations in the pools in the Greater Point McIntyre Area (GPMA), to make operations more efficient, and to make compliance oversight for the Alaska Oil and Gas Conservation Commission (AOGCC) simpler. There are several requests that apply broadly across multiple GPMA pools. These are as follows. COs 207D.001, 311B.003, 317B.003, 329B.005, 345.002,362A.006, 570.010 April 3, 2020 Page 2 of 12 Well Spacing Requirements: Currently, the Lisburne Oil Pool (LOP) has an interwell spacing requirement of one well per government quarter section and no pay opened within 1,000 feet of another well. The West Beach Oil Pool (WBOP) has an interwell spacing requirement of one well per 160 acres until circumstances warrant the AOGCC changing it. The Pt. McIntyre Oil Pool (PMOP) has a spacing requirement of one well per 40 acres with no pay open within 500 feet of another well. The Niakuk Oil Pool (NOP) gives the AOGCC the authority to approve the drilling of any well that is at least 500 feet from the affected area boundary and does not have open pay within 1,000 feet of another well. The Raven Oil Pool (ROP) has an interwell spacing requirement of 20 acres with no pay open within 500 feet of the affected area external boundary. BPXA requests that the interwell spacing requirements be eliminated and that the only spacing requirement be a 500 -foot offset from property lines where the landowner is not the same on both sides of the line. At the time the spacing requirements in these pool rules were imposed wells were being drilled nearly vertically. Because modern horizontal and multi -lateral wells are now being utilized to develop pools, BPXA needs flexibility to drill wells as dictated by the geology and reservoir models in order to maximize recovery. Standardizing the spacing requirements by eliminating interwell spacing requirements while retaining property offset requirements will result in improved recovery while protecting correlative rights. Pressure Survey Requirements: BPXA requests that the pressure survey requirements be modified so that compliance with regulatory oversight becomes simpler and data is collected in a meaningful manner. Currently, the Lisburne Oil Pool (LOP) requires at least one pressure survey be taken each year from each producing drillsite and that the results be submitted monthly, while the West Beach Oil Pool (WBOP), Pt. McIntyre Oil Pool (PMOP), and Niakuk Oil Pool (NOP) require one pressure survey per producing governmental section per year and results submitted quarterly. North Prudhoe Bay Oil Pool (NPBOP) requires one pressure survey per producing governmental section but doesn't specify when the results need to be reported, and Raven Oil Pool (ROP) requires one pressure survey per reservoir compartment where production wells exist and specifies the results are to be reported in the annual reservoir surveillance report. The inconsistency in where pressure surveys need to be collected and how the results are to be reported makes it more difficult for the operator to stay in compliance without yielding any benefit that could not be obtained by more uniform collection and reporting requirements. Moreover, after decades of development and reporting, the pools in the PBU are well understood and have sophisticated reservoir models. At this point, monitoring of reservoir pressure is important for proper reservoir development and targeted pressure surveys would provide the most useful information for reservoir development purposes. Presenting the results of the reservoir pressure surveys from the prior year in the annual reservoir surveillance report and proposing a plan for collection of reservoir pressure surveys in the coming year as part of the annual reservoir surveillance report will give the AOGCC an opportunity to review the data and ensure the proposed plans are adequate. This is consistent with how the other pools in the PBU are managed. COs 207D.001, 31 1B.003, 317B.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 3 of 12 Well Testing: The GPMA pools have inconsistent well testing requirements that include quarterly allocation process reviews, monthly allocation reports, determining water volumes by API approved methods or an on-line water cut meter, monthly or annual API gravities for each well depending on the pool, gas samples collected yearly from each non -gas lifted producer, a minimum of two well tests per well, and twice monthly well tests. BPXA requests to eliminate the quarterly allocation process reviews and monthly allocation reports and proposes instead to provide an allocation factor report as part of the annual surveillance report as is done elsewhere in the PBU. BPXA also requests eliminating the water volume calculation, API gravity, and gas sampling requirements since at this point, recovery methods in these pools are unchanging and render this data of little benefit. Finally, BPXA requests to eliminate the requirement to test each producing well at least twice each month and instead require a minimum of one test per month per well. This request is consistent with how the rest of the PBU is managed and allows BPXA to maximize its well testing resources by testing the wells with stable production less frequently and testing the wells with less stable production more frequently to improve the overall allocation of production. Additionally, BPXA makes several requests that apply only to a single pool. These include the following. LOP Gas Oil Ratio (GOR) Testing Requirement: The LOP requires a GOR test on each producer within 90 to 120 days of commencement of regular production and then semiannually thereafter. The monthly well testing requirements for allocation purposes will provide adequate information as to the producing GOR of the wells so as to render the current rule unnecessary. LOP Gas Cap Water Injection (GCWI) Project: BPXA proposes to remove the 20,000 BWPD injection rate limit and raise the injection pressure limit from 0.55 psi/ft to 0.85 psi/ft. When the LOP GCWI was initially approved it was thought that the water injection rate and pressure must be constrained to prevent parting the LOP matrix to prevent premature water breakthrough. After several years of operation, such strict limits on injection rates and pressure do not appear to be necessary and the GCWI project will still function as planned if injection rates are constrained to 0.85 psi/ft. PMOP Enhanced Oil Recovery (EOR) Project Report: BPXA requests elimination of the annual EOR project report for the PMOP because miscible injectant for this pool is now being supplied by PBU Central Gas Facility and not from the Lisburne Production Center. As such, a PMOP EOR project specific report is no longer needed as the MI composition is the same as elsewhere in the PBU. Conclusions: Each of the affected COs contain an administrative action rule that allows the AOGCC to administratively amend the orders provided the proposed change does not promote waste, jeopardize correlative rights, is based on sound engineering and geoscience principles, and will COs 207D.001, 31113.003, 31713.003, 329B.005, 345.002,362A.006,570.010 April 3, 2020 Page 4 of 12 not increase the risk of fluid movement into freshwater. All of BPXA's requested changes comply with these requirements. The proposals to consolidate the rules across the GPMA pools, eliminate or modify the GOR testing and GCWI project rules in the LOP, and eliminating the requirement for an unnecessary EOR project report for the PMOP will simplify operations for BPXA, make uniform the compliance requirements, and will not impact ultimate recovery. Eliminating interwell spacing requirements, while maintaining a minimum offset distance from property lines where ownership changes, will maximize ultimate recovery while also protecting correlative rights. The only proposed change that could potentially have an impact on fluid movement into fresh water is the elimination of the water injection rate limitation and increasing the water injection pressure limitation for the LOP GCWI. However, since the proposed injection pressure limit is below the fracture gradient of the confining interval this will ensure the LOP GCWI injection remains in the LOP. The proposed changes can be made administratively. Finally, on its own motion, the AOGCC is revising the administrative action rules, where necessary, to be consistent and uniform with the language currently used by the AOGCC for these rules. Now, therefore, it is ordered that the subject conservation orders are amended as shown below. Lisburne Oil Pool — Conservation Order No. 207D Rule 3. WELL SPACING There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 9. GAS -OIL RATIO TESTS (Rescinded) Rule 10. PRESSURE SURVEYS a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 1511 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 151 of each year on Form 10- 412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,900 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. COs 207D.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 5 of 12 Rule 16. GAS -CAP WATER INJECTION PROJECT a. Water injection is authorized into Well L5-29 only and is limited to perforations within the upper Wahoo Formation (Zone 6) between the measured depths of 13,585' and 13,634'; and b. Injection pressures must be maintained below 0.85 psi/ft. West Beach Oil Pool— Conservation Order No. 311B Rule 3 Well Soacin¢ There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 7 Common Facilities and Surface Commin line a. Production from the West Beach Pool may be commingled on the surface with production from other pools prior to custody transfer. b. NGLs will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. C. Each producing well will be tested at least once each month. Wells that have been shut-in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. d. Optimum test duration and stabilization time will be determined on a well -by -well basis by the operator. Rule 9 Reservoir Pressure Monitorin a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 151h of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut- in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be COs 207D.001, 311B.003, 317B.003, 329B.005, 345.002,362A.006, 570.010 April 3, 2020 Page 6 of 12 permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. Pt. McIntyre and Stump Island Oil Pools — Conservation Order No. 317B Rule 4 Well Soacine There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 10 Surface ComminelinQ and Common Facilities a. Production from the Pt. McIntyre and Stump Island Oil Pools may be commingled at the surface with production from other pools for processing at the Lisburne Production Center ("LPC") and production from the Pt. McIntyre Oil Pool Drillsite PM2 may be commingled at the surface with production from other pools for processing at the Prudhoe Bay Unit IPA Gathering Center 1 ("GCI"), prior to custody transfer. b. Daily production from all wells will be based on empirical well performance curves derived from 3-phase flow equations and production well test data, and will be a function of flowing tubing pressure and gas -lift rate. The method is described within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan — Policies and Procedures Document' dated August 1, 2002. c. Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operation conditions must be utilized for well testing. d. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. e. Wells will use the associated process facility allocation factor for oil, gas, and water. Pt. McIntyre wells that flow to both GC 1 and LPC in the same month will use a prorated (GCI and LPC) well allocation factor for oil, gas, and water. f. Natural gas liquids ("NGLs") processed at the LPC will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. COs 20713.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 7 of 12 g. NGLs attributable to the PM2 to GCI gas stream and recovered at the CGF will be allocated by calculating the amount of separator off -gas, excluding gas lift gas, attributable to Pt. McIntyre wells producing into GC -1. The percentage of total separator off -gas delivered to the CGF, that is Pt. McIntyre formation gas, multiplied by the total NGL recovery at CGF, yields the amount of NGLs to be allocated to Pt. McIntyre. h. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. Rule 12 Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Pt. McIntyre Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Pt. McIntyre Oil Pool Reservoir Surveillance Report by June 151 of each year on Form 10- 412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 14 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. Rule 16 Pt. McIntyre Oil Pool Enhanced Oil Recovery Project Injection of miscible injectant for enhanced recovery operations is approved for the Pt. McIntyre Pool. COs 207D.001, 31113.003, 31713.003, 329B.005, 345.002, 362A.006,570.010 April 3, 2020 Page 8 of 12 Niakuk Oil Pool — Conservation Order No. 329B Rule 3 Well Snacine There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 6 Surface Commineline and Common Facilities a. Production from the Niakuk oil pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. i. Conduct well tests to determine production rates for each well. ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. iii. Sum the TMP volume for all wells in all pools. iv. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP) v. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor c. NGL's will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. d. Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. Rule 8 Reservoir Pressure Monitorine a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 1511 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. COs 20713.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006,570.010 April 3, 2020 Page 9 of 12 b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 15th of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 12 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. North Prudhoe Bay Oil Pool — Conservation Order No. 345 Rule 5 Surface Commineline and Common Facilities a. Production from the North Prudhoe Bay Oil Pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. 1. Conduct well tests to determine production rates for each well. 2. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. 3. Sum the TMP volume for all wells in all pools. 4. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP). 5. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor c. NGLs will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. COs 207D.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 10 of 12 d. Ata minimum, each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. e. Optimum test duration and stabilization time will be determined on a well -by - well basis by the operator or, in its discretion, by the AOGCC. Rule 7 Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 1511 of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. COs 20713.001, 31113.003, 31713.003, 329B.005, 345.002, 362A.006,570.010 April 3, 2020 Page I 1 of 12 Greater Pt. McIntyre Area — Conservation Order No. 362A.005 Rule 1: Lisburne Production Facilities Produced fluids from the Lisburne Oil Pool, West Beach Oil Pool, North Prudhoe Bay Oil Pool, Niakuk Oil Pool, Pt. McIntyre Oil Pool, Stump Island Oil Pool, and Raven Oil Pool may continue to be commingled on the surface for processing at the Lisburne Production Center. Production from each pool may be assigned on the basis of at least once monthly well tests using procedures described in individual conservation orders for those pools or in this order. The AOGCC may approve a different test frequency for individual wells upon application. Raven Oil Pool — Conservation Order No. 570 Rule 3: Well Suacine There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 6: Common Production Facilities and Surface Comminaline a. Production from the Raven Oil Pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. i. Conduct well tests to determine production rates for each well. ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. iii. Sum the TMP volume for all wells in all pools. iv. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP). v. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor c. NGL's will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. d. Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. COs 207D.001, 31113.003, 31713.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 12 of 12 Rule 7: Reservoir Pressure Monitorine a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Raven Oil Pool Reservoir Surveillance Report by June 151 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual North Raven Oil Pool Reservoir Surveillance Report by June 151 of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9,850 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rale. DONE at Anchorage, Alaska and dated April 3, 2020. Jeremy M. Price Daniel T. oaWhw•.aao....+*. Seamount,Jr. Jessie L. C h m l e l ows KI 13sasa� ogoo Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is tiled. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 ME BP Exoloration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 February 20, 2020 Via USPS and Electronic Delivery Jeremy Price Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7h Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Administrative Approval Conforming PBU GPMA Pool Rules for Consistency Amendments to Conservation Orders: 207C, Rules 3, 9c, IOa-f,16c; CO 317B Rules 4, l Ob,d, 10g, 10h, I Oi, I Oj, 12a -f, 16b; CO 329A Rules 3, 6b,d, f -j, 8a -f, e; CO 311 B Rules 3, 7b, d, f -k; 9a -f; CO 345 Rules 5b,d,f-i, 7a -f; CO 362A.005 Rule 1; CO 570 (Corrected) Rule 3; AA No. 570.002; CO 570.004 Rule 6 b, d, f -i; , l Of governing the development and operation of the Lisburne, Pt. McIntyre, Niakuk, West Beach, North Prudhoe, and Raven Oil Pools Dear Chair Price, BP Exploration (Alaska) Inc. (BPXA), as the operator of the Prudhoe Bay Unit (PBU), respectfully requests that the commission administratively approve amendments described in this application to the referenced Conservation Orders. Each of these pools is in the Greater Pt. McIntyre Area (GPMA) in the PBU. This administrative relief is sought under Rule 17 of CO 207C and its equivalents in the other referenced Conservation Orders. The amendments are proposed with the goal of bringing more efficiency to the management of these reservoirs through achieving as much rule consistency as possible, while still honoring the unique aspects of each pool. More consistent rules will also result in easier monitoring of compliance for the Commission. The proposed changes are in line with recent Commission - approved changes to CO 341F (January, 2018) for the Prudhoe Oil Pool and for changes made to COs 452, 457B, 471, 484A, 505B for the Aurora, Borealis, Orion, Polaris and Midnight Sun Oil Pools (May 29, 2019). With the GPMA Plan Year running April 1 — March 31, BPXA RECEIVED FEB 2 1 2020 AOGCC respectfully requests adjudication by April 1, 2020 in order that the entire next plan year may be under the new regulations. In overview*, BPXA seeks simplification and consistency for the following: • Well Spacing. BPXA proposes there should be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area, unless the owner and landowner are the same on both sides of the line. This is consistent with the language for the Prudhoe Oil Pool except for the "same landowner" clause which represents an improvement to the POP rule. • Pressure Data 10-412 Report. BPXA proposes to eliminate the monthly (Lisburne) to quarterly (Pt. McIntrye, Niakuk, West Beach) to unspecified (N Prudhoe and Raven) reporting requirement by allowing the operator to annually nominate in the ASR (or if no ASR is required to annually report) the number and approximate locations of pressure surveys, with the AOGCC having 30 days to register an issue; if none is raised the proposed number will take effect. The pressure data report would be included in the ASR with that report replacing Lisburne's requirement for an annual meeting to review pressure monitoring requirements and to discuss plans for reservoir management. All data necessary for analysis of each survey need not be submitted with the report but must be available to the commission upon request. This is the current regulation for the POP. • It is proposed to remove the requirement to determine water volumes, annual API gravity, and annual gas samples from each non -gas lifted producing well in the Surface Commingling and Common Facilities rules as our reservoir recovery mechanisms are not changing. The need for data of this kind on such a frequency is not justified. If the operator were to change the recovery mechanism then it might be prudent to monitor each well in such a manner but barring that, BPXA does not see this data guiding reservoir management decisions. • Allocation Process Reviews. BPXA proposes to formally eliminate this requirement. Instead, this requirement can be replaced with an Allocation Factor report in the Annual Surveillance Report (ASR). • Well Test data Report. BPXA proposes to formally eliminate this requirement for all GPMA pools that currently have it and replace it with the Allocation Factor report in the ASR, as provided for other BP operated pools in AOGCC Administrative Approval (AA) (Docket # CO -15-013) dated 1/7/16. That AA waived the requirement to submit monthly reports of daily allocation and test data for a number of PBU pools. It covered some but not all of the GPMA Pools. • Well Test Frequency. BPXA proposes to go from two to one per month for the GPMA pools. This will be in alignment with the other PBU pools. *Items that pertain solely to individual pools are: proposed elimination of the Lisburne Oil Pool Gas -Oil Ratio Test requirement, proposed upward revision of Injection Gradient and elimination of injection rate limit for the Lisburne Gas Cap Water Injection Project, and proposed elimination of the Pt. McIntyre Oil Pool EOR Project performance report. Rationale behind these "one-off' items is provided in Table 1, a spreadsheet containing all the proposed changes across the six GPMA pools. 2 The specific requests are detailed on an individual pool basis below using the convention of brackets [ ] for deletions of existing order words; use of underline denotes proposed new text. Only those rules and paragraphs within rules that have proposed changes are included below. Lisburne Oil Pool Conservation Order 207C Rtl'I • . _ ' . ► � 1 i There shall be no restrictions as to well spacing except that no [The well spacing unit shall be one producing well per governmental quarter section. No] pay shall be opened [in a well closer than 1,000 feet to the pay opened in another well or opened] in a well which is closer than 500 feet to the boundary of the affected area. PI'MmImmEll I0,4,4,V# 1 a) Between 90 and 120 days after regular production commences and each six months thereafter a gas -oil ratio test will be taken on each well for as long as it produces oil; b) The gas -oil ratio tests will be for a minimum of four hours and shall be taken at the normal producing rate of the well; and c) The results of the gas -oil ratio tests will be reported on Form 10-409, Gas -Oil Ratio Test and will be submitted in January and July of each year.] I'MrsumWoma a) (All new wells shall have an acceptable pressure survey, as defined in part (c), taken prior to regular production or injection. b) One pressure survey per producing drillsite per year shall be taken. Pressure surveys from producing or water and gas injection wells may be used for this pressure requirement. Pressure surveys covered in section (a) may be substituted for a drilisite pressure. c) Acceptable pressure surveys include static surveys, RFT/FMT, pressure buildup and falloff tests, and multi -rate pressure transient tests in production or injection wells. Other quantitative methods may be administratively approved by the Commission. d) The pressure datum for the Lisburne Oil Pool is 8900 feet subsea. The Commission may administratively amend this datum or create an additional datum when more information is available on the reservoir. e) Data from the pressure surveys, along with additional pressure data obtained through proper management of the reservoir, shall be filed on form 10-412 by the last day of the month following the month that the pressure survey was obtained. Submitted pressure data shall include other information as necessary such as rate, time, depth, temperature, and well conditions to allow for a complete analysis of the pressure survey. f) The operator shall schedule an annual meeting with the Commission to review the pressure monitoring program and discuss future plans for reservoir management.] 3 a. year. This plan will contain the number and approximate location of Pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412. Data submitted shall include rate pressure time depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,900 true vertical feet subsea. Transient pressure surveys obtained by a shut-in buildup test, an injection well pressure fall-off test a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques tests or surveys shall also be submitted as prescribed in (b) of this rule. Rule 16. GAS -CAP WATER INJECTION PROJECT [b The Well L5-29 injection rate is limited to 20,000 barrels of water injected per day;] c.Injection pressures must be maintained below 0.85 psi/ft. Pt. McIntyre Oil Pool Conservation Order 317B There shall be no restrictions as to well spacing except that no [The spacing unit shall be one producing well per 40 acres or quarter -quarter governmental section. No] pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 10 Surface Commingling and Common Facilities b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission [quarterly in both computer file and report formats.] via the Annual Reservoir Surveillance Report. No changes to the remainder ofb (sub paragraphs). d. Each producing well will be tested at least [twice] once each month. Wells that have been shut in and cannot meet the [twice] once monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. The operator shall submit a review of pool production allocation factors and 4 issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Data shall be presented on a monthly basis reported annually in the ASR. []Of) API gravity will be determined for each producing well annually by an API/MPMS approved method. I Og) Gas samples will be taken and analyzed for composition from each non -gas lifted producing well yearly. I Oh) Quarterly allocation process reviews will be held with the Commission. 10i) This rule may be revised or rewritten after an evaluation period of at least one year.] Ia. Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. b. A minimum of one bottom hole pressure survey per producing governmental section shall be run annually. The surveys in part a. of this rule may be used to fulfill the minimum requirements c. The datum for all surveys is 8800' TVDss. d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period. e. The pressure surveys will be reported to the Commission quarterly. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted upon request. f. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys also shall be submitted in accordance with part e. of this rule.] year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b.Data from the surveys required in (a) of this rule shall be submitted with the Annual Pt McIntyre Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10- 412. Data submitted shall include rate pressure time depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut- in buildup test, an injection well pressure fall-off test, a multirate test or an interference 47 test are acceptable. Calculation of bottom -hole Pressures from surface data will be permitted for water iniection wells Other quantitative methods may be administratively approved by the AOGCC. c.Results and data from any special reservoir pressure monitoring techniques tests or surveys shall also be submitted as prescribed in (b) of this rule Rule 16 Pt. McIntyre Oil Pool Enhanced Oil Recovery Project [b. An annual report must be submitted to the Commission detailing performance of the PMOP Enhanced Oil Recovery Project and outlining compositional information for the current miscible injectant necessary to maintain miscibility under anticipated reservoir conditions. The report should be submitted in conjunction with the PMOP Annual Reservoir Report.] Niakuk Oil Pool Conservation Order 329 Rule 3 Well S acro [Upon application ofthe operator, the Commission may administratively approve the drilling of any well to a bottom hole location greater than 500 lineal feet from the external boundary of the affected area. No well bore may be open to the Niakuk oil pool within 500 feet of the external boundary of the affected area nor within 1000 feet of another well capable of producing from thesamepool.] There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area Rule 6 Surface Commingling and Common Facilities b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission [monthly in both computer file and report formats.] via the Annual Reservoir Surveillance Report. No changes to the remainder of b (sub paragraphs). d.Each producing well will be tested at least [twice] once each month. Wells that have been shut in and cannot meet the [twice] once monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. [f.Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. g.API gravity will be determined for each producing well annually by an API/MPMS approved method. h.Gas samples will be taken and analyzed for composition from each non gas lifted 0 producing well yearly. i.Quarterly allocation process reviews will be held with the Commission. j.This rule may be revised or rewritten after an evaluation period of at least one year.] Rule 8 Reservoir Pressure Monitoring a. [Prior to regular production, a pressure survey shall betaken on each well to determine the reservoir pressure. b. A minimum of one bottom hole pressure survey per producing governmental section shall be obtained annually. The surveys in part'a' ofthis rule may be used to fulfill the minimum requirements. c. The datum for all surveys is 9200' TVDss. d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period. e. The pressure surveys will be reported to the Commission quarterly on form 10-412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted upon request. Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with parte' ofthis rule.] This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year, b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412 Data submitted shall include rate pressure time depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8.800 true vertical feet subsea. Transient pressure surveys obtained by a shut- in buildup test, an iniection well pressure fall-off test a multirate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. 7 C. Results and data from any special reservoir pressure monitoring techniques tests, or surveys shall also be submitted as prescribed in (b) of this rule West Beach Oil Pool Conservation Order 311B Rule 3 Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area [Statewide 160 -acre drilling units are in effect until such time as data or circumstances warrant the Commission to approve a change.] Rule 7 Common Facilities and Surface Commingling [(b) Production from each pool will be determined by the following well test allocation method. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats.] (d) Each producing well will be tested at least [twice] once each month. Wells that have been shut-in and cannot meet the [twice]once-monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. [(f) Water volumes will be determined by API/MPMS approved methods, or the use of industry proven on-line water cut measurement devices. (g) API gravity will be determined for each producing West Beach well monthly. (h) Gas samples will be taken for each non -gas lifted producing well yearly. (i) Quarterly allocation process reviews will be held with the Commission. 0) Prior to installing separate test facilities (if required by future development) at West Beach, Commission approval of the facilities must be obtained. (k) This rule may be revised or rewritten after an evaluation period of at least one year.] Rule 9 Reservoir Pressure Monitoring [(a) Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. (b)A minimum of one bottom -hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements. (c)The datum for all surveys is 8,800' TVD SS. (d)Pressure survey will be a pressure buildup, pressure falloff, RFT, or static bottom -hole pressure after the well has been shut in for an extended period. (e)The pressure surveys will be reported to the Commission quarterly. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted 93 on request. (f)Results and data from any special reservoir pressure monitoring techniques, tests, or surveys also shall be submitted in accordance with part (e) of this rule.] a. An Annual Pressure Surveillance Plan shall hr c„hmittpd fn tha ACU'rt' This plan will contain the number and approximate location of pressure surveyspated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of thatyear. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10- 412. Data submitted shall include rate nressure time depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea Transient pressure surveys obtained by a shut- in buildup test an injection well pressure fall-off test a multirate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be Permitted for water infection wells. Other guantitative methods may be administrative) approved by the AOGCC. C. Results and data from any special reservoir pressure monitoring techniques tests or surveys shall also be submitted as prescribed in (b) of this rule North Prudhoe Bay Oil Pool Conservation Order 345 Rule 5 Surface Commingling and Common Facilities (b) Production from each well will be determined by the following well test allocation methodology. Allocation data andwell test datawill be supplied to the Commission via the Annual Reservoir Surveillance Report. [monthly in both computer file and report formats.] No changes to the remainder of b (sub paragraphs). (d) At a minimum, each producing well will be tested at least once [twice] each month. Wells that have been shut in and cannot meet the once [twice] monthly test frequency must be tested within five days of startup. [(f) Water volumes will be determined by APUMPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. (g) API gravity will be determined for each producing well annually by an API/MPMS approved method. (h) Gas samples will be taken and analyzed for composition from each non -gas lifted producing well yearly. (i) The allocation process for the North Prudhoe Bay Oil Pool will be reviewed with the Commission in conjunction with scheduled LPC allocation review.] Rule 7 Reservoir Pressure Monitoring [7a) Prior to regular production, a pressure survey shall be taken on each well to determine the reservOIr pressure. 7b) Until a secondary recovery project is approved and implemented, a minimum of one bottom- hole pressure survey per producing governmental section shall be obtained annually. 7c) The datum for all surveys is 9245' TVDss. 7d) Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom- hole pressure after the well has been shut in for an extended period. 7e) The pressure surveys will be reported to the Commission on form 10-412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10-412, but must be submitted upon request. 7f) Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part'e' of this rule.] year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b.Data from the surveys required in (a) of this rule shall be submitted with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 15 of each , year on form 10-412. Data submitted shall include rate pressure time depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9245 true vertical feet subsea. Transient pressure surveys obtained by a shut-in buildup test an injection well pressure fall-off test a multirate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques tests or surveys shall also be submitted as prescribed in (b) of this rule Raven Oil Pool Conservation Order 570 Rule 3: Well Spacing [To allow for close proximity of wells in separate fault blocks, spacing within the pool will be a minimum of 20 acres. The ROP shall not be opened in any well closer than 500 feet to the external property lines where ownership or landownership changes.] 10 There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 10: Annual Reservoir Surveillance Report [f. By August 1 of each year, the Operator shall schedule and conduct a technical review meeting with the AOGCC to discuss the report contents and to review items that may require action within the coming year by the AOGCC. The AOGCC may conduct audits of technical data and analyses used in support of the surveillance conclusions and reservoir depletion plans.] Rule 6: Common Production Facilities and Surface Commingling c. All wells must be tested a minimum of [twice] once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. Wells that have been shut in and cannot meet the [twice] once monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. d. [The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation.] Allocation data and well test data will be supplied to the Commission via the Annual Reservoir Surveillance Report. [f. Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. g.API gravity will be determined for each producing well annually by an API/MPMS approved method. h.Gas samples will be taken and analyzed for composition from each non gas lifted producing well yearly. i.Quarterly allocation process reviews will be held with the Commission.] Rule 7: Reservoir Pressure Monitoring a. [Prior to regular production or injection, an initial pressure survey must be taken in each well. b. A minimum of one pressure survey will be taken annually in each of the ROP reservoir compartments where production wells exist. C. The reservoir pressure datum will be 9,850' feet true vertical depth subsea. d. Pressure surveys may consist of stabilized static pressure measurements (bottom - hole or extrapolated from surface), pressure fall-off tests, pressure build-up tests, multirate tests, drill stem tests, and open -hole formation tests. e. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the AOGCC upon request. f. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule.] 11 a.An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Raven Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b.Data from the surveys required in (a) of this rule shall be submitted with the Annual Raven Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9,850' true vertical feet subsea. Transient pressure surveys obtained by a shut- in buildup test, an injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c.Results and data from anyspecial reservoir pressure monitoringtechniques, chnigues, tests, or surveys shall also be submitted as prescribed in (b) of this rule. If you have any questions regarding this request, please contact Bill Bredar at 564-5348 or through email at William.bredar@bp.com. Sincerely, Katrina Garner PBU Area Manager Cc: J. Schultz, CPAI J. Farr, ExxonMobil Alaska, Production Inc. D. White, Chevron USA D. Sturgis, ExxonMobil Alaska, Production Inc. E. Reinbold, CPAI D. Roby, AOGCC 12 Y —__ Table 1. GPMA Current vs. Proposed Conservation Order Changes (part of Application for Administrative Approval Conforming PBU GPMA Pool Rules for Consisting( 13abom. RewlwmrtCpmx Carn.mn MR[Regmmnmt euwgwci Rprrx.m.m CYnemwwte„eF cum OF. MOI prrtent Rewn pgYMment .-. __. _ _- co n]r fD Mbwmmwlco xlER Re9wymhm co rose Pmw+m pynw xw,+ r PMe3.one-felenim OF rM .i at rn,Il ne nnrmr:nnnr ieV o ' ,IISpnN mmnann mryadni-IMOMMO MMO etne point weW wM1nrn rneaXmeearn e+[ee roar ne atnNlmeNXMw IFM of any a mnom oak toloonn Diner we mmgnmwM1Fm 50)Inrlr°m rAe ne'Manhnealfenlrpn+Feeneonanient". " Atn,u Mona M uM In N,,. aownainal Pron-Minfwehincattail en ryMM-nXthenin unkn'rneownerane 'In �FetaehaheIII OFMIheetl am, n.No prymrymmopen oar Me Monte Pn^ 4 mnsmfrt +iambi. aonbOMI bq eke, w'et aerneaameon mmanngrM need nu,n UM F r n ne mtmear 1}Wefrt 'I. any X Mprya [n w r m " .1MM Me On nM aw1An[n Nan. or openo,I an an SW lett n awtl one. PrWwtNle�l a am h a vnmapp ena oro Colne Y A _ murmrywMeallm_mwn" __ "MMOalhM Mol emnSM)leer hof pMYM ownenXpnr _r_ea._ mN/oMM pe n n0 49eheprnaore e onnen,MoPer an nw M,it1. o -I Met niniomWnmrome +a anM argnwnroh 10,. 33 Pl lief ^M prmurewrvMwR tiv 3a5 P.It )ellnepmwe Surrryr/Pr,un )Pm Puk lhlIXmlrem lMPmuywrvn/., N n m Wrm eCnmmbnen ygrk Naa'na m5rvre+any IwmEM]L • 4reWrlW In rhe pmve.—a..mMeNF onlwm ]Pali Rnemh P4nln^nenp r+ m,M CommM I.-a"Ohnne.,in I [ rm lMll, Report Me he hate he Wryenpm 5pgl] care PeWM1smll be uaMb 3E9nRMe ae 111=:= uePmm�eranMrn rain eXm W CaoI ire amore kne be remn- mmetlt°n un rnW Item P loanwey3,din rrrwMmldpW Month =ha Cmm le+m pmM of Data nem m^ ea aunrya arlkeso Foal u rywnodain pn"a'. °wMh on 1I r eunrya. Ind. aero Y nett mmpowralp4den Rme m npue R Amaro •am anavewnn p.I herubnMo taint +oreal nervpAr on -fain I, on loom I I ro fnrm.a. wmmh er. ..M,o uf^p reWrl. rymr rylor Offel a+ orvryto mon nbrmdbnd ewryaahnnm rnIheT.Mbw. One Nn npa M a Wmpnervmbolewr enyy rvryneMnd aWmXNen the meY nem wnh rF W Me SpMn rryulramenk r°r oM.drN M.1 -p Me, a,- le 'tl[mn eit ,aMweY[Men u ]0. 'am teepee "nn a ltd 'ht bm mutes oa1-he Ibrm ]3 Mmun kewhmnM wpnlXmran ne3ormniwli by mud Me wtnrnelw mE0d13Mmwr msubm Arm Frye. of en m.1 na4We ro 11 .Feng 0. noewMO IMMOMMmral 'n Man, ane" r . own quer aplwoutlaenropW]Inlworclowrdornemlyin carat la Y Xma'.'. ft.O en romPln<anaMYalln aure5urve[. .. _ t _ bmm. uponf_ maubmClm°nrq repwae_ wh Me remn W MM, he wwe Me to lee e 4maryemenr -1 Man *11 Gemmation rrvw NaneaWrwMO/rgmiN. _ _ _. _ 40GCC_Wnrmuar. ._ _ OOF r pnrdnrnneaoXndpnranlonFa EPhwnouer Mo I weer Man "Foon In- 11 -Man" IMMI anif nee, hea-M. Inanition,aif,.... eyN M' on" I vruna Revl, fe onalor,mrnon-o"yea,MSIarpoon FSP I[urren Pq iw [O's,a3i 3.1 NS. 3a5 111,11he 5050. , I. Ifft a1, MaAWi 3S9.p1rany O13. 339 R.Na Do.TNb[den ort Pm an m "n V/ roaXwman[emEpOS. BIn ml IR flf-. Xhtnfrvn SALNflukwMMhab 4 M PooY IXPBee[ Mam11.) maMe xaE'Nane nMpnO a '31)BRpe lIX)4u,M1rk nn p°[ 'flul rly 'v+r MPrdan m'msv M rynwerkw+ not he mlrr Nvnwer eeWN o.,I +nknw MmbwMI'M t n q re, 31)0. rB.X twat pyo Pe )O.y ve SRAM Rukx. Nn nFm[°mmubn Mau, -Comm 'Me_yn rwye epen.n'M (mMwn M°l Mkw4Ymm! Pw rueno I. "� +W e b tlw" rMewn°r ee5q in.VR. MY4Y _ SN.CW/1 nd _. _. __ __ _queHYpmW poWa ntt for lapXne. dnmukM/mmn+brm[v.___ r r rermnm45P mrepkra xaa Pooh 11-11,µlor [O'r NS4031,.Si0N1, ISaR TIM On, onnoteen To. nxmNhe lmM an OfanNl1 Jee, 5w41 pmMenne. )alin 1.,PiM I 3]'BRuk mol Prmunenlrom eunxNl abed' SmIId, fO/Woat"I' annotrleen j M9 ma m I'llo Penhanat foo, n°mml,- Mae -M-h dv annotation M l°Ibwrr wN4m albmb n w M onnmrmY M the f°mxlN Mel .3He Then Pr°euTan lmneM wen WflI 'enod+amrY r eae Mon,Mhm M r M MOMM Me, nu, ern otlnor m[Irv}IONewrg4PW mnnmobRy.glrxaXm eda mnbM nM hombRY.4wombn iGMrMnen MIMIUIbNnRwNlrnrnMdbn money vrlhwpI to the ismw ed 4e °talon mon°nology.Nbminnnna of Mn1-13l,-'a YexF3rah. wYIM on. and a.e cal I ... to m MMOMMa...a.I .w M,uenme Mlnc ae mwhh le Mm trrepkemne 6'nnmhswn en ena n.11 be aupprim mtM 3as1 w emm Me ennee.n C6wMepnSA+PY1 me[mmmmnn nwghnmmmmpmd kaupY'mmde[°mmapbnrrnnghn.1 rk ane 171 m.mla�n Yn Manwk mr aoc[C mcew en 1-1 Mw ane Phot- Pr°rMe n° PramRbn in an.0 DF,,n 1pmau Xq pte mprfwm.n. ��xane Memrt la mpreWnfu epnrtm M,MMMdrt kk 'fwHR l.AspeY rquvememaperplm M -ON 1)NOl hve Mon In Frye remn ._ _ _____ _mmarymlMV1)mewklwwnun000w° n H 5(YNarnwlumnwtllM Mon, -I . MRPUMPMS anarnkM oona,u°I 'aPpenemernoe,w Oheraeol nwWmnM IIM n : I 31WMn Wum wlllM Inemiryproren. M-I .. r.Jn. mmlrnevner rmin. M.VI/Mp SroppM MennmpmM mine M4N/MPMS Mpwdmmnnmr,w re6nWnnwlunn wAlMnnnminm <taff, a".onII e+wihewee+ r O.I.M."Whemrumne mh,u,ueueorneuwpwen.on"q /MpaWrnyn mono., arms meor 'approrm Mme fommmmn. ury w nm.ewo. �. ttrR+MM. aea..'ar.tamprn hnmmM rMnemldenam mYweno. n� q AY ISM ) e lY Ma arcaTO wremmm a-anthr III I Dot ann,rn antlMtn, tom pmeupeR we nn rvnrremv. dknptM,e[merYmmm�Ym[FmnmyhrMprWwlmmanMrMen w,YMwM. ryIn.nn ry MM W.Cam®elnry wmM M, Manno-Olt em I o mM Mem�N Mw RPYAmn OF 1. ma mr. YueNI-I m.I-roan.. mm an5mt Me not Mae. M e M -Meana. Me IF M aeermnne.1 wmF w 0 MM 'M P/MP s Pp w 1.1 iI.-In.Mwm '.. an"u�M enta nota.". MOMM LONTI ,e MMMPMS,Pprn.e a "v Wn. by ne annul, M M+ pm. O.J.P.ampka°w IMMM ont000 . Fmn tempka [ena appmm mnom, j am an, hen aampn wlle 4Ym ane... 1.TTOI p "'Me"mr no' -res mmpwtion-han mnM "a' N(rnumpnwllmuYen Of an, naryamlwmmuM bn omeeM nen Sd n frwn In on 11. haenel ve n Freepeauen, exn Bdwm prnea". "P yn5wnnnh°m wNnonwtlX.Ma.ln ut pnm mWn cam _ "wellrwN. ImewnYwNlwu, _ __ _ na"Mone"Mn.1.M a a.,. a'. m°mh, Mel, lnrbnh, IFMAm,r. remn fro van. done DMOMr F, .11 wuM Mona Monea.n m,bwa: Icon lore[cmewdlM.11. to PDP M n Snew n: on,, Wr. earn ' I OYMMPrmunbnfaiNb Pr ineene uKKlmm MCLLWrne O4 Po°x Wnr OeamMPoOI,XnrNlrmhwxry OilPod. I nithlM 'x4Mrtp=I Mamde Dermot hump o ne o" I and Rry IP. mn mmYwno teMT--Mee .Faahp r°eu[mYw,I wpMNlmm en ryelE pre [,aril 4 9 n m "Pu Nn reapOw h one.. M taea..IprewunY done The-'eaf Gemmed Rmudlnn e6[4M-11,mrnr Me Mteato. IhmmmnM _ _ ewh Doth' _ m yYen 'kadrwle_ena _. - _ mono olniw ermonrn. mryM .Nan the Mab °I n uy m nENm. Itwkel MxcEmn MMwe d nY en[rmeeY mnamnien 4! n rnOnb DrM. 3o)BRnk9grnemaxsNmewellratinmowNM ,IF n r rem,w .SMY4m GORimwmmmn M. waewerrawemMmYomn,nmunion egnn mar j F.Mi dOiRW Tent Wtl -'mnWnY'rymr;eM Wetnam4n rrtnMwe. proWaa In n[uh44Mnbnranor _ m w.y.nelWyanmy... x4 _xq_ w '.w xn ir`p°rtwk In. pwunpnMMt M°rmelmn. _-.1- __ _ "_��mM,Ronmp. pgb ya"e.maedu R.bprmremd ion-fe.-Mono. dton M.hne". Mwrmmrwm. Rmnmoe, caw. Mmnbywkn RPL.mxlaW¢x9Yasdpw.m Mldti.nmmnheryerkNewnnlaemne anne, an r anotheMent I wdnlNenbn feet avu.' a91 Mn Mann. in w in oftmp�Copia. eeMOM MMM Me to Mane Mean° mfmr and ana°No- the - .an ane MFM', a,. r nMPm ^ImnrY_DM J - h^L5-39 Ya yP M, MI)Ir. and lo-. brjeeem me h 1110. web r M wan ml.edpa mr, and I Imkemn pmurn now M ma... Mbw 0 55 jog he nnueneortmutMwmnM.m tM C°mmMien nea6N MeMmrm W n d e PMO a.-OAa-, mFit m PralM ' 'MOMMIM mwa Pitioninlarmron for Manne. rrdlMMV MMr,mkipa.ry e thent loned an mined'. [orywnbhn-1 if. That" r F" nfnae ingrt on Yedwr nen m.. a, I the "-_- 1L1 no ParMen onNmelryenpnmeYmn Yreyued.. Prod.bnenana reswmemlMurna[CNIhe10 mNlm tlreymOneogrn rnPonO to ywmF oryNtr mn .gimme rebNe mawgmem. Nd env a Ymn ~$ • • ra~C i ui ~ Roby, David S (DOA) From: Roby, David S (DOA) Sent: Thursday, September 27, 2007 1:16 PM To: Williamson, Mary J (DOA); Foerster, Catherine P (DOA); Maunder, Thomas E (DOA) Subject: RE: Raven and Niakuk allocation issues It was BP that requested to use the WOA plan, 1 think they probably just cut and pasted from a prior western satellite application/order. Dave Roby Phone: 907-793-1232 email: dave_roby c alaska_,g_ov From: WiNiamson, Mary J (DOA) Sent: Thursday, September 27, 2007 1:13 PM To: Roby, David S (DOA); Foerster, Catherine P (DOA); Maunder, Thomas E (DOA) Subject: RE: Raven and Niakuk allocation issues You are absolutely correct it should be consistent with C0362. 6'm sorry I didn't catch that when we recommended rules on Raven. From: Roby, David S (DOA) Sent: Thursday, September 27, 2007 12:59 PM To: Foerster, Catherine P (DOA); Maunder, Thomas E (DOA); Williamson, Mary J (DOA) Subject: Raven and Niakuk allocation issues BP sent in an application a little while ago to make their pilot downhole commingling project for the NK-43 permanent. The pilot project was to prove up the viability of using geochemical fingerprinting as a method to allocate between the two pools. When the pilot project began the pools were identified as the Niakuk Oil Pool and the Sag River Formation Undefined Oil Pool. In August 2006 CO 570 established the Raven Oil Pool, which includes the Sag River Formation in the project area. While reviewing the application it was discovered that the Niakuk and Raven pools had what appeared to be different methods approved for the purpose of surface allocation. The Niakuk allocation is governed by CO 362 that applies to all pools, except Raven, that are processed through Lisburne facilities and is based on twice monthly well tests. The Raven pool rules, at BP's request, state that allocation would be done in accordance with the PBU Western Operating Metering Plan from 2002, which does allocation based on well production performance curves. The different methods raised the issue of how can you allocate production within the wellbore when you have inconsistent methods of allocating production to the wellhead? The Raven Oil Pool, which contains two producers and one injector, is the only pool processed at the LPC that utilizes the WOA metering plan. However, reviewing the WOA metering plan it appears that it only applies to pools that are processed at GC1 or GC2. Therefore, it seems that the Raven pool rules reference an allocation methodology that is not applicable to Raven and therefore should be amended. BP's request is that the Raven Pool Rules be administratively amended so that surface commingling and allocation is done in accordance with C0362. I support this request for a few reasons, 1) It appears that WOA metering plan isn't applicable to Raven since it only applies to GC1 and GC2 and not the LPC, 10/12/2007 • • rage ~ or ~ 2) Amending the Raven Pool Rules to be consistent with all other LPC processed pools removes the stumbling block to approving BP's downhole commingling request, and 3) It doesn't make sense for production from a facility to be allocated differently to two wells than to all of the other wells. Before proceeding down the path of amending the Raven Pool Rules and finishing up the NK-43 commingling request I wanted to get your opinions. Thanks, ®ave R®by Reservoir Engineer Alaska Oil and Gas Conservation Commission Phone: 907-793-1232 Fax: 907-276-7542 email: da_v__z_roby@alaska._gov 10/12/2007 -:tt7 GPMA Pt. McIntyre P2 well .g . Page 1 of2 Colombie, Jody J (DOA) From: Carr, Jessie L [Jessie.Carr@bp.com] Sent: Tuesday, July 10,20072:00 PM To: Roby, David S (DOA) Subject: RE: GPMA pt. Mcintyre P2 well testing Dave, 1) Please address the letter to Mark Weggeland (GPMA Resource Manager). 2) The test separator was taken out of service on June 27,2007. I apologize for not informing you sooner but I was out on vacation. Jessie From: Roby, David 5 (DDA) [mailto:dave.roby@alaska.gov] Sent: Tuesday, July 10, 2007 12:32 PM To: Carr, Jessie L Subject: RE: GPMA pt. McIntyre P2 well testing Jessie, Two more questions: 1) Should I address the Administrative Approval letter to you or Mark Weggeland? 2) For the record on what date was the P2 test separator taken out of service? Thanks, Dave Roby Phone: 907-793-1232 email :QªYe_rQºy@ªIª§!g¡,go\( From: Carr, Jessie L [mailto:Jessie.Carr@bp.com] Sent: Tuesday, July 10, 2007 10:38 AM To: Roby, David 5 (DDA) Cc: Frankenburg, Amy; Carr, Jessie L Subject: RE: GPMA pt. McIntyre P2 well testing Dave, The 24" commonline tie-in work has begun, and the P2 test separator is out of service until the work is complete in late July or early August. Jessie From: Roby, David 5 (DDA) [mailto:dave.roby@alaska.gov] Sent: Tuesday, July 10, 2007 10:21 AM To: Carr, Jessie L Subject: RE: GPMA Pt. McIntyre P2 well testing 7/11/2007 GPMA Pt. McIntyre P2 well .g . Page 2 of2 Jessie, When is the work scheduled to begin, or has it already begun? Dave Roby Phone: 907-793-1232 email: Qªve_CQþy@ªIª§Kª,90V From: Carr, Jessie L [mailto:Jessie.Carr@bp.com] Sent: Tuesday, July 10, 2007 9:59 AM To: Roby, David 5 (DDA) Cc: Frankenburg, Amy; Weggeland, Mark C; Mitchell, Alan W Subject: GPMA pt. McIntyre P2 well testing July 10, 2007 Dave, This email communication is to inform you that the test separator at pt. Mcintyre P2 pad will be temporarily unable to obtain well tests for the next several weeks. Testing at P2 must be suspended during the final tie-ins on the new 24" common line to the Lisburne Production Center (LPC). The 24" piping tie-ins require energy isolation at P2 pad for safety reasons. The pressure safety valve (PSV) on the P2 test separator is designed to relieve pressure to the 24" common line in the event that the test separator pressure is too high. The PSV is now needed as a second barrier for energy isolation between process fluids and the 24" commonline and must remain closed. So no fluids may enter the test separator in case the PSV opens to relieve vessel pressure and violates the "double block and bleed" required for safety. The well test separator on pt. Mcintyre P2 pad will remain out of service until the 24" common line is placed in service in late July or early August. Normal testing at P2 pad will resume at that time. BP requests an exemption to the pt Mcintyre pools rules and permission to suspend well testing at PM2 pad until the 24" common line is placed in service. If you have any further questions or request for information, please feel free to contact me. Regards, Jessie L. Carr GPMA pt. Mcintyre PE (907) 564-5015 7/11/2007 . GPMA Pt. McIntyre P2 well teg . Page 1 of2 Colombie, Jody J (DOA) From: Carr, Jessie L [Jessie.Carr@bp.com] Sent: Tuesday, July 10, 2007 1 :51 PM To: Roby, David S (DOA) Subject: RE: GPMA pt. Mcintyre P2 well testing Sorry for the confusion. I think that PM2 (pt. Mcintyre 2) would be the proper designation. Thanks, Jessie From: Roby, David 5 (DDA) [mailto:dave.roby@alaska.gov] Sent: Tuesday, July 10, 2007 1:47 PM To: Carr, Jessie L Subject: RE: GPMA pt. McIntyre P2 well testing One more question. In your original email you refer to both the P2 pad and the PM2 pad I am assuming that these are one and the same. If they are the same what is the proper designation for the pad, if they are not the same which pad are you requesting the waiver for? Thanks, Dave Roby Phone: 907-793-1232 email: dave_roby@alaska.gov From: Carr, Jessie L [mailto:Jessie.Carr@bp.com] Sent: Tuesday, July 10, 2007 10:38 AM To: Roby, David 5 (DDA) Cc: Frankenburg, Amy; Carr, Jessie L Subject: RE: GPMA pt. McIntyre P2 well testing Dave, The 24" commonline tie-in work has begun, and the P2 test separator is out of service until the work is complete in late July or early August. Jessie From: Roby, David 5 (DDA) [mailto:dave.roby@alaska.gov] Sent: Tuesday, July 10, 2007 10:21 AM To: Carr, Jessie L Subject: RE: GPMA pt. McIntyre P2 well testing Jessie, When is the work scheduled to begin, or has it already begun? Dave Roby 7/11/2007 I GPMA Pt. McIntyre P2 well .g . Page 2 of2 Phone: 907-793-1232 email:Qªve_CQÞy@ªIª§Kª,9QV From: Carr, Jessie L [mailto:Jessie.Carr@bp.com] Sent: Tuesday, July 10, 20079:59 AM To: Roby, David 5 (DDA) Cc: Frankenburg, Amy; Weggeland, Mark C; Mitchell, Alan W Subject: GPMA pt. McIntyre P2 well testing July 10, 2007 Dave, This email communication is to inform you that the test separator at pt. Mcintyre P2 pad will be temporarily unable to obtain well tests for the next several weeks. Testing at P2 must be suspended during the final tie-ins on the new 24" common line to the Lisburne Production Center (LPC). The 24" piping tie-ins require energy isolation at P2 pad for safety reasons. The pressure safety valve (PSV) on the P2 test separator is designed to relieve pressure to the 24" commonline in the event that the test separator pressure is too high. The PSV is now needed as a second barrier for energy isolation between process fluids and the 24" common line and must remain closed. So no fluids may enter the test separator in case the PSV opens to relieve vessel pressure and violates the "double block and bleed" required for safety. The well test separator on pt. Mcintyre P2 pad will remain out of service until the 24" common line is placed in service in late July or early August. Normal testing at P2 pad will resume at that time. BP requests an exemption to the pt Mcintyre pools rules and permission to suspend well testing at PM2 pad until the 24" commonline is placed in service. If you have any further questions or request for information, please feel free to contact me. Regards, Jessie L. Carr GPMA pt. Mcintyre PE (907) 564-5015 7/11/2007 GPMA Pt. McIntyre P2 well .g . Page 1 of 1 Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Tuesday, July 10, 2007 10:45 AM To: Colombie, Jody J (DOA) Subject: FW: GPMA pt. Mcintyre P2 well testing Jody, Here is an admin approval request that I just received and will process shortly. I believe it is related to CD 362, but will double check that for you when I prepare the write-up. Dave Roby Phone: 907-793-1232 email:qªVe...Joþy@ªI~Kª.9Q\( From: Carr, Jessie L [mailto:Jessie.Carr@bp.com] Sent: Tuesday, July 10, 2007 9:59 AM To: Roby, David 5 (DDA) Cc: Frankenburg, Amy; Weggeland, Mark C; Mitchell, Alan W Subject: GPMA pt. McIntyre P2 well testing July 10, 2007 Dave, This email communication is to inform you that the test separator at Pt. Mcintyre P2 pad will be temporarily unable to obtain well tests for the next several weeks. Testing at P2 must be suspended during the final tie-ins on the new 24" commonline to the Lisburne Production Center (LPC). The 24" piping tie-ins require energy isolation at P2 pad for safety reasons. The pressure safety valve (PSV) on the P2 test separator is designed to relieve pressure to the 24" common line in the event that the test separator pressure is too high. The PSV is now needed as a second barrier for energy isolation between process fluids and the 24" commonline and must remain closed. So no fluids may enter the test separator in case the PSV opens to relieve vessel pressure and violates the "double block and bleed" required for safety. The well test separator on pt. Mcintyre P2 pad will remain out of service until the 24" commonline is placed in service in late July or early August. Normal testing at P2 pad will resume at that time. BP requests an exemption to the pt Mcintyre pools rules and permission to suspend well testing at PM2 pad until the 24" commonline is placed in service. If you have any further questions or request for information, please feel free to contact me. Regards, Jessie L. Carr GPMA pt. Mcintyre PE (907) 564-5015 7/1112007 GPMA Pt. McIntyre P2 well teg . Page 1 of2 Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Tuesday, July 10, 2007 10:56 AM To: Colombie, Jody J (DOA) Subject: FW: GPMA pt. Mcintyre P2 well testing Here is an email for the CO 362A.004 file. Dave Roby Phone: 907-793-1232 email: dave_roby@alaska.gov From: Carr, Jessie L [mailto:Jessie.Carr@bp.com] Sent: Tuesday, July 10, 2007 10:38 AM To: Roby, David 5 (DDA) Cc: Frankenburg, Amy; Carr, Jessie L Subject: RE: GPMA pt. McIntyre P2 well testing Dave, The 24" commonline tie-in work has begun, and the P2 test separator is out of service until the work is complete in late July or early August. Jessie From: Roby, David 5 (DDA) [mailto:dave.roby@alaska.gov] Sent: Tuesday, July 10, 2007 10:21 AM To: Carr, Jessie L Subject: RE: GPMA pt. McIntyre P2 well testing Jessie, When is the work scheduled to begin, or has it already begun? Dave Roby Phone: 907-793-1232 email :qªye_rQþy@ªIª§I<ª.9QY From: Carr, Jessie L [mailto:Jessie.Carr@bp.com] Sent: Tuesday, July 10, 2007 9:59 AM To: Roby, David 5 (DDA) Cc: Frankenburg, Amy; Weggeland, Mark C; Mitchell, Alan W Subject: GPMA pt. McIntyre P2 well testing July 10, 2007 Dave, This email communication is to inform you thatthetestseparatoratPt. Mcintyre P2 pad will be temporarily unable to obtain well tests for the next several weeks. Testing at P2 must be suspended during the final tie-ins on the 7/10/2007 GPMA Pt. McIntyre P2 well eg . Page 2 of2 new 24" common line to the Lisburne Production Center (LPC). The 24" piping tie-ins require energy isolation at P2 pad for safety reasons. The pressure safety valve (PSV) on the P2 test separator is designed to relieve pressure to the 24" common line in the event that the test separator pressure is too high. The PSV is now needed as a second barrier for energy isolation between process fluids and the 24" commonline and must remain closed. So no fluids may enter the test separator in case the PSV opens to relieve vessel pressure and violates the "double block and bleed" required for safety. The well test separator on pt. Mcintyre P2 pad will remain out of service until the 24" common line is placed in service in late July or early August. Normal testing at P2 pad will resume at that time. BP requests an exemption to the pt Mcintyre pools rules and permission to suspend well testing at PM2 pad until the 24" common line is placed in service. If you have any further questions or request for information, please feel free to contact me. Regards, Jessie L. Carr GPMA pt. Mcintyre PE (907) 564-5015 7/1 012007 #6 FW: Commingling approval . . Subject: FW: Commingling approval From: Cammy Taylor <cammy_taylor@dnr.state.ak.us> Date: Fri, 13 Apr 200709:25:07 -0800 To: Jody Colombie <jody _ colombie@admin.state.ak.us> CC: Cathy Foerster <cathy _foerster@admin.state.ak.us>, Alan Birnbaum <alan _ birnbaum@law.state.ak.us> Sharri Gould told me yesterday that they needed to correct the well names that were referred to in their application to commingle production from IP A production with Lisburne production. Here are the correct names. I sent the e-mail to Dave Roby this morning, but just learned that he is out of the office. Thanks, Cammy From: Gould, Sherri L [mailto:Sherri.Gould@bp.com] sent: Friday, April 13, 2007 8:27 AM To: Cammy Taylor Subject: RE: Commingling approval Hi Cammy, Great to meet you too! Here are the correct well names. L2-03A L2-07 A L2-08A L2-Il L2-13A L2-18A Thanks, Sherri From: Cammy Taylor [mailto:cammy_taylor@dnr.state.ak.us] Sent: Thursday, April 12, 2007 4:37 PM To: Gould, Sherri L Subject: Commingling approval Sherri, It was great to meet you today. If you could e-mail me the correct well name/numbers for those 6 IF A wells I can add them to the approval letter and try to get it signed tomorrow. Thanks, Cammy Cammy Oechsli Taylor Petroleum Land Manager Department of Natural Resources Division of Oil and Gas 550 W. 7th Ave., Ste 800 Anchorage, AK 99501-3510 907-269-8817 10fl 4/1312007 9:26 AM #5 ~1J&u~ f &~~æ& DIVISION OF OIL & GAS . SARAH PALIN, GOVERNOR . DEPARTMENT OF NATURAL RESOURCES 550 WEST 7TH AVENUE, SUITE 800 ANCHORAGE. ALASKA 99501·3560 PHONE: (907) 269-8800 FAX: (907) 269-8938 CERTIFIED MAIL RETURN RECEIPT REQUESTED April 12, 2007 Mark C. Weggeland GPMA Resource Manager BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99519-6612 Re: Request to Commingle Production from the Initial Participating Area with Lisburne Participating Area Production Dear Mr. Weggeland: By letter dated April 2, 2007, BP Exploration (Alaska) Inc. (BPXA), as Operator ofthe Initial Participating Area (IP A) within the Prudhoe Bay Unit (PBU), requested authorization to commingle a portion of the production from the IPA of the PBU with production from the Lisburne Participating Area (LP A) that is processed through the Lisburne Production Center (LPC). Six IPA wells (L2-03A, L2-07A, L2-08A, L2-11, L2-13A, and L2-18A) located on the Lisburne L2 pad are currently connected to DS-18 by a pipeline and processed at FS-1. These six wells are currently cycled on and off, depending on whether their marginal gas oil ratio (GOR) is competitive with lower GOR production at the FS-I processing facility. Because the LPC is not currently gas- constrained, BPXA proposes to re-route this partially shut-in production through the L2 pad to the LPC processing facility and maintain full-time production ÍÌ'om these wells. The Division of Oil and Gas (Division) approves BPXA's request to commingle production ÍÌ'om the IPA with production ITom the LPA with the following conditions: (a) BPXA shall report production from the six IP A wells at the LPC as IP A production and include it on the IP A production reports; (b) BPXA shall report these volwnes to the Division using selling arrangement number 207002FOOO on the PRUD and PGAS accounting unit oil operator reports (0 I); (c) production from PBU IP A wells to the LPC shall be determined and allocated in accordance with the GPMA metering and allocation procedures; (d) NGLs removed from gas produced by these PBU IPA wells at the LPC shall be accounted for and reported as IPA NOLs; (e) BPXA shall provide the Division the appropriate NOL yield for IP A NGLs produced at the LPC within 10 days of the determination and provide the Division with the annual OPMA NGL allocation update; and (t) the updated Lisburne POD, due in June 2007, shall incorporate a description of operations " associated with these six wells. "Develop, COllserve, a"d EIIIlallce Natllral Resollrces for Presel1t mid Flltllre Alaskalls. " . . Division of Oil & Gas 4/13/07 p'age 2 of2 . A person affected by this decision may appeal it, in accordance with II AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040 (c) and (d), and may be mailed or delivered to Tom Irwin, Commissioner, DNR, 550 W. 7th avenue, Suite 1400, Anchorage, Alaska 99501; faxed to I -907-269-8918, or sent by electronic mail to dnrappeals@dnr.state.ak.us . This decision takes effect immediately. An eligible person must first appeal this decision in accordance with II AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. If you have any questions regarding this decision, contact Cammy Taylor with the Division at 907- 269-8817. cc: Sherri Gould, BPXA Sam French, BPXA Gary Benson, BPXA Ted Cahalane, BPXA Tim Verseput, BPXA Eric Reinbold, ConocoPhillips Gary Forsthoff, Chevron Hank Bensmiller, ExxonMobil John Norman, AOGCC Dave Roby, AOGCC Tom Maunder, AOGCC John Iversen, DOR Cammy Taylor, DNR Jim Stouffer, DNR Jeff Landry, DOL [Fwd: PBU IPA & Lisburne - Production Req. . . Subject: [Fwd: PBU IP A & Lisburne - Production Request] From: John Norman <john _ norman@admin.state.ak.us> Date: Wed, 04 Apr 2007 15:58:11 -0800 To: Jody J Colombie <jody_colombie@admin.state.ak.us> print cover e-mail for file --.----- Original Message -------- Subject:PBU IP A & Lisburne - Production Request Date:Tue, 03 Apr 2007 14:50:12 -0800 From:Stevens, Ellen <ellen.stevens(G?bp.com> To:Kevin Banks <kevin banks(G?dnr.state.ak.us>, John Norman <john norman(G?admin.state.ak.us> CC:Dave Roby <dave roby(G?admin.state.ak.us>, Tom Maunder <tom maunder(G?admin.state.ak.us>, Jon Iversen <ionathan iversen(G?revenue.state.ak.us>, Camille Taylor <camille taylor(G?dnr.state.ak.us>, Hank Bensmiller <hank.d.bensmiller(G?exxonmobil.com>, "Gould, Sherri L" <Sherrì.Gould(G?BP.com>, "French, Samuel WIt <SamueI.French(G?BP.com>, "Cahalane, Ted WIt <Ted.Cahalane(G?BP.com>, "Benson, Gary A" <Gary.Benson(G?BP.com>, "Verseput, Tim" <Tim. V erseput(G?BP .com>, "ForsthofI, Gary" <gmfo(G?chevrontexaco.com>, "Reinbold, Eric W (Phillips)" <EREINBO(a¿,ppco.com> All, For your review, attached please find a letter from BP regarding the production request pertaining to PBU IPA and Lisburne Participating Area. Should you have any questions, please do not hesitate to contact me at your convenience. Ellen Stevens PBU Coordinator 907.546.5933 «070402 PBU IPA and Lisburne - Production request.pdf» John K. Norman <John Norman(G?admin.state.us> Chairman Alaska Oil & Gas Conservation Commission Content-Type: application/octet-stream 070402 PBU IP A and Lisburne - Production request.pdf Content-Encoding: base64 10ft 4/6/2007 6:37 AM #4 . . bp 0·····················'··········.......... ........... .... /. BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 April 2, 2007 Mr. Kevin Banks, Acting Director Division of Oil and Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, AK 99501 Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Request to Commingle Production from the Initial Participating Area with Lisburne Participating Area Production Dear Chairman Norman and Acting Director Banks: BP Exploration (Alaska) Inc. (BPXA), as Operator of the Initial Participating Area (IP A) within the Prudhoe Bay Unit (PBU), requests authorization, through Administrative Amendment to Conservation Orders 362A and 341 E, to commingle a portion of the production from the IP A of the PBU with the Lisburne Participating Area (LP A) production through surface facilities at DS- 18, Lisburne L2 pad and LPC processing facilities. Currently six IP A wells are located on the Lisburne L2 pad, but are connected to DS-I8 by a pipeline. These six wells are: L2-II, L2-13, L2·07, L2-03, L2-08 and L2-I8. All six wells are currently cycled on and off, depending on whether their marginal GOR is competitive with lower GOR production at the FS-l processing facility. BPXA has identified a way, because the LPC is not currently gas-constrained, to re-route this partially shut-in production to LP A facilities and maintain full-time production. The LPC also has a lower marginal GOR than FS-I when it is gas-constrained. BPXA plans to install a jumper line that will re-route the IP A production from these six wells through the L2 pad to the LPC. Production from these IP A wells will be commingled with LP A fluids at the L2-Pad and delivered to the LPC processing facility. All wells will have the ability to be well tested separately. According to our current schedule, the jumper line could be in place and the wells ready to commence production as early as April 16, 2007. Figure I is a diagram of the facilities and pipelines involved. The intent is for the commingling to continue indefinitely. The planned engineering design includes simple valving that provides the ability to reverse production back to the IP A should that become desirable in the future. This project will also allow Lisburne to recover a portion of the LP A gas production that is currently exported to the GC-I IP A processing facility and injected into the Prudhoe reservoir. This will assist in voidage replacement in the Lisburne reservoir. A portion of the Lisburne produced gas currently is exported for use as lift gas and gas cap injection gas in the Point McIntyre field. Point McIntyre production routed through GC-I is not returned to GPMA reservoirs. . . Mr. Kevin Banks Mr. John Norman April 2, 2007 Page 2 For royalty and tax purposes, production from PBU IP A wells at the LPC will be reported as IP A production and included on the IP A production reports. Production from PBU IP A wells to the LPC will be determined and allocated in accordance with the GPMA metering and allocation procedures. NGLs removed from gas produced by these PBU IP A wells at the LPC will be accounted for and reported as IP A NGLs and taxed in the same manner as other NGLs produced at the LPC. PBU IP A will be allocated a proportionate share of LPC fuel and flare gas associated with production from these wells in a manner consistent with the allocation of fuel and flare to other GPMA Participating Areas. Gas produced will either be consumed in operations or injected into the Lisburne (Wahoo) Reservoir and tracked as PBU IP A gas on the GPMA Gas Reserve Debit Report. The updated Lisburne POD, due in June 2007, will incorporate a description of operations associated with this well. BPXA staff are available should you have any questions or need any additional information. If you need any additional information, please contact Sherri Gould at 564~5942. Sincerely Yours, /'1\/ \ (,\' { . V'^-~ v.J , ~v-J\ Mark C. Weggeland ~ GPMA Resource Manager Attachment: Figure I: L2 Production Reroute Project cc: Dave Roby, AOGCC Tom Maunder, AOGCC John Iversen, DOR Cammy Taylor, DNR Hank Bensmiller, ExxonMobil Eric Reinbold, ConocoPhillips Gary Forsthoff, Chevron Sherri Gould, BPXA Sam French, BPXA Gary Benson, BPXA Ted Cahalane, BPXA Tim Verseput, BPXA . . Figure I : L2 Production Reroute Project MOO 4922 - WELL MANlFOLDBUlLDtNG FOR O$UEVEN NUMBERED WELLS MOO 49~ - WELL. MANIFOLD BUILOING FOR DS-L2 ODD NUMBERED weLlS MOD 4902- HEATED BUILDING FOR ESO VALVES, TEST SEPARATOR, MID HEATER DSl2 r-·-·..·-·..-··..···...-··......---·-··---·-··-·..--..--·..···--- ¡ j I 1 I I....................................................................._..._..............................-j - EXISTINGUNES - PROJECT SCOPE Attachment *3 bp e e BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Mr. Bill Van Dyke, Acting Director Mr. John Norman, Chairman Division of Oil and Gas Alaska Oil and Gas Conservation ~--_.------------~._- .~---------"--- ~Departmenfõfl'\IaturarHesou rces~-Commlsslon-- 550 West 7th Avenue, Suite 800 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Anchorage, Alaska 99501 Re: Request for Prudhoe Bay IPA Production Metering Changes to Accommodate EOA Facility Resumption at FS-3 Due to Shut-In Oil Transit Lines Dear Chairman Norman and Acting Director Van Dyke, BP Exploration (Alaska) Inc. (BPXA) as Operator of the Prudhoe Bay Unit requests authorization to alter the metering configuration utilized in the Prudhoe Bay Initial Participating Area (IPA) and the Greater Point Mcintyre Area (GPMA) so that early restoration of production from the Eastern Operating Area (EOA) of the Prudhoe Bay field can occur. These changes are being sought due to the shutdown of the EOA Oil Transit Line which is undergoing repair / replacement. The changes requested in this application will allow production rates to resume from Flow Station NO.3 (FS-3) and Gathering Center NO.3 (GC-3). This is one of three related applications for metering changes to accommodate EOA production resumption. The other applications (filed separately) pertain to: 1) the re-routing of Flow Station No. 1 (FS-1) and Flow Station No.2 (FS-2) production through the Endicott Sales Oil Pipeline; and 2) re-routing of the Crude Oil Topping Plant (COTP) to the Endicott Sales Oil Pipeline. The metering changes proposed in this application affect the location of the Lease Automatic Custody Transfer (LACT) meters and require changes to the individual FS-3 and Lisburne Production Center (LPC) facility volume allocation procedures, but do not affect current well testing or well allocation procedures. The proposed new facility allocation process for FS-3 and LPC is entirely consistent with the current methodology Page 1 bp e e BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 for Prudhoe Bay described in the Western Satellite Metering Plan and is further described in the attached excerpts from the Presentation that you received on August ~9th-(S-e-e-Atta-chmenrr:r--------~------~~--~- ~ ------ Lisburne Pipeline Connections: FS-3 and LPC Metering As you are aware, plans are underway to utilize" bypass" piping arrangements to connect FS-3 to the Lisburne Sales Oil Pipeline1. This is not a regulated common carrier sales oil pipeline; it is an on-lease oil transit line, owned and operated by the Prudhoe Bay Unit that delivers sales quality crude from LPC to Pump Station No. 1 (PS-1). G I~C Line / Hydraulic calculations indicate that the Lisburne Pipeline has sufficient excess capacity to carry the incremental volume from FS-3 (including GC-3 production) of 70,000 barrels per day (nominally) without causing any impact to LPC or FS-3/ GC-3 production rates. - N"wC,,,,,,,,,¿iOI,. A potential reduction of 2,000 _ '''MerC",''''€x,.tirJU"", 5,000 barrels per day is expected due to utilization of the OS-150 common line for the tie-in2. Work is also progressing to determine if there is sufficient incremental capacity 1 A new twelve-inch (12") line downstream of the F8-3 meter run will be installed to allow for flow to the 08-150 common line (in the reverse direction). A second new twelve-inch (12") diameter line and hot tap will be constructed to connect the 08-150 common line into the Lisburne 8ales Oil Pipeline. The 08-150 common line is a Prudhoe Bay Unit-owned and operated line and will flow approximately 70,000 barrels per day. 2 The 08-150 common line traditionally carried high pressure 3-phase production from 08-15 to F8-3. For the purposes of this bypass arrangement, this line will now be used in the opposite direction to Page 2 bp e e BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 available in the Lisburne Sales Oil Pipeline to allow early production from FS-1 to FS-3 via the Gas Handling Expansion (GHX) tie-line3. -~~"--------~-"---"-'---- ~------- "--"--- ---------~,_._--- The new FS-3 bypass will re-route oil production from a point downstream of the FS-3 shipping pumps and meters4 to the Lisburne Sales Oil Pipeline at a point downstream of the LPC shipping pumps and meters. No incremental back-pressure effects are expected on the wells flowing to LPC or FS-35. LPC facility volumes are currently metered at the PS-1 LACT meter on the Lisburne Sales Oil Pipeline, as this is currently a dedicated pipeline. The proposed metering changes, however, do not result in any methodological difference to the manner by which production allocation is currently handled within the Prudhoe Bay IPA. On a conceptual level, it approaches LPC metering on the same basis as is currently applied at the Gathering Centers (GC's) and Flow Stations (FS's). Prior to shutdown of the EOA Oil Transit Line, all liquid production leaving the Prudhoe Bay facilities was measured at the single PS-1 LACT meter (plus crude oil volumes withdrawn at the COTP). This measurement represented the known daily total liquid volume - and all crude oil facility meter readings upstream from this point were proportionally normalized so that they summed to this known amount6 (after accounting for NGL volumes in the blended PS-1 stream). transport sales quality oil from FS-3 to its jumper point into the Lisburne Sales Oil Pipeline. As a consequence, high pressure production normally transported down the OS-150 common line will be commingled, to the extent possible, into other OS-15 common lines, creating a net reduction of some 2,000 to 5,000 barrels per day. 3 This would be an interim solution that would provide an incremental (but limited) production benefit until such time as the FS-1 connection into the Endicott Sales Oil Pipeline is available. 4 Sales quality oil emanating from FS-3 also contains production sourced from GC-3 (via the fizzy oil line), and may include some early FS-1 production via the GHX tie-line. 5 Ouring normal operating conditions, there are no anticipated constraints on production at LPC or FS-3 beyond the current constraints such as gas compression, flare, water-handling limits, etc. 6 This approach created a daily GC/FS facility meter allocation factor used to normalize the upstream crude oil meter readings at FS-1, FS-2, FS-3, GC-1 and GC-2. The daily GC/FS meter allocation factor is a ratio equal to the PS-1 LACT meter plus the COTP supply meter minus the COTP return meter minus Page 3 bp e e BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O Box 196612 Anchorage, Alaska 99519-6612 (90?) 561-5111 The proposed FS-3 bypass arrangement utilizes the same concept. When FS-3 is connecteBlOffleDsDurne Sales 'OirPipeline, fne-rnBiviauarFS-=-3 anBTPC met~~--------" readings will be similarly normalized back to the known reading on the PS-1 Lisburne LAGT meter? During this period, FS-3 volumes will no longer be included in the Prudhoe Bay IPA calculation. Upon start-up of the FS-3 connection, the existing flow meter at FS-3 will be the identical meter that has been in use, and approved by your agencies for production allocation purposes, since start-up in 1977. An equivalent-quality meter will be used downstream of the shipping pumps at LPG. These meters do not have fixed-volume prover loops installed8; instead, they will continue to rely upon the master meter system for proving - the same method of meter proving that has always been utilized at these facilities. The daily sediment and water (%S&W) measurement from the Lisburne composite sampler (at the PS-1 connection) will be proportionally applied to both FS-3 and LPG gross oil volumes to determine dry oil volumes. This is analogous to the Prudhoe Bay IPA methodology for correcting for %S&W. With regard to the FS-1 early start-up scenario (via reverse flow in the GHX tie-line), FS-1 individual well oil volumes will be allocated together with the FS-3 and GG-3 well oil volumes and normalized against the FS-3 final allocated facility volume. This is consistent with the current methodology for accounting for oil flow from FS-3 to FS-1 (in the normal direction) using the GHX tie-line. the NGL LACT meter at Skid 50 divided by the sum of the individual meter readings at FS-1, FS-2, FS-3, GC-1 and GC-2. 7 A new daily LPC/FS-3 facility meter allocation factor will be established, similar to the GC/FS facility meter allocation methodology. It is a ratio equal to the PS-1 LACT meter (Lisburne connection at PS-1 ) divided by the sum of the individual meter readings at LPC and FS-3. 8 A fixed volume prover loop is the hallmark piece of equipment that makes a custody transfer turbine meter meet the standards established for a Lease Automatic Custody Transfer (LACT) meter system. Page 4 bp e e BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Attached are excerpts from the Presentation that you were shown on August 29th outline the specific mathematical calculations we intend to utilize until such time that the EOA ----O-il-Tra-n-sICti1reÎ~repaireciÎ replaceci~------- ~--~-------~------~-~--._----- We intend to resume production from the EOA as soon as safely possible, and as such, your expeditious approval is requested. Let me know if you need any more information to obtain approval for the changes requested. Respectfully, ~ n 1 /\ 1- V l~()- L ~¿m/vv Nancy C. Foust Projects and Engineering Manager BP Exploration (Alaska) Inc. cc: Robynn Wilson, Director, Department of Revenue, Tax Division Jane Williamson, Alaska Oil and Gas Conservation Commission Tom Maunder, Alaska Oil and Gas Conservation Commission Art Copoulos, Department of Natural Resources, Division of Oil and Gas Mike Hanus, Exxon Mobil Mike Erwin, ConocoPhillips Alaska, Inc Attachment 1 - Excerpts from August 29, 2006 Presentation Page 5 e bp ,,; e I ! i I ! I FS3 / GC3 Production Bypass Option to LPC Pipeline . GC3 Badami FS3 Rec. Option - FS1 to End. Line Endicott Line PSi New Connections Other Colors EXisting Lines .. LPC Pipeline Design Basis [·.~ê¡;¡g-""--JE,' "',~_ -~~~-----/- lJHr<:1soni( 16" LPC Pipeline Quality Bank __f-.u;:crl --......... To ALPS 1 Mete~ J Cornposlte SampJer UltrasonIc !VIetei .. m FS :3 Expand Opio 22 I/O Black leµfesenl::> EXlsung r-acihtles ~ 24" GHX TIe-LIne Early Production Optjon LPC Pipeline r--;:-~~ :!),-f-- ~~~ 16' Quality Bank Sampler 0-- -----. To ALPS Composite Samp!ef Gross (wet) Metered Oil: GPMA = OilpSJIJSB %S&W: GPMA = %SWpSJLlSß Net (dry) Metered Oil: GPMA = Oilps'LlSB * ( 1- %SWpSIUSB) - Ultrasonic Meter lPC 4-path Ultrasonic 16" LPC PlpeJine IPC Pig Quality Bank To ALPS Compos¡le Sampler Expand 01'10 22 110 ALPS Balance Factor (LISBAF) = [OilpSJlJSH ] / [OiILPc + Oil LPC gross (wet) allocated oil = LISBAF * OilLPc FS3 gross (wet) allocated oil = LISBAF * OilFs3 %S&W = %SWpSIUSB GPMA Net (dry) Metered Oil = LISBAF*OilLPc * ( 1- %SWpSIUSB) FS3 Net (dry) Metered Oil = LISBAF*OiIFs3 * ( 1- %SWpS]USB) - LPC Pipeline 4path Ultrasonic 16" LPC Pipeline Quality Bank To ALPS Cúmposite Sarnpler U!Lrdsonic Meter :[JI ~ele¡ ---05 3 Expônd Optu 22 1/0 24" GHX Tie-line Early Production Option Same as GPMA I FS3 option FS 1 oil included in FS3metered oil so will have the same facility oil factor and &W - · Do s not require new connection agreements · Does not requi Quality Bank Samplers. ak Detection will b expan d. Allocation metho same m thodology as cur U system. · ate tial early start optio for FS1 productio ugh FS3. GPB Oil Transit System Scr I I I I I I I I I I I I I I I S' I I I I I I I I I - J Lisburme Pipeline from Lisburne Original is located in CO 341 E FS-3 to Lisburne Jumper will remain in place — with spools at each end removed i——————————————— — — — — —- I OIL IN I Modify Metering to Match Typical 1 I I I I I o; o #68 n #69 I I I I I I I I I I— — — — — — — — — — — — — — — — — — — — :#;;t STATE OF ALASKA ADVERTISING ORDER INVOICE IT BE 1~~r~~T~ S!~I~~~~~~I~~~ER NO.tTIFIED AADO:OER2T3ISI1N40G ORD23ER NO. AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF A.O. Jod Colombie November 12 2002 PHONE PCN ¿ Anchorage Daily News POBox 149001 Anchorage,AK 99514 DATES ADVERTISEMENT REQUIRED: November 14,2002 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal o Display Account #STOF0330 Advertisement to be published was e-mailed o Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING DATE 2 ARD 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LlQ 03 02140100 73540 2 3 4 REQUlSITIONE 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: Lisburne Oil Pool and Prudhoe Bay Oil Pool, Prudhoe Bay Field Request to commingle Lisburne Well (K -317B) production with Prudhoe Bay Oil Pool Production By letter dated October 14, 2002, BP Exploration (Alaska) Inc. (BPXA) requested authorization to commingle production from a proposed well (K-317B) to be drilled and completed in the Lisburne Oil Pool with production from the Prudhoe Bay Oil Pool through Prudhoe Bay Oil Pool facilities. The Commission has tentatively set a public hearing on this application for December 17, 2002 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 November 29,2002. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order 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 this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on December 13, 2002 except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on December 17,2002. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before December 2, 2002. &~ ~t~·.~~~ Cammy ~echsli Taylor Chair Published Date: November 14,2002 ADN AO 02314023 Re: Advertising Order . Subject: Re: Advertising Order Date: 12 Nov 2002 13:11:16 -0900 From: Amy Heath <aheath@adn.com> To: Jody Colombie <jody_colombie@admin.state.ak.us> Account Number: STOF0330 Legal Ad Number: 637877 (Public Notice) Run Dates: November 14, 2002 Total Amount: $160.29 Thanks Jody! :) Have a great Tuesday. Amy L. Heath Legal Customer Service Representative Phone: ( 907) 257 - 4 2 96 Fax: (907) 279-8170 Office Hours 8:00am - 5:00pm legalads@adn.com lofl e 11/12/20024:48 PM tfnchOrage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 - PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 637877 11/14/2002 02314023 STOF0330 $160.29 $160.29 $0.00 $0.00 $0.00 $0.00 $0.00 $160.29 STATE OF ALASKA THIRD JUDICIAL DISTRICT Amy Heath, bei!l$ first duly sworn on oath deposes and says that sh: 1S an advertIsmg representative of the Anchorage Daily News, a dally 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 print.ed ~n an offi.ce maintained at the aforesaid place of publIcation of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed[kA ~/&~ Subscribed and sworn to me before this date: /jÍ~d. Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska - {;( 0t?~ \\\'ll(((((fff/: \.\\\ !»~\;\~~: bl'l''l ~~O., ...... "~~~ ~ :"~O..~~,,}:.~% .... . - ~:~Þu8L\C : ~ :::.~"'~ ...~:~:::: ., . . ~~ ~ '~Q: . .',a-:\- ~ '. ...._...v:\' /.1 &Dire&P;,,\ JIJ)))JJ)))\' I I ~ .j , Notice of Public . Hearing STA TÉ. Of'AL.ASKÄ Alaska Oil and Gas C;on$érvafionC;ommi~ion Re.: Lisburne Oil Pooton¡l Prudhoe Bay Oil Pool.,PrUdh()e Bay Flej¡l Request to commlng)e Lisburne Well (K-3I7B) proøuctlon wlthPru¡lhoe.Say Oil Pool Production ..... ..... .,' . BY letter d(lted October 14. 2002.BP Exploration (Alaska) Inc. (BPXA) requested authorization to commingle,pro¡luctionfrom. a propOsed well (K-317B) to be drilled an¡l comple~ in the Lisburne 011 Pool wlthp'j(uction from the Prudhoe Bay Oil poot throúghPrudhoe Bay Oil .PoalfacUitles. , .' , "'I.w,~?"",,"",.-_,,: ,>-",,--, The Commissiof> h(lstentatively Seta puf¡licheorinll'O!I"thl$~!lfIPf1 for December 17. 2002 at 9:00 amat the Alaska Oii and Gas Con~r:vatlon Commission 01333 West 7th Avenue. Suite 100, Anchorage, AI.aska 99501. A per, son may request that the.tenta'lvelY scheduled hearl!1gbehetd by fiii",,, a writ, ten request with the Commission no later than 4:30Pm on November 29. 2oQ2; If a request for a héarlng Is nonlmely filed, theComlT1lssion will Coi'l$!ðer the Issuance of an order without a hearing. To learn If the Commi$slon Will hord the public /learing, please call 793-1221 ; I n addition. c{Þerson may submit wrlttencomrnenf$ regarding this applÌcQtiQn to the Alaska Oil an.d GasConservQtlon Commission at 333 West 7th Avenue. Suite 100, Anc:horage, Alaska 99501. Written com.róentsmust~ re,c:eived no later than 4:30 pm on oecember 13. ~002except thClt~lfthé<;ommisslon cle<:14et to hold a public hearing, written comments must be received no late.r than 9:00 am 011 December 17.2002. I f yoU are a person with a dlsobilit." wh~ may, netic! a specipl m(¡dlflçp: tlon in Order to comment o.r to attend the pUblic hearing, PleaSlifc:ontac;t JQdY , Colombie at 793--1221 before December 2. 2002. '. Cammy Oech~1i Taylor. Chair Publish: Novemb~~J4; 2002 STATE OF ALASKA ADVERTISING ORDER e NOTICE TO PUBLISHER. ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., RTIFIED AO 02314023 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF . ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC 333 West 7th Avenue, Suite 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF A.O. R PHONE PCN ¿ Anchorage Daily News POBox 149001 Anchorage,AK 99514 November 14,2002 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account #STOF0330 AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2002, and thereafter for _ consecutive days, the last publication appearing on the _ day of . 2002, 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 2002, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER e e Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Lisburne Oil Pool and Prudhoe Bay Oil Pool, Prudhoe Bay Field Request to commingle Lisburne Well (K-317B) production with Prudhoe Bay Oil Pool Production By letter dated October 14,2002, BP Exploration (Alaska) Inc. (BPXA) requested authorization to commingle production from a proposed well (K-317B) to be drilled and completed in the Lisburne Oil Pool with production from the Prudhoe Bay Oil Pool through Prudhoe Bay Oil Pool facilities. The Commission has tentatively set a public hearing on this application for December 17, 2002 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 November 29,2002. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order 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 this application to the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on December 13, 2002 except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on December 17, 2002. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before December 2, 2002. &~ ~~.~~~ Cammy ~echsli Taylor Chair Published Date: November 14,2002 ADN AO 02314023 I œrtify that on II / 'f. ilZ _ a COPV of the above was faxed/mailed to eecff of the following a~their addresses of record: ¡:¡ ì~f., c 1/-a t ~t./ lß/3L~ LJC Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Mir Yousufuddin US Department of Energy Energy Information Administration 1999 Bryan Street, Ste 1110 Dallas, TX 75201-6801 Michael Nelson Purvin Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 T.E. Alford ExxonMobilExploration Company PO Box 4778 Houston, TX 77210-4778 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 e SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 Texico Exploration & Production PO Box 36366 Houston, TX 77236 W. Allen Huckabay Phillips Petroleum Company Exploration Department PO Box 1967 Houston, TX 77251 Shelia McNulty Financial Times PO Box 25089 Houston, TX 77265-5089 James White Intrepid Prod. Co.lAlaskan Crude 4614 Bohill SanAntonio, TX 78217 e John Katz State of Alaska Alaska Governor's Office 444 North Capitol St., NW, Ste 336 Washington, DC 20001 Alfred James 107 North Market Street, Ste 1000 Wichita, KS 67202-1822 Conoco Inc. PO Box 1267 Ponca City, OK 74602-1267 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 G. Scott Pfaff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 William Holton, Jr. Marathon Oil Company Law Department 5555 San Fecipe St. Houston, TX 77056-2799 Corry Woolington ChevronTexaco Land-Alaska PO Box 36366 Houston, TX 77236 Donna Williams World Oil Statistics Editor PO Box 2608 Houston, TX 77252 Shawn Sutherland Unocal Revenue Accounting 14141 Southwest Freeway SugarLand,TX 77478 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 John Levorsen 200 North 3rd Street, #1202 Boise,ID 83702 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Tim Ryherd State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Jim Arlington Forest Oil 310 K Street, Ste 700 Anchorage, AK 99501 Ed Jones Aurora Gas, LLC Vice President 1029 West 3rd Ave., Ste 220 Anchorage, AK 99501 Susan Hill State of Alaska, ADEC EH 555 Cordova Street Anchorage, AK 99501 John Harris NI Energy Development Tubular 3301 C Street, Ste 208 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Mark Hanley Anadarko 3201 C Street, Ste 603 Anchorage, AK 99503 e e Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Cammy Taylor 1333 West 11th Ave. Anchorage, AK 99501 Richard Mount State of Alaska Department of Revenue 500 West 7th Ave., Ste 500 Anchorage, AK 99501 Duane Vaagen Fairweather 715 L Street, Ste 7 Anchorage, AK 99501 Williams VanDyke State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Julie Houle State of Alaskan DNR Div of Oil & Gas, Resource Eva!. 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Robert Mintz State of Alaska Department of Law 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Trustees for Alaska 1026 West 4th Ave., Ste 201 Anchorage, AK 99501-1980 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Rob Crotty CIO CH2M HILL 301 West Nothern Lights Blvd Anchorage, AK 99503 Jack Laasch Natchiq Vice President Government Affairs 3900 C Street, Ste 701 Anchorage, AK 99503 Mark Dalton HDR Alaska 2525 C Street, Ste 305 Anchorage, AK 99503 Judy Brady Alaska Oil & Gas Associates 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503-2035 Arlen Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,lnc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 BP Exploration (Alaska), Inc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Bob Shavelson Cook Inlet Keeper PO Box 3269 Homer, AK 99603 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 e e Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jim Ruud Phillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw - MS 575 Anchorage, AK 99515 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Dudley Platt DA Platt & Associates 9852 Little Diomede Cr. Eagle River, AK 99577 Peter McKay 55441 Chinook Rd Kenai, AK 99611 Shannon Donnelly Phillips Alaska, Inc. HEST -Enviromental PO Box 66 Kenai, AK 99611 Penny Vadla Box 467 Ninilchik, AK 99639 Claire Caldes US Fish & Wildlife Service Kenai Refuge PO Box 2139 Soldotna, AK 99669 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Senator Loren Leman State Capitol Rm 113 Juneau,AK 99801-1182 e e John Tanigawa Evergreen Well Service Company PO Box 871845 Wasilla, AK 99687 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 SOldotna, AK 99669-2139 Cliff Burglin PO Box 131 Fairbanks, AK 99707 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 North Slope Borough PO Box 69 Barrow, AK 99723 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 Re: Notice of Public Hearing e e ..Subject: Re: Notice of Public Hearing Date: Tue, 12 Nov 200209:33:10 -0900 From: Jane Williamson <Jane_ Williamson@admin.state.ak.us> To: Cammy _ Taylor@admin.state.ak.us CC: Jody Colombie <jody_colombie@admin.state.ak.us> This looks fine. The upper Wahoo Formation is a part of the Lisburne Oil Pool. The proposed location is inside of the Lisburne Pool boundaries. Cammy_Taylor@admin.state.ak.us wrote: > Jody, here is the edited version of the public notice for > commingling of Lisburne production with Prudhoe production. > > It is ready to go as soon as Jane confirms that the Upper Lisburne > Wahoo is the same as the Lisburne Oil Pool. I think December 17th > is the earliest hearing date we can use. The delay is my fault - > Jane gave this to me last Friday - sorry. > > All three C's are out of the office on Tuesday after 10:30am and all > day Wednesday. But I can come back Tuesday night to sign if need > be. Thanks, Cammy > > > > > ------------------------------------------------------------------------ Name: 1 LisburneK317B .doc 1 LisburneK317B .doc Type: WINWORD File (application/msword) Encoding: base64 lof1 11112/20029:27 AM Re: Request to Commingle planned K-317B with PB. e Subject: Re: Request to Commingle planned K-317B with PBU Date: Sat, 09 Nov 2002 13:39:30 -0900 From: Cammy Oechsli Taylor <Cammy _ Taylor@admin.state.ak.us> Organization: DOA-AOGCC To: Jane Williamson <Jane_ Williamson@admin.state.ak.us> CC: Jack Hartz <jack_hartz@admin.state.ak.us>, Dan Seamount <dan_seamount@admin.state.ak.us>, Mike Bill <mike _ bill@admin.state.ak.us>, Jody Colombie <jody _ colombie@admin.state.ak.us> Jane, I apologize for not getting to this last week - I thought we could work on it today, but as I was preparing to give this to Jody I realized that I had a dumb question - is the Upper Lisburne Wahoo Formation of the LPA the same thing as the "Lisburne Oil Pool" as defined by the commission? Jane Williamson wrote: > > Cammy Oechsli Taylor wrote: > > > The e-mail came through without the attachment . . . > > > > Jane Williamson wrote: > > > > > > Cammy, > > > Attached is a draft for notice for hearing to allow for Commingling of > > > planned Lisburne Well K-317B with Prudhoe Bay (IPA) facilities. BP > > > needs approval from both DNR and AOGCC. I don't see a problem with > > > this, and approval would be only for this well. They want to drill the > > > well in early January. I don't believe we have a 401 on this yet > > > (though BP submitted and pulled one last year for this well). > > > > > > I don't see anything in the Lisburne Pool rules that allow us to do this > > > administratively. > > > > > > If this looks ok with you, please forward to Jody. > > > > > > PS. Jack if you see this as something we can do administratively please > > > let me know. > > > > > > Jane > > -------------------------------------------------------------------- > Name: LisburneK317B.notice.doc > LisburneK317B.notice.doc Type: WINWORD File (application/msword) > Encoding: base64 "··,·"····,,"'."'...·.·v,·,,,, "'''''''",'",wnm'mmmww Cammy Oechsli Taylor <cammy taylor(a)admin.state.ak.us> Commissioner Alaska Oil and Gas Conservation Commisison Department of Administration 11/11/20028:47 AM ~1 ©~&~~ (I &rJÆ©~ DIVISION OF OIL AND GAS NK H. MURKOWSKI, GOVERNOR · DEPARTMENT OF NATURAL RESOURCES 550 WEST 7TH A VENUE, SUITE 800 ANCHORAGE, ALASKA 99501-3560 PHONE: (907) 269-8800 FAX: (907) 269-8938 CERTIFIED MAIL RETURN RECEIPT REQUESTED RECEIVE FEB 0 4 2004 February 2, 2004 BP Exploration (Alaska) Inc. 900 East Benson Blvd. P.O. Box 196612 Anchorage, Alaska 99519-6612 Alaska Oil & Gas COilS Anchorage Via Fax (564-5706) and Mail Attention: Dwight Warner Interim GPMA Resource Manager Subject: Prudhoe Bay Unit Request to Commingle Production from Lisburne Participating Area (Well L2-14A) with IP A Production at Flow Station No.1 · Dear Mr. Warner: Your January 29, 2004 letter requested approval to temporarily commingle production from the Lisburne Participating Area (LPA) Well L2-14A with production from the Initial Participating Areas (IPA) through surface facilities at Flow Station No.1 (FS-l). After telephone conversations with BPXA representatives regarding this request, the Division of Oil and Gas (Division) grants approval through February 29. 2004 to flow production from L2-14A to FS-l subject to the following terms and conditions: 1) The PBU Western Satellite Production Metering PIan (WSMP) is acceptable for determining and allocating production from the L2-14A Well through FS-l. BPXA shall provide the well test data from L2-14A to the Division with the monthly royalty reports. The well test data shall also be provided electronically to the Division. The well test data shall include all the valid well tests performed during a month, the daily allocated volume of oil, gas and water produced from the well during this commingling period. 2) BPXA shall notify the Division, in writing or bye-mail, of the date of first production from the well. · 3) The Division acknowledges that for purposes of the L2-14A commingling period only, the NGLs removed from the produced gas will be accounted for and reported as IP A fluids. Any residue gas from the well will be injected into the PBU (Permo-Triassic) Reservoir and treated as indigenous IP A gas. "Develop, Conserve, and Enhance Natural Resources for Present and Future Alaskans." . . · Mr. Dwight Warner L2-14A Commingling Request February 2, 2004 Page 2 Assuming that the conditions set forth in this letter are acceptable to the working interest owners, you are authorized to proceed with the commingling ofL2-14A production with IPA production at FS-1. A person affected by this decision may appeal it, in accordance with 11 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040(c) and (d) and may be mailed or delivered to Tom Irwin, Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1-907-269- 8918, or sent by electronic mail to dncappeals@dnr.state.ak.us. This decision takes effect immediately. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of N atural Resources. · 4nc~r~~, . VI.. ... Lættßt--·~ I .:iv/r- /J ,,'It t ,M~k D. Myers - Director cc: AOGCC Chair Gary Benson, BPXA Gary Gustafson, BPXA PBU_LP A_L2-14Acommingle.doc · . . . bp . . o BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 January 29, 2004 Mark Myers, Director Division of Oil and Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, AK 99501 Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Request to Temporarily Commingle Production from Lisburne Participating Area with IPA Production (L2-14A Well) Dear Commissioner Seamount and Dr. Myers: BP Exploration (Alaska) Inc. (BPXA), as Operator of the Lisburne Participating Area (LP A) within the Prudhoe Bay Unit (PBU), requests authorization to temporarily commingle a portion of the production from the LP A with production from the Initial Participating Areas of the PBU through surface facilities at FS-l. . The coiled sidetrack of the L2-14A Well was originally planned to be completed in mid- February 2004 (Exhibit A). However, problems encountered while drilling necessitated that the well be brought on production without reaching the planned target to evaluate if the well will produce with the -580' MD of hole that was drilled. Currently, Lisburne production from L2 flows into the test header and through the separator and then on to the Lisburne Production Center (LPC). In order for this to occur for the L2-14A Well, a Graylock flange must first be secured that will allow production from the well to flow into the test header configuration and onto the LPC. Unfortunately, this valve is not scheduled to arrive on the slope before February 9th. Alternatively, BPXA has in place the necessary equipment to hook the L2-14A Well up to the production header going directly to FS-1. Operationally, we believe this to be a much better approach than using a much smaller hard line to temporarily connect the well to the test header until we receive the necessary equipment. When the well is flowing to FS-l it will produce from the wellhead through an S-riser into a 4" production line that enters module 4922 on the pad. Inside this module it can flow through the three phase meter for testing and then into the production line or directly into the production line going to FS-l. Accordingly, BPXA requests immediate approval through February 29, 2004 to temporarily flow production from the L2-14A Well to FS-l. This will allow time for the valve to arrive and be installed so the well can again flow back into the LPC. RECEIVED FEB 0 4 2004 Alaska OH & Gas Cons. Co:nrm~5¡Qn Anchorage . . . . . - 2- For royalty and tax purposes, production from the L2-14A Well will be reported as Lisburne production and included in the Greater Pt. McIntyre Well Allocation Report. Production from L2-14A Well will be determined and allocated in accordance with the PBU Western Satellite Production Metering PIan. We will use a three-phase meter for this purpose as soon as the well is on production. Any NGLs removed from the production of the L2-4A Well will be accounted for and reported as IP A fluids. Any gas produced will either be consumed in operations or injected into the Prudhoe Bay (Permo-Triassic) Reservoir and considered as indigenous IP A gas. The updated Lisburne POD will incorporate a description of operations associated with this wel1. Initially, testing will be done with a portable separator and by early next week the well could be produced to FS-l. Therefore, your immediate attention to this request would be greatly appreciated. BPXA staff are available should you have any questions or need any additional information. If you need any additional information, please contact Gary Gustafson at 564-5304 or myself at 5645359. Sincerely Yours, ;;}J~if) U~ Dwight Warner Interim GPMA Resource Manager Attachment: Exhibit A - Lisburne L2-14A Well Location cc: Commissioner Norman, AOGCC Jane Williamson, AOGCC Dan Dickinson, DOR Mike Kotowski, DO&G Jeff Farr, ExxonMobil Lamont Frazier, ConocoPhillips Bradley Brice, Forest Oil Gary Forsthoff, Chevron Gary Gustafson, BPXA Leslie Senden, BPXA Gary Benson, BPXA 2 -~- -~-- --- ---- -------------- - -----~~ -- ------- -- Lisburne L2-14A Well Location ib NOTE Existinq Lisburne wells selected from Finder by name only. Ifthere are other wells that have been converted to lisburne production, they are not shown. o 1 L~~__ I Map Projection: ASP 4 I 1 BPXA 2 miles I , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , _ __......J PBU Boundary Lisburne PA Lease Number Lease Acres Tract Number Scale: 1 :72,000 ------- - ----------------------- - -------- --- -----------~---------- --~- - bp e e o October 14, 2002 B P Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Mark Myers, Director Division of Oil and Gas Department of Natural Resources 550 West ih Avenue, Suite 800 Anchorage, AK 99501 Cammy Oechsli Taylor, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Request to Commingle Production from Lisburne Participating Area with IP A Production Dear Chair Taylor and Dr. Myers: BP Exploration (Alaska) Inc. (BPXA), as Operator of the Lisburne Participating Area (LP A) within the Prudhoe Bay Unit (PBU), requests authorization to commingle a portion of the production from the LP A with production from the Initial Participating Areas of the PBU through surface facilities at K-Pad and GC-l processing facilities. Current plans for the LPA are to drill the K-317B sidetrack well as depicted in Exhibit A. The K-317B well will be drilled from K-Pad and will target the Upper Lisburne Wahoo formation in a segment of the interval referred to as the Western Wahoo Extended Area (WWEA). Production from this region of the LP A will be comrningled with IP A fluids at the manifold building on K-Pad and delivered to the GC-l processing facility. According to our current schedule, the K-317B well should be ready to commence production by December 31,2002. For royalty and tax purposes, production from LPA K-Pad wells will be reported as Lisburne production and included in the Greater Pt. McIntyre Well Allocation Report. Production from LPA K-Pad wells will be determined and allocated in accordance with the PBU Western Satellite Production Metering Plan. Any NGLs removed from the production of the LPA K-Pad wells will be accounted for and reported as IP A fluids. Any gas produced will either be consumed in operations or injected into the Prudhoe Bay (Permo-Triassic) Reservoir and considered as . indigenous IP A gas. The updated Lisburne POD, due on or before April 2, 2003, will incorporate a description of operations associated with this wel1. BPXA staff are available should you have any questions or need any additional information. If you need any additional information, please contact Gary Gustafson at 564-5304. sincerepc~.....~J. ours, L"bp'~ Anne L. Shaw GPMA Resource Manager Y~k RD€eIVED OCT 16 2002 Alaska on& Gas Cons. Commission Anchorage e Attachment: Exhibit A - Map cc: Commissioner Bill, AOGCC Commissioner Seamount, AOGCC Dan Dickinson, DOR Mike Kotowski, DO&G Jeff Farr, ExxonMobil Lamont Frazer, ConocoPhillips Ken Griffin, Forest Oil Wade Fennel, ChevronTexaco Gary Gustafson, BPXA - 2- e " , - 3 - OOTE PBU BOIJ1'Irla¡y L\s!:I'I.lme f'A Lé!!I!ie l\h.Jmber Lø~ A~re!l TradNumoor 3