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Home My WebLink AboutCO 329 BIndex Conservation Order 317B Pt McIntyre and Pt McIntyre and Stump Island Oil Pool 1. November 8, 1999 Arco Alaska's Pt McIntyre Application to Amend AI04B 2. November 20, 1999 Notice of Hearing and Affidavit of Publication 3. December 1, 1999 Ltr from AOGCC to Arco re: application 4. January I, 2000 Meeting sign in sheet with Arco 5. January 12, 2000 Transcript of hearing, testimony, sign in sheet 6. March 9, 2000 Ltr from Arco answering questions from hearing 7. September 9, 2003 BP request to Commingle Production from Pt. McIntyre Participating Area with IPA Production 8. October 16, 2003 DOR response to BP's request 9. October 27, 2003 DNR response to BP's request 10. November 11, 2003 Revised BP request to Commingle Production from Pt. McIntyre Participating Area with IPA Production 11. January 27, 2004 DNR revised response to BP's request 12. May 23, 2007 Annual Surveillance Reporting Requirements (C031713- 002) 13. February 20, 2020 BPXA's request for Amin Approval for Conforming PBU Greater Pt. McIntyre Area Satellite Pool Rules for Consistency (CO 31713.003) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7�h Avenue, Suite 100 Anchorage, Alaska 99501 Re: APPLICATION OF BP ) Conservation Order 329B EXPLORATION (ALASKA) INC. to ) allow pilot commingling of the Niakuk ) Prudhoe Bay Field Oil Pool and Sag River Undefined Oil ) Niakuk Oil Pool Pool, Prudhoe Bay Field, North Slope, ) Sag River Formation - Undefined Oil Alaska ) Pool November 9, 2005 IT APPEARING THAT: 1. By letter and application dated September 1, 2005, BP Exploration (Alaska) Inc. (`BPXA") in its capacity as Niakuk Operator and Unit Operator of the Prudhoe Bay Unit ("PBU") requested the Alaska Oil and Gas Conservation Commission ("Commission") to issue an order in conformance with 20 AAC 25.215(b) allowing commingling of production from the Niakuk Oil Pool ("NOP") and Sag River Formation (undefined oil pool) ("SAG") within Well NK-43. 2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on September 15, 2005 concerning BPXA's application. 3. On October 17, 2005, BPXA submitted additional data and information supporting its application. 4. The Commission received no protests to BPXA's application or requests for public hearing. 5. The Commission has sufficient information to proceed with a ruling on the application and a hearing is not required. FINDINGS: 1. Request: BPXA proposes to initiate a 180-day pilot project to commingle production from the SAG and the Kuparuk River Formation of the NOP in NK-43 wellbore. The bottomhole location of the well is in Section 29, T12N-R16E, Umiat Meridian. The Kuparuk interval in the well is from 13,113 to 13,258 feet measured depth ("md") and the Sag interval is from 13,653 to 13,742 feet md. Conservation Order 329B is November 8, 2005 2. Commission Authority: 0 Page 2 Per 20 AAC 25.215 (b) "Commingling of production within the same wellbore from two or more pools is not permitted unless, after request, notice, and opportunity for public hearing in conformance with 20 AAC 25.540, the Commission (1) finds that waste will not occur, and that production from separate pools can be properly allocated; and (2) issues an order providing for commingling for wells completed from these pools within the field." 3. Objectives: The test will provide information that will be used in evaluation of further development of the Sag, including the feasibility of enhanced recovery projects. Production and geochemical data will be gathered to determine a reliable and acceptable production allocation methodology. 4. Well Performance: Well NK-43 produced within the Sag from March to April 2001. Total production was 35.8 MSTB and average rate was about 500 BOPD and 8.1 MSCFGPD. A mechanical plug was placed above the Sag and the well was perforated in the NOP in May 2001. The well currently produces approximately 206 BOPD, 656 BWPD, and 514 MSCFGPD. 5. Benefits: Additional longer term testing of the Sag is needed in this area of the reservoir for further evaluation of development options. A new well to the Sag would be a high - cost and high -risk option. A retest of the Sag in NK-43 requires commingling with the NOP, unless the current NOP perforations are shut-off. Abandonment of the NOP interval is not an acceptable option as this would result in a loss of existing developed reserves. Production logs will be used to monitor whether crossflow occurs downhole between the NOP and Sag. Dynamic crossflow is not anticipated to be a problem as flowing bottomhole pressure will be significantly below reservoir pressure for each pool. Static crossflow may occur but is expected to be minimal because reservoir pressures are relatively close to one another. Even if crossflow does occur, loss of reserves is not anticipated. Rather, the commingling will provide synergistic benefits, which could increase rate and reserves from both the Sag and NOP. The higher GOR production of the Sag can provide lift to the NOP production. Also, the hotter NOP production will help heat the Sag production, lowering potential for hydrates. Six months of pilot test production of the Sag without secondary recovery should not cause significant loss of reserves as the production will be small — roughly 40-90 MSTB and 560-1300 MMscf. The information gained from the pilot test will outweigh any reserves impact from lack of pressure support. Conservation Order 329B , November 8, 2005 6. Sag River Reservoir Properties, Hydrocarbon Volumes: The following summarizes reservoir properties of the Sag River. Porosity N:G Sw Boi Rsi Bgi Oil Gravity Condensate Gravity Condensate Yield Initial Reservoir Pressure Original Oil in Place Original Gas in Place 7. Allocation of Production: 20% 55% 40% 1.96 rb/stb 1600 scf/stb 0.62 rb/Mscf 32 API 49 API 65 bbl/MMSCF 3915 psi 6,426 MSTB (1,765 MSTB condensate) 34,200 MMSCF (27,200 MMSCF free gas) Page 3 The primary method for estimating NOP/Sag oil production splits will be geochemical analysis. In August 2005, BPXA contracted OilTracers LLC to test three different samples of NK-43 NOP and Sag oil mixtures for determining production splits. The geochemical fingerprints of the two oils are very different allowing identification of the source of the oil and determination of production splits. OilTracers LLC was not told the actual recombination ratios of the oils prior to their evaluation. The estimate of production ratios was highly accurate using the geochemical analysis (within +/- 1.5 to 2.5% error). BPXA proposes to perform geochemical sampling and analysis once per month. BPXA also proposes to run one production log early in the pilot testing to determine if significant dynamic and/or static crossflows occur downhole between the Sag and the NOP. Evaluation of the allocation technique is a major objective of this test, and the Commission must be assured of proper allocation. The use of chemical tracers for determination of production from separate pools commingled within a single wellbore has never before been applied for Alaska state production reporting purposes. However, the technique has been used for years for reservoir management and to estimate flow splits from different sand intervals within the Shrader Reservoir at Milne Point and the Kuparuk and Prudhoe Bay units. The Commission has previously approved production commingling in some Cook Inlet fields (e.g. McArthur River Field) using well tests and production logs to allocate production. The use of the geochemical fingerprinting technique in combination with production logs and well tests will allow for proper oil allocation so long as frequent Conservation Order 329B Page 4 November 8, 2005 production measurements are obtained. Accuracy of allocation is largely dependent upon the frequency of the production measurements. The Commission believes geochemical sampling, production logging and well testing should be conducted more frequently than proposed by BPXA to meet the objectives of the test and to satisfy the requirements of 20 AAC 25.215 (b)(1). An appropriate frequency for well testing is weekly during the first 2 months of production and at least twice per month thereafter. The well tests must be of sufficient duration and have sufficient stabilization periods to ensure representative tests. Oil samples should be collected and geochemical analysis should be performed on these samples at the time of each well test to ensure accurate allocation of oil production. In order to determine if crossflow is a problem and to allocate water and gas production, at least three production logs should be obtained over the six month test period. The working interest owners of the Prudhoe Bay Unit have integrated their interests through unitization. The royalty owner is the State of Alaska and royalty rate is uniform for the pools. Hence, there are no correlative rights issues associated with the proposed production allocation. CONCLUSIONS: 1. The proposed commingling of Sag and NOP production will provide valuable information for future development decisions for the Sag. 2. Correlative rights will not be negatively impacted by the proposed 6-month pilot test. 3. The use of geochemical fingerprinting in combination with production logs and frequent well tests will allow for proper oil allocation so long as frequent production measurements are obtained as prescribed in this order. 4. No waste will occur as a result of this test. NOW, THEREFORE, IT IS ORDERED: Conservation Order 329A is temporarily amended as follows: 1. Within the NK-43 wellbore, production from the Niakuk Oil Pool may be commingled with the Sag River Undefined Oil Pool 2. Lisburne Production Center allocation factors for oil, gas, and water must be used to allocate production to NK-43 in accordance with Rule 6 of CO 329. 3. During the first 2 months of production, well tests must be conducted weekly. During the remaining test period well tests must be conducted at least two times per month. The well tests must be of sufficient duration and have sufficient stabilization periods to ensure representative tests. 4. NK-43 well test production will be allocated between the Sag River Undefined Oil Pool and the Niakuk Oil Pool using the following information: a. During every well test, an oil sample must be taken from NK-43. Geochemical analysis must be performed on these samples to determine oil production splits Conservation Order 329B i November 8, 2005 . Page 5 of Sag River Undefined Oil Pool and Niakuk Oil Pool production. b. A minimum of three production logs must be run in NK-43 and evaluated over the six month interval of the pilot test to determine splits of Sag River and Niakuk Oil Pool water and gas production. 5. Bottomhole shut-in reservoir pressure must be measured at the beginning and end of the pilot testing period. 6. The operator shall submit a monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. Volumes reported on Form 10-405 in accordance with 20 AAC 25.230 (b) must break out Sag River Undefined Oil Pool and Niakuk Oil Pool allocated production within NK-43. 7. Within two months of the end of the pilot test period, the Operator shall provide a written report of the results of the test to the Commission. 8. Unless notice and public hearing are 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 freshwater. 9. This Order shall expire on July 1, 2006. DONE at Ancfiolraze. Alaska and dated November 9, 2005. Jrelfin�. Norman Daniel T. Seamount, Jr Chairman Commissioner Cathy P. Foerster Commissioner AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 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 fer4weal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after UaiM_Dbation for rehearing was filed). CO 329B PBU Niakuk Subject: CO 329B PBU Niakuk From: Jody Colombie<j ody_colombie@admin. state. ak.us> Date: Thu, 10 Nov 2005 16:30:53 -0900 To: undisclosed -recipients:; BCC: "bren >> Cynthia B Mciver" <bren mciver@admin.state. ak'.us>, Robert E Mintz <robert_mintz@law. state.ak.us> Christine Hansen <c.hansen@iogcc. state. ok.us>, Terrie'Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj.@unocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, trmjrl, <trmjrl @aol.com>, jbriddle <jbriddle@marathonoil.com>, shaneg <shaneg@evergreengas.com>, jdarlington <j darlington@forestoil. com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>,Mark Dalton`' <mark.dalton@hdrinc.com>, Shannon Donnelly<shannon.donnelly@conocophillips.com>, "Mark P. Worcester <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dec.state. ak.us>, tjr <tjr@dec.state. ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <P1attJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.£fullmer@conocophillips.com>, bocastwf <bocastwf@bp.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesno l @gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>,'rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa'' <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <j ah@dnr. state. ak.us>, Kurt E Olson <kurt_olson@legis.state. ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark hanley@anadarko.com>, loren leman <loren_leman@gov.state.ak.us>, Julie Houle <julie_houle@dnrstate.ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan_hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dec.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, 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@der.state. ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Bill Miller <BiIT_Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks<kristin_dirks@dec.state. ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe. gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>, jack newell <jack.neweil@acsalaska.net>, James Scherr <james_scherr@yahoo.com>, david roby <David.Roby@mms.gov>, Tim Lawlor <Tim Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, Jerry Dethlefs <nl617@conocophillips.com>, 1 of 2 11/10/2005 4:31 PM CO 329B PBU Niakuk 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>, Harry Lampert <harry.lampert@honeywell.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>,Jeff <smetankaj@unocal.com>, Todd Kratz <ToddKratz@chevron.com>, Gary Rogers <gary_rogers@revenue. state.ak.us>, Arthur Copoulos <Arthur_Copoulos@dnr.state.ak.us>, Phillip Ayer <pmayers@unocal.com>, Ken <ken@secorp-inc.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com> Content -Type: appiication/pdf �C0329B.pdf Content -Encoding: base64 2 of 2 11/10/2005 4:31 PM Citgo Petroleum Corporation Mary Jones David McCaleb PO Box 3758 XTO Energy, Inc. IHS Energy Group Tulsa, OK 74136 Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft, Worth, TX 76102-6298 Houston, TX 77056 Mona Dickens Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 408 18th Street President Boise, ID 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman Schlumberger Baker Oil Tools Halliburton Drilling and Measurements 4730 Business Park Blvd., #44 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Jill Schneider Land Department 9649 Musket Bell Cr.#5 US Geological Survey PO Box 93330 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 Williams Thomas North Slope Borough Arctic Slope Regional Corporation PO Box 69 Land Department Barrow, AK 99723 PO Box 129 Barrow, AK 99723 , • a r ME 0 ALASKA FRANK H. MURKOWSKI, GOVERNOR ALASKA OIL AND GAS 333 W. 7' AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. CO 329B.01 Mr. Mark Weggeland GPMA Subsurface Team Leader BP Exploration (Alaska) Inc. 900 East Benson Blvd. P.O. Box 196612 Anchorage, AK 99519-6612 RE: Conservation Order 329B - BPXA Pilot Commingling of the Niakuk Oil Pool and Sag River Undefined Oil Pool, Prudhoe Bay Field, North Slope, Alaska Dear Mr. Weggeland, By letter dated June 27, 2006 and received on July 13, 2006, BP Exploration (Alaska) Inc. ("BPXA") requested that Conservation Order 329B ("CO 32913") be extended for a period of 6 months, expiring 1/l/2007. CO 329B authorized commingling of production from the Niakuk and Sag River Undefined Oil Pools within the NK-43 wellbore on a temporary basis until July 1, 2006. Delays of bringing this well on production due to well integrity issues and other problems have resulted in commingled production of only six weeks. Therefore, geochemical and production profile allocation methods temporarily approved by the Commission have not been fully tested. The Commission agrees that additional time is needed to allow for evaluation of these allocation methods. Continuation of the pilot will provide valuable information for future development decisions for the Sag and will not cause waste or negatively impact correlative righ ccordingly, the expiration date of CO 329B is extended to January 1, 2007. All of r re uirements of CO 329B shall remain in effect. Alaska and dated July 17, 2.Q,06. aniel T. Se6mount, Jr. Cath P. Foerster Commissioner Commissioner v 0 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by i. a Ithe Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on tlh0 f Mowing the date of the order, or next working day if a holiday or weekend, to be timely filed. The ommiss sh 1 grant or refuse the application in whole or in part within 10 days. The Commission can refuse an y n acting on it within the 10-day period. An affected person has 30 days from the date the Commission ,fia(e ppli ation or mails (or otherwise distributes) an order upon rehearing, both being the final order of the ' sio , to ppeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the 1 h vti ?A �m si 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied Ot er the a placation for rehearing was filed). i 0 Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Kay Munger Michael Parks 200 North 3rd Street, #1202 Munger Oil Information Service, Inc Marple's Business Newsletter Boise, ID 83702 PO Box 45738 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Seattle, WA 98119-3960 Mark Wedman Schlumberger Baker Oil Tools Halliburton Drilling and Measurements 4730 Business Park Blvd., #44 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Jill Schneider Land Department 9649 Musket Bell Cr.#5 US Geological Survey PO Box 93330 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. • PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough Williams Thomas PO Box 69 Arctic Slope Regional Corporation Barrow, AK 99723 Land Department PO Box 129 Barrow, AK 99723 A CO 329B.001 Subject: CO 32913.001 From: Jody Colombie <Jody_colombie@admin.state. ak.us> Date: Tue, 18 Jul 2006 09:08:08 -0800 To: undisclosed -recipients:; BCC: Robert Mintz <robert mintz@law. state.ak.us>, Christine Hansen <c.hansen@iogcc. state. ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjrl@aol.com>, shaneg <shaneg@evergreengas.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tj r@dnr. state. ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank. alford@exxonmobil. com>, Mark Kovac <yesno 1 @gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud"<james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <j ah@dnr. state. ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, loren_leman <loren_leman@gov.state. ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr. state. ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, 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>, nl617@conocophillips.com, Tim Lawlor <Tim Lawlor@ak.blm.gov>, m Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry. C.Dethlefs@conocophillips. com>, crockett@aoga.org, Taera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon. Goltz@conocophillips. com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Todd Kratz <ToddKratz@chevron.com>, Gary Rogers <gary_rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur_Copoulos@dnr.state. ak.us>, Ken <ken@secorp-inc.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews 1 of 2 7/18/2006 9:08 AM CO 329B.001 0 <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>, Marguerite 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 G Aubert <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 <jim_regg@admin.state.ak.us>, Catherine P Foerster <cathy_foerster@admin. state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Cynthia B Mciver <bren mciver@admin.state.ak.us> Jody Colombie <jody colombie ir,admin.state.ak.us> Special Staff Assistant 907-793-1221 Alaska Oil and Gas Conservation Commission Department of Administration C0329B.01.pdf Content -Type: application/pdf Content -Encoding: base64 2 of 2 7/18/2006 9:08 AM ""TTE OF ALASKA A SARAH PALIN, GOVERNOR ALASKA OIL AND GAS 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 CONSERVATION COMMISSION 7 PHONE (907) 279-1433 FAX (907) 276-75423 ADMINISTRATIVE APPROVAL NO. CO 3291B.02 Mr. Mark Weggeland GPMA Subsurface Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: Conservation Order 329B - BPXA Pilot Commingling of the Niakuk Oil Pool and Sag River Undefined Oil Pool, Prudhoe Bay Field, North Slope, Alaska Dear Mr. Weggeland, By letter dated November 20, 2006 BP Exploration (Alaska) Inc. ("BPXA") requested that term of Conservation Order 329B ("CO 329B") be extended to 6/1/2007. The original CO 329B authorized commingling of production from the Niakuk and Sag River Undefined Oil Pools within the NK-43 wellbore on a temporary basis until July 1, 2006. The Commission required specific surveillance and reporting prior to this date. With delays of bringing this well on production due to well integrity issues and other problems BP requested and received approval (329B.01 dated July 17, 2006) to extend the expiration date of the order to l/1/2007. Again, however, well integrity problems delayed resumption of the commingled test. Installation of a tubing patch has since resolved the problem as evidenced by a post patch MIT -IA. The well was returned to production on 10/11/2006. The Commission agrees that additional time is necessary to collect required geochemical and production profile data and to verify and report to the Commission the test results and recommendation for allocation of production. Continuation of the pilot will provide valuable information for future development decisions for the Sag and will not cause waste or negatively impact correlative rights. Accordingly, the expiration date of CO 329B is extended to June 1, 2007, All other requirements of CO 329B shall remain in effect. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for 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 uperi y Court unless rehearing has been requested. ch rage, Alaska and dated December 7, 2006. Jo N : Daniel T. Seamount, Jr. Cathy P Foerster hairma Commissioner Commissioner t � :s George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company is NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Kay Munger Michael Parks 200 North 3rd Street, #1202 Munger Oil Information Service, Inc Marple's Business Newsletter Boise, ID 83702 PO Box 45738 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Seattle, WA 98119-3960 Mark Wedman Schlumberger Baker Oil Tools Halliburton Drilling and Measurements 4730 Business Park Blvd., #44 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Ivan Gillian Jill Schneider Land Department 9649 Musket Bell Cr.#5 US Geological Survey PO Box 93330 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough Williams Thomas PO Box 69 Arctic Slope Regional Corporation Barrow, AK 99723 Land Department PO Box 129 Barrow, AK 99723 AI022C-02, AI03-10 PBU and C0329B-02 S ver Subject: AI022C-02, AI03-10 PBU and C0329B-02 Sag River From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Fri, 08 Dec 2006 09:52:23 -0900 To: undisclosed -recipients:; BCC: Cynthia B Mciver<bren_mciver@admin.state. ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjrl@aol.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <P1attJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer<barbara.£fullmer@conocophillips.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, , Julie Houle <julie_houle@dnr.state. ak.us>, John W Katz <jwkatz@sso.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, 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>, nl617@conocophillips.com, Tim Lawlor <Tim Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Gary Rogers <gary_rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur_ Copoulos@dnr.state.ak.us>, Ken <ken@secorp-inc.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews <Iris_Matthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough i of 2 12/8/2006 9:52 AN AIO22C-02, AIO3-10 PBU and CO329B-02 V iver <admin@aleutianseast.org>, Marguerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <Camille_Taylor@law.state.ak.us>, Winton G Aubert <winton_aubert@admin.state.ak.us>, Thomas E Maunder <torn maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoil.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg <jim_regg@admin.state.ak.us>, Catherine P Foerster <cathy_foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <Laura_silliphant@dnr.state.ak.us>, David Steingreaber<david.e.steingreaber@exxonmobil.com>, akpratts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paul_bloom@ml.com>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple_davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner <taggoner@nrginc.com>, Mike Stockinger <Mike.Stockinger@anadarko.com>, , Arthur C Saitmarsh <artsaltmarsh@admin.state.ak.us> Jody Colombie <jody colombie(&,,admin.state. ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration co329B-02.pdf Content -Type: application/pdf Content -Encoding: base64 aio22C-02.pdf Content -Type: application/pdf Content -Encoding: base64 aio3-10.pdf Content -Type: application/pdf Content -Encoding: base64 12/8/2006 9:52 AN DOTALASKA SARAH PALIN, GOVERNOR AILASSA OIL AND GaLS 333 W 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. CO 329B.003 Mr. Mark Weggeland GPMA Resource Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: Conservation Order 329B - BPXA Pilot Commingling of the Niakuk Oil Pool and Sag River Undefined (i.e., Raven) Oil Pool, Prudhoe Bay Field, North Slope, Alaska Dear Mr. Weggeland, By letter dated June 19, 2007, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on June 26, 2007, BP Exploration (Alaska) Inc. ("BPXA") requests that Conservation Order 329B ("CO 32913"), which authorized a downhole commingling pilot project for well NK-43, be amended to permanently authorize the downhole commingling of production from the Raven Oil Pool and the Niakuk Oil Pool in the NK-43 wellbore. 1 BPXA also requests that production be allocated to the pools based on geochemical analyses performed twice per annum. The Commission has reviewed the report BPXA submitted and the Commission's own records regarding the pilot project. Based on that report and those records, the Commission finds that the pilot project demonstrates that the downhole commingling production from the two pools in the NK-43 wellbore dramatically increases the production rates of the pools. Increasing the production rates should increase the ultimate recovery from these pools. Also, the pilot project demonstrates that the geochemical analysis method of production allocation provides acceptable results, as compared to conventional production profile surveys, and that there is little variation in the geochemical analyses over time. Therefore, allowing the downhole commingling to continue on a permanent basis and production to be allocated between the two pools based on the results of geochemical analyses conducted twice per annum is appropriate. Rule 8 of CO 329B gives the Commission authority to administratively waive or amend any rule in CO 329B so long as the change does not promote waste, does not jeopardize correlative rights, does not increase the risk of fluid movement into freshwater, and is based on sound engineering and geoscience principles. For the reasons explained above, among others, the pilot project has demonstrated that the downhole commingling of the 1 When CO 329E was issued on November 9, 2005, the Sag River Formation was not part of a defined pool where it was penetrated by well NK-43. On August 9, 2006, Conservation Order 570 established the Raven Oil Pool. The Raven Oil Pool includes what was previously referenced as the Sag River Undefined Oil Pool. In this administrative approval, the terms "Raven Oil Pool' and "Sag River Undefined Oil Pool" are used interchangeably. f C0329B.003 October 9, 2007 Page 2 of 2 based on sound engineering and geoscience principles. For the reasons explained above, among others, the pilot project has demonstrated that the downhole commingling of the Raven and Niakuk Oil Pools in well NK-43 complies with these conditions, and, therefore, administratively amending CO 329B to allow the commingling to continue on a permanent basis is appropriate. Now, therefore, it is ordered: CO 329B is amended as follows: 1. Rule 1 of CO 329B is retained. 2. Rule 2 of CO 329B is retained. 3. Rule 3 of CO 329B is repealed. 4. Rule 4 of CO 329B is renumbered Rule 3 and revised to read as follows: At least twice per annum and not less frequently than once every seven months: (a) samples will be collected from NK-43; and (b) NK-43 well production will be allocated between the Raven Oil Pool and the Niakuk Oil Pool based on a geochemical analysis. 5. Rule 5 of CO 329B is repealed. 6. Rule 6 of CO 329B is renumbered Rule 4. 7. Rule 7 of CO 329B is repealed. 8. Rule 8 of CO 329B is renumbered Rule 5. 9. Rule 9 of CO 329B is repealed. 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 23`d day falls on a state holiday or weekend. This decision may not be appealed to the Superior Court unless the Commission has received a timely, properly filed application for reconsideration. ka, and dated October 9, 2007. Daniel T. Seamount, Jr. Commissioner t Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 David McCaleb Mona Dickens IHS Energy Group Tesoro Refining and Marketing Co. GEPS Supply & Distribution 5333 Westheimer, Ste 100 300 Concord Plaza Drive Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman —200 NeFtth 3rdStreet#1202 Boise, ID 83702 MaFPle's_Q"sin 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr, Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 rag 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 329E-003 PBU Attachments: CO 574-004 and CO 362A-005.pdf; CO 329B-003.pdf 10/ 10/2007 THE STATE 'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 505B.001 CONSERVATION ORDER NO.457B.005 CONSERVATION ORDER NO.341F.001 CONSERVATION ORDER NO.471.008 CONSERVATION ORDER NO. 452.003 CONSERVATION ORDER NO.484A.003 CONSERVATION ORDER NO. 559.011 CONSERVATION ORDER NO.570.009 CONSERVATION ORDER NO.329B.004 Ms. Diane Richmond Performance and Data Management Lead, Alaska Reservoir Development BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO-15-013 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Request for administrative approval to waive the monthly production allocation reporting requirement for the Schrader Bluff Oil Pool, Aurora Oil Pool, Prudhoe Oil Pool, Borealis Oil Pool, Midnight Sun Oil Pool, Polaris Oil Pool, Put River Oil Pool, Raven Oil Pool, and PBU Well NK-43 which is completed in the Niakuk and Raven Oil Pools in the Prudhoe Bay Unit. Dear Ms. Richmond: By letter dated November 2, 2015, and email date December 16, 2015, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to waive the requirement for monthly reporting of daily allocation and test data contained in the following rules: - Rule 4(f) of Conservation Order No. (CO) 50513; - Rule 4(e) of CO 45713; - Rule 18(d) of CO 341F; - Rule 4(g) of CO 471; - Rule 7(d) of CO 452; CO 505B.001, CO 457B.005, CO 341F.001, CO 471.008, CO 452.003, CO 484A.003, CO 559.011, CO 570.009, CO 329B.004 January 7, 2016 Page 2 of 3 - Rule 4(d) of CO 484A'; - Rule 4(f) of CO 559; - Rule 6(d) of CO 570; and - The first sentence of Rule 4 of CO 32913.003 In accordance with Rule 13 of CO 50513, Rule 10 of CO 45713, Rule 21 of CO 341 F, Rule 10 of CO 471, Rule 13 of CO 452, Rule 13 of CO 484A, Rule 11 of CO 559, Rule 14 of CO 570, and Rule 5 of CO 32913.003, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to waive the requirement to submit monthly reports of daily allocation and test data. BPXA requested to waive only the first sentence of Rule 4 CO 32913.003, which states: The operator shall submit a monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. BPXA requested to waive the following rules in their entirety. Rule 4(d) of CO 484A states: The Operator must submit a monthly report (in printed and electronic form) including well tests, daily -allocated production and allocation factors for the Pool. Rule 18(d) of CO 341 F states: In addition to the other requirements of Rule 4 of CO 45713, the monthly reports required by Rule 4(e) of CO 457B must identify the Well S-26 production allocated to the Aurora Oil Pool and Prudhoe Oil Pool. Rule 4(f) of CO 50513, Rule 4(e) of CO 45713, Rule 4(g) of CO 471, Rule 7(d) of CO 452, Rule 40) of CO 559, and Rule 6(d) of CO 570 states: The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Each of the affected pools is required to submit an annual reservoir surveillance report, providing a summary report on the production allocation and well test data in this annual report and retaining the ability to review the daily data if necessary allows the AOGCC to verify the performance of the well testing and allocation system without the need for monthly reports on the same data. ' BPXA's application requested to amend CO 484, however CO 484 was replaced by CO 484A on November 30, 2005. Therefore, the AOGCC is treating BPXA's application as an application to amend CO 484A. CO 505B.001, CO 457B.005, CO 341F.001, CO 471.008, CO 452.003, CO 484A.003, CO 559.011, CO 570.009, CO 329B.004 January 7, 2016 Page 3 of 3 Now therefore it is ordered that: Part (d) of Rule 18 of CO 341F, part(d) of Rule 7 of CO 452, part (e) of Rule 4 of CO 45713, part (g) of Rule 4 of CO 471, part (d) of Rule 4 of CO 484A, Part (f) of Rule 4 of CO 505B, part (f) of Rule 4 of CO 559, and part (d) of Rule 6 of CO 570are revised as follows: The operator shall submit a review of pool production allocation factors and 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. Rule 4 of CO 32913.003 is revised as follows: The operator shall submit a review of pool production allocation factors and 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. Volumes reported on Form 10-405 in accordance with 20 AAC 25.230 (b) must break out Sag River Undefined Oil Pool and Niakuk Oil Pool allocated production within NK-43. DONE at Anchorage, Alaska and dated January 7, 2016. S�, OIL 1Wo Cathy . Foerster Daniel T. Seamfount, Jr. 0 Chair, Commissioner Commissioner `�. RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Ms. Diane Richmond Richard Wagner Darwin Waldsmith Performance and Data Management Lead, Alaska Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99519-6612 � S qvv'c C'V 4y) 2-G CIAI�Clz*� Angela K. Singh Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, January 08, 2016 12:51 PM To: Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov); Bender, Makana K (DOA) (makana.bender@alaska.gov); Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA) oody.colombie@alaska.gov); Cook, Guy D (DOA); Crisp, John H (DOA) oohn.crisp@alaska.gov); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); Frystacky, Michal (michal.frystacky@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA) (Jeff Jones@alaska.gov); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored) ooseph.mumm@alaska.gov); Noble, Robert C (DOA) (bob.noble@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Regg, James B (DOA) oim.regg@alaska.gov); Roby, David S (DOA) (dave.roby@alaska.gov); Scheve, Charles M (DOA) (chuck.scheve@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov); Seamount, Dan T (DOA) (dan.seamount@alaska.gov); Singh, Angela K (DOA) (angela.singh@alaska.gov); Wallace, Chris D (DOA) (chris.wallace@alaska.gov); AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; Becky Bohrer; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jennifer Williams; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; John Easton; Jon Goltz; Juanita Lovett; Judy Stanek; Julie Houle; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laney Vazquez; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer (meg.kremer@alaska.gov); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; Mike Mason; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Steve Moothart (steve.moothart@alaska.gov); Suzanne Gibson; Tamera Sheffield; Tania Ramos; Ted Kramer; Temple Davidson; Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr, Graham Smith; Greg Mattson; Hak Dickenson; Heusser, Heather A (DNR); Holly To: Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen 1 (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Marie Steele; Matt Armstrong; Mike Franger; Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Susan Pollard; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: CO 505B.001, CO 457B.005, CO 341F.001, CO 471.008, CO 452.003, CO 484A.003, CO 559.011, CO 570.009, CO 329B.004 (PBU) Attachments: co505b-001.pdf, co457b-005.pdf, co341f-001.pdf; co471-008.pdf; co452-003.pdf, co484a-003.pdf, co559-011.pdf, co570-009.pdf, co329b-004.pdf Please see attached. Conservation Order 505B.001 Conservation Order 457B.005 Conservation Order 341F.001 Conservation Order 471.008 Conservation Order 452.003 Conservation Order 484A.003 Conservation Order 559.011 Conservation Order 570.009 Conservation Order 329B.004 Thank you, Samantha Carlisle CONFIDENTIALITY NOTICE. This e-ina.il message, including any attachments, contains information from the Alaska Oil and Gas Conservation Conunission (AOGCC), State of Alaska and is for the sole use of the untended recipient(s). It inay contain confidential and/or privileged information. The unauthorized. review, use or disclosure of such information may violate: state or federal law. if you are: an unintended recipient of this e-mad, please delete: it, without first saving or foilvarding it, and, so that the AOGCC is aware of the mistake in sending, it to you, contact SainiunUia Carlisle at (907) 7 93-1223 or Samantha.Carlisle@alaska.<*ov. Tlir STATE. °ALASKA GOVERNOR MICHAEL I. DUNLEAVY 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 Ms. Katrina Garner PBU Area Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -20-003 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.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 311 B 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, 31 1B.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, 311 B.003, 317B.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 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 Lisburne 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 8,900 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, 31713.003, 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 Soacina 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 Comminelina 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 Monitorine 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 151h 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 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 COs 20713.001, 31113.003, 317B.003, 32913.005, 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 Commineline 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 ("GC I"), 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 (GC 1 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 207D.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 GC1 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 15`h 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, 32913.005, 345.002,362A.006,570.010 April 3, 2020 Page 8 of 12 Niakuk Oil Pool — Conservation Order No. 329B 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 6 Surface Commingling 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. 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) 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 Monitoring 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 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. COs 207D.001, 31 1B.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 15`h 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 ComminElin¢ 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. I . 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, 31113.003, 31713.003, 32913.005, 345.002, 362A.006,570.010 April 3, 2020 Page 10 of 12 d. At a 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 Monitorine 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 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 North Prudhoe Bay 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 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 207D.001, 31 1B.003,317B.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 11 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 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 6: Common Production Facilities and Surface Comminelina 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, 317B.003, 329B.005, 345.002,362A.006, 570.010 April 3, 2020 Page 12 of 12 Rule 7: Reservoir Pressure Monitoring 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, 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 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 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. DONE at Anchorage, Alaska and dated April 3, 2020. Jeremy M. °",,,,"",,,=w Price Jeremy M. Price Chair, Commissioner Daniel T. oau.rrsu�.awwMnr. Seamount, Jr. mi�mioa`nvumwaroa Daniel T. Seamount, Jr. Commissioner AND APPEAL Jessie L. Chmielowski 13:ss:`si`o"eoo� Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 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 B? Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561 -511 1 February 20, 2020 Via USPS and Electronic Delivery Jeremy Price Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7`s Avenue, Suite 100 Anchorage, AK 99501 0 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, 1Ob,d, IOg, IOh, IOi, l Oj, 12a -f, 16b; CO 329A Rules 3, 6b,d, f -j, 8a -f, e; CO 311B 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; , I 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 21 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 There shall be no restrictions as to well spacing except that no fThe 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. 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.] �S =1129M. . t 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 drillsite 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. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 15`h 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 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 Rule 4 Well Soacine 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 Commineline 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 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. e. The operator shall submit a review of pool production allocation factors and 0 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. [1 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. 10h) 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 forth 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 5 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 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 [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 F producing well yearly. j.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 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 obtained annually. The surveys in part'a' of this 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 10412, 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. f Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part'e' 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 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. 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 Spacin¢ There shall be no restrictions as to well spacing except that no nay 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 Commin lin¢ [(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. [(t) 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 1*1 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 he suhmitted to rhe AnOC in rnninnrtinn 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 15 of that year. 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 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 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 gny 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 and well 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 APUMPMS 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 reserv0l r 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 avoroximate 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 pressuretime depths temperature and M 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 monitorintz 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 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. If you have any questions regarding this request, please contact Bill Bredar at 564-5348 or through email at William.bredar@bp.com. Si�nJcerreely, �j / �+e-C/.civ� .+ 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. 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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 14 by RECEIVED NOV 0 4 2015 AO` C 90 Exploration (Alaska) Inc. (4�- 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 November 2, 2015 Cathy Foerster Commission Chair Alaska Oil & Gas Conservation Commission 333 West 7 h Avenue, Suite 100 Anchorage, AK 99501 Re: Request for Administrative Waiver of Monthly Reporting of Daily Production Allocation Data Dear Chair Foerster, BP Exploration (Alaska) Inc., as the Operator of the Prudhoe Bay Unit, respectfully requests that the Commission administratively waive the requirement in the following Conservation Orders (CO) Pool Rules, for monthly reports and files containing daily production allocation data: Schrader Bluff Oil Pool - CO 505B Rule 4f Aurora Oil Pool - CO 457B Rule 4e Prudhoe Oil Pool — CO 341 F Rule 18d Borealis Oil Pool - CO 471 Rule 4g Midnight Sun Oil Pool - CO 452 Rule 7d Polaris Oil Pool - CO 484 Rule 4d Put River Oil Pool - CO 559 Rule 4f Raven Oil Pool - CO 570 Rule 6d Niakuk Oil Pool -43 — CO 32913.003 Rule 4b BP will continue to collect the daily production allocation data and will provide the data to the Commission at any time upon request. BP will also continue to submit required monthly production data to the Commission through the 10-405 forms. We simply seek relief from the cost and burden of preparing the reports on a monthly basis. We have attempted to include in this request all Prudhoe Bay Unit oil pool Conservation Orders that contain a requirement for monthly reporting of daily Request for AOGCC Administrative Waiver November 2, 2015 Page 2 allocation data. If the Commission is aware of additional Conservation Orders containing this requirement, BP respectfully requests the opportunity to add them to this request. Please direct any questions you may have to the undersigned or to Caroline Bajsarowicz at 907-564-4314, Caroline.Bajsarowicz@bp.com. Sincerely, /0.-, ate/ Diane Richmond Performance and Data Management Lead Alaska Reservoir Development, BPXA 564-4136 Carlisle, Samantha J (DOA) From: Roby, David S (DOA) Sent: Wednesday, December 30, 2015 2:53 PM To: Carlisle, Samantha J (DOA) Subject: FW: Monthly Reporting of Daily Production Allocation Data Sorry I forgot to forward this sooner. Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.aov. From: Richmond, Diane M [mailto:Diane.Richmond@bp.com] Sent: Wednesday, December 16, 2015 2:05 PM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Dave, Thanks for your note. Actually you are correct in that we want to waive the first part of Rule 4 which was Rule 6 in C0329B. BP as operator is asking for a waiver of the monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. However, we will continue to report volumes on Form 10-405. 6. The operator shall submit a monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. Volumes reported on Form 10-405 in accordance with 20 AAC 25.230 (b) must break out Sag River Undefined Oil Pool and Niakuk Oil Pool allocated production within NK-43. Let me know if you need additional information. Thanks Diane From: Roby, David S (DOA) [ma iIto: dave.roby alaska.gov] Sent: Tuesday, December 15, 2015 6:11 PM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline 3 Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane and/or Caroline, 1 I'm putting the finishing touches on the admin approval for this request and 1 have a question for you. In the request you asking us to waive Rule 4b in CO 32913.003. However the way I read this order there is no 4b. CO 32913.003 states that Rule 6 (which dealt with reporting results during the pilot test) of CO 329b is to be renumbered as Rule 4, but Rule 6 in CO 329B does not contain a part b. I just want to clarify what you actually want waived in this order. I presume it is the entirety of C03296.003 Rule 4. Please confirm this or let me know if it is just a portion of that rule that you want waive and if so which portion. Below are links to the orders. http://doa.alaska.gov/ogc/orders/co/co300 399/co329b-3.pdf http://doa.alaska.gov/ogc/orders/co/co300 399/co329b.pdf Regards, Dave Roby (907)793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.roby@alaska.aov. From: Richmond, Diane M [mailto:Diane. RichmondC&bp.com] Sent: Thursday, December 03, 2015 10:20 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Thanks Dave. We will go ahead and complete the report. From: Roby, David S (DOA) [mailto:dave.rob&alaska.gov] Sent: Thursday, December 03, 2015 10:15 AM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane, Working on your request was actually on my to do list for today. That said, we won't have a quorum of commissioners until the week of the 131h, so it's unlikely an official action will be taken until that time. While I don't expect there to be any issues with approving your request I cannot guarantee what the commissioners might say/decide, so to be safe you should probably go ahead and complete the report. Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.c From: Richmond, Diane M [mailto:Diane. Richmond@bp.com] Sent: Thursday, December 03, 2015 8:55 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: Monthly Reporting of Daily Production Allocation Data Dave, We are getting ready to prepare the Monthly State Satellites production report. Before completing this report, I wanted to understand the status of our Request for Administrative Waiver of Monthly Reporting of Daily Production Allocation Data sent to the AOGCC on Nov 2, 2015. Should we complete this report for the month of November to stay in compliance? Thanks for all of your help as we look to streamline, but also stay compliant with AOGCC orders. Diane Diane M. Richmond BP AK Reservoir Development Compliance SPA 907-564-4136 907-440-0835 (Cell) #13 Carlisle, Samantha J (DOA) From: Roby, David S (DOA) Sent: Monday, June 02, 2014 9:50 AM To: Carlisle, Samantha J (DOA) Subject: FW: request for temporary waiver of sampling/lab testing of NK-43's commingled production Sam, A copy of this email should be put in the C0329B order file. Thanks, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.roby@alaska.gov. From: Roby, David S (DOA) Sent: Monday, June 02, 2014 9:47 AM To: 'Boman, Wade' Cc: Eko, Apolianto; Lenig, David C; Gerik, Bob G Subject: RE: request for temporary waiver of sampling/lab testing of NK-43's commingled production Wade, Your request for a waiver of the sampling requirements of C0329B.003 is hereby approved. So long as NK-43 remains shut-in it does not need to be sampled for geochemical allocation purposes. When the well is returned to regular production (short-term production that may be necessary for diagnostic purposes does not count) the sampling shall resume. Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.gov. From: Boman, Wade [ma ilto: Wade. Boman (!J) bp. com] Sent: Monday, June 02, 2014 9:23 AM To: Roby, David S (DOA) Cc: Eko, Apolianto; Lenig, David C; Gerik, Bob G Subject: RE: request for temporary waiver of sampling/lab testing of NK-43's commingled production The plan is to keep the well shut-in 01, it can be repaired. Since the repair plant complete the amount of time the well will be down is, at this point, a bit open-ended. At the very least the waiver is needed for the sampling that would normally be getting done the first half of this year. The next sampling is scheduled to be done in November. Though I hope it will be, it's unclear at this time if the well will be back online by then. -Wade From: Roby, David S (DOA) [mailto:dave.roby0)alaska.g0v] Sent: Monday, June 02, 2014 9:15 AM To: Boman, Wade Cc: Eko, Apolianto; Lenig, David C; Gerik, Bob G Subject: RE: request for temporary waiver of sampling/lab testing of NK-43's commingled production Wade, One quick question. Is it your intent to leave the well shut-in until it can be repaired, or do you want to return it to service? Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use offhe intended recipient(s). it may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.roby@alaska.aov. From: Boman, Wade [maiIto: Wade. Boman @ Lip. com] Sent: Monday, June 02, 2014 9:12 AM To: Roby, David S (DOA) Cc: Eko, Apolianto; Lenig, David C; Gerik, Bob G Subject: request for temporary waiver of sampling/lab testing of NK-43's commingled production Dave, as per our phone conversation, it would be most desirable for us to get a temporary waiver for the required twice - yearly sampling and lab end member testing of the commingled production of NK-43. This well is completed across both the Kuparuk and Sag formations and has been under commingled production since January of 2006. This last January (2014) the well was shut-in due to high watercut. In the interest of a water shut-off, subsequent logging runs were recently performed, the results of which are being analyzed now. As the well is not currently producing, and a repair is not yet in the execution phase, a temporary waiver of the sampling requirement would be helpful from both a clerical and operational standpoint. The last commingled sample was taken this last November (2013), and the lab analysis showed 100% of the oil was from the Kuparuk, with 0% belonging to the Sag. If you require any additional information, please don't hesitate to call or email me. Thank -you. —Wade Boman Wade Boman Production Engineer Niakuk, L4 Northern Tier Base Management 678B wade, bornanLbp. corn Phone: 907-564-4674 Cell: 907-687-4468 #12 1] • OilTracers Report 08-749: Niakuk-43 Allocation (Confidential) September 30, 2008 Page 1 of 1 40 0 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Tuesday, September 30, 2008 12:21 PM To: McMains, Stephen E (DOA); Colombie, Jody J (DOA) Subject: FW: OilTracers Report 08-749: Niakuk-43 Allocation Attachments: 08-749 NK-43 Allocation Report.pdf See e-mail below. The attached is confidential, and should be filed with C0329B. From: Gerik, Bob G [mailto:Bob.Gerik@bp.com] Sent: Tuesday, September 30, 2008 8:51 AM To: Williamson, Mary J (DOA); Taylor, Cammy 0 (DNR) Cc: Frankenburg, Amy Subject: OilTracers Report 08-749: Niakuk-43 Allocation Jane, Cammy, I have taken over PE responsibilities for Niakuk and have attached a geochemical allocation report for NK-43 including both analysis of the most recent sample taken 8-04-08 along with other samples dating to December 2005. The most recent analysis indicates 86% of the flow from the Kuparuk and 14% of the flow from the Sag. The new percentage splits will be reflected in the September 2008 allocation reports. Let me know if you have any questions. thx Bob 9/30/2008 #11 Review of June 19, 2007, Downhole Commingling Application BP Exploration (Alaska), Inc. Well Prudhoe Bay Unit NK-43 Prudhoe Bay Unit, Niakuk and Sag River Undefined Oil Pools Conservation Order 329B (as amended) Requested Action: BP Exploration (Alaska), Inc. (BPXA) proposes to convert CO 32913, which granted temporary authorization for downhole commingling with allocation based on geochemical analysis, to a permanent order. Recommendation: I recommend approval of BPXA's application. Discussion: On November 9, 2005, the Commission issued CO 32913, which authorized a six month pilot downhole commingling test for the NK-43 well (PTD 201-001). The pilot project was to test the feasibility of using geochemical analysis to allocate production between two oil pools with very different crude oil properties. Due to well integrity issues the test was not able to be completed as originally anticipated and on July 17, 2006, and again on December 7, 2006, the Commission issued administrative approvals that extended the pilot project deadline. The test began in earnest in October 2006 and continued through May 2007. On June 19, 2007, BPXA submitted a report on the results of the pilot project, which concluded that the testing had demonstrated the viability of this method of allocation and requested that authorization be granted to continue the downhole commingling permanently. During the testing period BPXA gathered samples for geochemical analysis approximately every two weeks. A total of 24 samples were collected for geochemical analysis between December 2005 and April 2007. They are now requesting to gather samples for allocation purposes on a bi-yearly basis. During the pilot project period BPXA also ran production profile surveys on four occasions to evaluate the effectiveness of the geochemical analysis. Two of these production profile surveys were conduct on the date a sample was taken for geochemical analysis. One sample, collected on October 22, 2006, showed 94.9% of the oil should be allocated to the Niakuk Oil Pool (NOP). The production profile survey run on this day showed 98% of production coming from the NOP. A conventional well test was also conducted on the well on this date and showed total production at 527 bopd. Therefore, the actual difference in allocated oil volume is only 16 bbls. However, on the production report submitted for the month only 75% of production was allocated to the NOP. There were two other geochemical analyses performed for this month and they showed NOP oil allocation of 81.5% and 86.4 %. The other geochemical analysis that was performed on the same day as a production profile survey occurred on April 2, 2006. This sample showed that 82.5% of production should be allocated to the NOP, while the production profile survey showed 92% of production coming from the NOP. No conventional well test was conducted on this day, so the actual difference in barrels of oil can not be determined (an estimate would be approximately 50 bbls). During the pilot project period the geochemical analyses showed that the allocation of oil to the NOP ranged from 81.9 to 96.4%, and where typically around 86%. The difference between the typical value and the extreme values is only about 30 to 50 BOPD. Prior to commencing the downhole commingling of production the well produced the pools separately. The Sag River Undefined Oil Pool (SRUOP) was produced from March to June 2001 and produced a total of about 65 MBO. The NOP then produced from July 2001 to December 2005 and produced a total of about 365 MBO. The SRUOP exhibited a rapid decline in production rate during its limited period prior production, decreasing from 800 to 450 BOPD in less than 4 months. The NOP showed a steadier decline and was producing approximately 200 BOPD prior to the commencement of commingling. After downhole commingling commenced production from the SRUOP was low, about 50 to 60 BOPD, but the NOP production increased dramatically. The NOP produced in the 300 to 400 BOPD immediately after the commingling and has lately been producing in the 400 to 500 BOPD range. BP attributes the higher NOP production to an `artificial lift' effect from being commingled with the deeper SRUOP, which is gassier and higher pressured. Conclusion: It would be marginal to produce either the SRUOP or the NOP alone in the NK-43 well. However, the NOP has shown a dramatic improvement in production as a result of downhole commingling. Therefore, continuing to downhole commingle the production in well NK-43 should prolong the economic life of the well and increase the ultimate recovery in this area of the pools. The amount of difference in the production splits during the pilot project is relatively minor, no more than 50 BOPD. Therefore, frequent sampling is not necessary to ensure a reasonable allocation of production between the two pools. D.S. Roby Reservoir Engineer October 8, 2007 #10 by � •0 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 John Norman RECEIVED Alaska Oil and Gas Conservation Commission J U N 2 1 2007 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Alaska Oil & Gas Cons. Commissio" Anchorage RE: Conservation Order 329B — BP Pilot Commingling of the Niakuk Oil Pool and Sag River Undefined Oil Pool, Prudhoe Bay Field, North Slope, Alaska June 19, 2007 Dear Chairman Norman, As set forth in Alaska Oil and Gas Conservation Commission's Conservation Order 329B (as amended), BP Exploration (Alaska) Inc. has complied with the commingled production of the Niakuk Oil Pool (NOP) and the Sag River Undefined Oil Pool (Sag) within well NK-43 to determine a reliable and acceptable production allocation method. Over the course of the six month commingled test period (ending July 1, 2007) BP has fulfilled the Commission's requirements in obtaining Production Profiles, Static Bottom Hole Pressure Surveys, Geochemical Samples, and Well Tests. The results of the collected surveillance data are included in this letter. History of NK-43 Well NK-43 was drilled and completed in February 2001. Oil from the Sag was tested to be a 49' API condensate with 10-20% oil (based on geochemistry). A six week production test period of the Sag was performed. During the test period the Sag exhibited strong performance with an average oil rate of 650 bbls per day, at this time the Sag flowed without the assistance of gas lift. The Sag reservoir pressure at this time was 3,993 psi. During this test period the Sag produced 37,850 stbo, 487,000 scf, and 1,265 stbw. On 5/4/2001, a cast iron bridge plug (CIBP) was set to isolate the Sag from the NOP (Kuparuk formation). The Kuparuk oil was tested to be 24 ° API. Kuparuk only production took place from 5/6/2001 to 1 /2/2006. During the Kuparuk only period of production 393,500 stbo, 670,336 scf, and 1,068,000 stbw were produced. The CIBP separating the Kuparuk and Sag was milled out 1/9/2006 and commingled production began 1 /29/2006. The commingling of the Sag and the NOP during this test period has shown to have a positive impact on the oil production from NK-43. Prior to the Sag being produced with the NOP, the NOP production had declined to approximately 200 barrels of oil per day. During the commingled test period, the average oil rate for NK-43 has been 540 barrels per day. The increase in oil production can be attributed to the addition of the Sag production plus higher oil production from the NOP. The increase in NOP production is credited to an `artificial lift' benefit to the NOP production from the deeper, gassier Sag production. Results Obtained from Commingled Test During the course of the commingled testing period four production profiles using Schlumberger's DEFT and GHOST tool, 24 geochemical samples, 2 static bottom hole pressure surveys, and 43 well tests were gathered to assess the performance of the Sag and Kuparuk. A Summary of the production profile logging of the Sag and NOP is shown in Table 1. Based on production profile logging, approximately 10% of the oil is being produced from the Sag. Table 1 SaLY/Kuparuk PROF results. Oil Water Gas Y Y 4/2/2006 92% 66% 14% 10/22/2006 98% 78% 81 % 12/26/2006 88% 83% 60% 2/17/2007 91 % 86% 35% i CU 4/2/2006 8% 34% 86% 10/22/2006 2% 22% 19% 12/26/2006 12% 17% 40% 2/17/2007 9% 14% 65% Geochemical samples were collected at varying frequencies over the course of the commingled test period and the results are shown in Table 2. As with the production profile logging, geochemical analysis of the commingled oils indicates that approximately 10% of the production is coming from the Sag. 2 Table 2 SaR/NOP Lyeochemical testing results. NK-43 Geochemical Analysis Collection Date Sag River Contribution NOP Contribution 12/27/2005 4.5% 95.5% 12/29/2005 3.6% 96.4% 1 /24/2006 15.7% 84.3% 2/6/2006 9.8% 90.2% 2/17/2006 13.1 % 86.9% 3/3/2006 16.4% 83.6% 3/10/2006 16.4% 83.6% 4/2/2006 17.5% 82.5% 4/11 /2006 14.5% 85.5% 10/16/2006 18.5% 81.5% 10/22/2006 5.1 % 94.9% 10/29/2006 13.6% 86.4% 11 /5/2006 16.2% 83.8% 11 /12/2006 18.1 % 81.9% 11 /27/2006 7.0% 93.0% 12/10/2006 9.0% 91.0% 12/24/2006 5.8% 94.2% 1 /7/2007 7.4% 92.6% 1 /21 /2007 10.7% 89.3% 2/4/2007 10.1 % 89.9% 2/19/2007 11.4% 88.6% 3/10/2007 12.1 % 87.9% 4/9/2007 14.0% 86.0% 4/20/2007 14.0% 86.0% Average 11.6% 88.4% Table 3 illustrates the historic and commingled test period required static bottom hole pressure surveys. The individual reservoir pressure data indicates that the Sag has a higher reservoir pressure than the NOR When the two zones are commingled, the pressure at the NOP datum (9,200 SSTVD) is increased, due to pressure influence from the Sag. Table 3 Sag/NOP pressure historv. Date SSTVD Pressure Sagy ,f Ku aruk Kuparuk4dy1z,Ea/I A Ku y aruk � .�., Sa /Ku aruk x 5 �"��f , Well tests were conducted frequently throughout the commingled test period to quantify the total amount of fluids being produced from NK-43. Appendix A contains the results • • of individual well tests that were obtained over the commingled test period. Figure 1 contains the well test plot for the testing period. Based on the well tests during the commingled test period the average oil rate for this well was 540 bpd. 3000 2500 2000 0 1500 a v w 1000 500 0 —01 /06 Conclusions 4a°A v %Jao b Oft lc' 6 n10 o . o o .00 0 04/06 07/06 10/06 01 /07 04/07 Figure 1 Well test plot for commingled test period. During the commingled test period both geochemical fingerprinting and production profiles were used to allocate oil to their respective zones. Table 4 presents the allocation method and amount allocated to each zone during the commingled test period. In October, field picks from the production profile run on 10/22/06 were used for production allocation. In November and December, 2006, fully processed and interpreted 3-phase production profile logs were used to allocate oil production for each zone. During these first three months of the commingled test period, results from geochemical fingerprinting were not yet available for month end allocations. The January through May, 2007 month end allocations were based on results obtained from geochemical fingerprinting and confirmed by production logging profiles. Table 4 Monthly allocation methods Allocation Method and percentages. Sag NOP October Production Profile 25% 75% November Production Profile 2% 98% December Production Profile 2% 98% January Geochemical 12% 88% February Geochemical 12% 88% March Geochemical 12% 88% April Geochemical 12% 88% May Geochemical 12% 88% — fluid o water 0 oil 0 Figure 2 is an overlay plot of the results obtained from the geochemical sampling and the production profile logging of the NOP and Sag. The data clearly illustrates the agreement of the two sampling methods. Based on the close agreement between the two methods BP believes that geochemical sampling and analysis can be used to accurately allocate production between the NOP and the Sag. 100.0% 90.0% 80.0% 70.0% 60.0% 50.0% 40.0% 30.0% 20.0% 10.0% 0.0% 10/25/2005 NK-43 Testing Results X ■ ■ ■ X ' ■■ ■ '■ 2/2/2006 5/13/2006 8/21 /2006 11 /29/2006 3/9/2007 ♦Sag Geochem ■ NOP Geochem +Sag PPROF XNOP PPROF Figure 2 Geochemical fingerprinting and production profile results. -- 6/ 17/2007 Future Method of Allocation Upon completion of the six month commingled test period of the NOP and Sag, BP believes that geochemical analysis has been demonstrated to provide an accurate and appropriate method of allocating oil between the NOP and the Sag. Therefore, BP proposes that from July 1, 2007 forward, geochemical fingerprinting be utilized to allocate oil production between the NOP and Sag at a sampling frequency of twice per year. Collecting geochemical samples on a bi-yearly basis will ensure that subtle changes in production from the Sag and NOP will be seen and properly allocated to their respective zones. We hope that the Commission will agree with our analysis of the commingle test and grant permission to continue commingled production of well NK-43 and will allow production to be allocated between the NOP and Sag using geochemical analysis performed twice per annum. 5 • • If you have any questions, or wish to discuss this further, feel free to contact me. Sincerely, (, Mark Weggeland Greater Point McIntyre Area Resource Manager BP Exploration (Alaska), Inc. 900 East Benson Blvd. P.O. Box 196612 Anchorage, AK 99519-6612 Cc: Dave Roby, AOGCC Ellen Stevens, BPXA LT 00000000000000000000000000000000000000000000 00000000000000000000000000000000000000000000 0000000000000000000000000000000000000000000o 00oc�c�c�c�c�c�c�c�c�c�c�c�c�c�o0c�c�c�c�0000c�00c�c�c�c�c�c�c�c�c�c�c�c�c�0 N O W (o W O n N r Lo M n N M V N O N W O r (p r CO Cl) Lo CO r Lo n M M W (O N n n (O W n (O O W W O O n M 0 N O tO � V Lo N O N 't CD C) M N W N M O (o n N 0 0 0 M n O co (O O to V O O V n V N N N r r r 0 0 (!7 W (O n (O CO W M M n W N Lo r M M N N N M r Cl) V tO V N (O n M M M N N N N N N N N N r r r r r r r r r r r r r r r r r r r r O r N N N N N r r n 0 co co 00 LO MIcoI coI MI NI NI N� NI NI NI NI(`')� co co m NI NI NI NI NI OI OI NI NI NI NI NI NI NI NI NI NI NI NI NI NI'' NIr ILo t2I �2 �2 �R N N N N N (No N "No N N N 'No N N N N N 'No N N N N N M (O W W O M M r M� O M� 00 0 Lo 0 W r LO n W O m M N N M r N N W M 0 7 W n M r (O U) O W n W 0 (O Lo O W N W It M O r (p ct W W N M O N n W n M I O W M M n 0 W It -It Lo O N Ln n Lo W N V ItN M 'Cl- N N n n n (o r r N r W N N N N Lo M N r r O r r W n 0 O t,O O W n n n r N Cl) M -It -It -It It 'Cl-V V't V V V �t V' 't co M M M M M M MMM M M M N N N M M M M M m M V N O M to W O d' O m O N W W O n W O M V W W W M M M Lo O O V' M W O co (O co M M n W M N M O M O O V O O W N W coW N (O W N Lr)a) oMM V It NM(o O(O n LP)O Lo V ON T Cl) T T T r T T T T r r 0 0 0 0 O O O co n n 0� n W co W n f� co W N (o � Lo n Lo Lo C J T W W (!') 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Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 RECEIVED John Norman Alaska Oil and Gas Conservation Commission JUN 2 6 2007 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 >�laaka Oil &Gas Cons. Commission Anchorage RE: Conservation Order 329B — BP Pilot Commingling of the Niakuk Oil Pool and Sag River Undefined Oil Pool, Prudhoe Bay Field, North Slope, Alaska June 19, 2007 Dear Chairman Norman, As set forth in Alaska Oil and Gas Conservation Commission's Conservation Order 329B (as amended), BP Exploration (Alaska) Inc. has complied with the commingled production of the Niakuk Oil Pool (NOP) and the Sag River Undefined Oil Pool (Sag) within well NK-43 to determine a reliable and acceptable production allocation method. Over the course of the six month commingled test period (ending July 1, 2007) BP has fulfilled the Commission's requirements in obtaining Production Profiles, Static Bottom Hole Pressure Surveys, Geochemical Samples, and Well Tests. The results of the collected surveillance data are included in this letter. History of NK-43 Well NK-43 was drilled and completed in February 2001. Oil from the Sag was tested to be a 490 API condensate with 10-20% oil (based on geochemistry). A six week production test period of the Sag was performed. During the test period the Sag exhibited strong performance with an average oil rate of 650 bbls per day, at this time the Sag flowed without the assistance of gas lift. The Sag reservoir pressure at this time was 3,993 psi. During this test period the Sag produced 37,850 stbo, 487,000 scf, and 1,265 stbw. On 5/4/2001, a cast iron bridge plug (CIBP) was set to isolate the Sag from the NOP (Kuparuk formation). The Kuparuk oil was tested to be 24 ° API. Kuparuk only production took place from 5/6/2001 to 1/2/2006. During the Kuparuk only period of production 393,500 stbo, 670,336 scf, and 1,068,000 stbw were produced. The CIBP separating the Kuparuk and Sag was milled out 1/9/2006 and commingled production began 1/29/2006. The commingling of the Sag and the NOP during this test period has shown to have a positive impact on the oil production from NK-43. Prior to the Sag being produced with the NOP, the NOP production had declined to approximately 200 barrels of oil per day. During the commingled test period, the average oil rate for NK-43 has been 540 barrels 1 per day. The increase in oil production can be attributed to the addition of the Sag production plus higher oil production from the NOP. The increase in NOP production is credited to an `artificial lift' benefit to the NOP production from the deeper, gassier Sag production. Results Obtained from Commingled Test During the course of the commingled testing period four production profiles using Schlumberger's DEFT and GHOST tool, 24 geochemical samples, 2 static bottom hole pressure surveys, and 43 well tests were gathered to assess the performance of the Sag and Kuparuk. A Summary of the production profile logging of the Sag and NOP is shown in Table 1. Based on production profile logging, approximately 10% of the oil is being produced from the Sag. Table 1 Sa2/Kuparuk PROF results. Oil Water Gas Y Y 4/2/2006 92% 66% 14% 10/22/2006 98% 78% 81 % 12/26/2006 88% 83% 60% 2/17/2007 91 % 86% 35% Cz 4/2/2006 8% 34% 86% 10/22/2006 2% 22% 19% 12/26/2006 12% 17% 40% 2/17/2007 9% 14% 65% Geochemical samples were collected at varying frequencies over the course of the commingled test period and the results are shown in Table 2. As with the production profile logging, geochemical analysis of the commingled oils indicates that approximately 10% of the production is coming from the Sag. 2 Table 2 Sag/NOP Lyeochemical testing results. NK-43 Geochemical Analysis Collection Date Sag River Contribution NOP Contribution 12/27/2005 4.5% 95.5% 12/29/2005 3.6% 96.4% 1 /24/2006 15.7% 84.3% 2/6/2006 9.8% 90.2% 2/17/2006 13.1 % 86.9% 3/3/2006 16.4% 83.6% 3/10/2006 16.4% 83.6% 4/2/2006 17.5% 82.5% 4/11 /2006 14.5% 85.5% 10/16/2006 18.5% 81.5% 10/22/2006 5.1 % 94.9% 10/29/2006 13.6% 86.4% 11 /5/2006 16.2% 83.8% 11 /12/2006 18.1 % 81.9% 11 /27/2006 7.0% 93.0% 12/10/2006 9.0% 91.0% 12/24/2006 5.8% 94.2% 1 /7/2007 7.4% 92.6% 1 /21 /2007 10.7% 89.3% 2/4/2007 10.1 % 89.9% 2/19/2007 11.4% 88.6% 3/10/2007 12.1 % 87.9% 4/9/2007 14.0% 86.0% 4/20/2007 14.0% 86.0% Average 11.6% 88.4% Table 3 illustrates the historic and commingled test period required static bottom hole pressure surveys. The individual reservoir pressure data indicates that the Sag has a higher reservoir pressure than the NOR When the two zones are commingled, the pressure at the NOP datum (9,200 SSTVD) is increased, due to pressure influence from the Sag. Table 3 I I Date I SSTVD I Pressure I i a k k Well tests were conducted frequently throughout the commingled test period to quantify the total amount of fluids being produced from NK-43. Appendix A contains the results 3 • of individual well tests that were obtained over the commingled test period. Figure 1 contains the well test plot for the testing period. Based on the well tests during the commingled test period the average oil rate for this well was 540 bpd. 3000 104*10A® a 2000 a c 0 3 1500 0 c. v w 1000 500 0 —01 /06 Conclusions 04/06 07/06 10/06 01 /07 04/07 Figure 1 Well test plot for commingled test period. During the commingled test period both geochemical fingerprinting and production profiles were used to allocate oil to their respective zones. Table 4 presents the allocation method and amount allocated to each zone during the commingled test period. In October, field picks from the production profile run on 10/22/06 were used for production allocation. In November and December, 2006, fully processed and interpreted 3-phase production profile logs were used to allocate oil production for each zone. During these first three months of the commingled test period, results from geochemical fingerprinting were not yet available for month end allocations. The January through May, 2007 month end allocations were based on results obtained from geochemical fingerprinting and confirmed by production logging profiles. Table 4 Monthly allocation methods and percentages. Allocation Method Sag NOP October Production Profile 25% 75% November Production Profile 2% 98% December Production Profile 2% 98% January Geochemical 12% 88% February Geochemical 12% 88% March Geochemical 12% 88% April Geochemical 12% 88% May Geochemical 12% 88% I -m-fluid t water 0 oil 11 Figure 2 is an overlay plot of the results obtained from the geochemical sampling and the production profile logging of the NOP and Sag. The data clearly illustrates the agreement of the two sampling methods. Based on the close agreement between the two methods BP believes that geochemical sampling and analysis can be used to accurately allocate production between the NOP and the Sag. 100.0% 90.0% 80.0% 70.0% 60.0% 50.0% 40.0% 30.0% 20.0% 10.0% 0.0% NK-43 Testing Results r : ■ ■ --------X ■■X 40 ♦ �• 10/25/2005 2/2/2006 5/13/2006 8/21 /2006 11 /29/2006 3/9/2007 6/17/2007 ♦Sag Geochem ■ NOP Geochem +Sag PPROF XNOP PPROF Figure 2 Geochemical fingerprinting and production profile results. Future Method of Allocation Upon completion of the six month commingled test period of the NOP and Sag, BP believes that geochemical analysis has been demonstrated to provide an accurate and appropriate method of allocating oil between the NOP and the Sag. Therefore, BP proposes that from July 1, 2007 forward, geochemical fingerprinting be utilized to allocate oil production between the NOP and Sag at a sampling frequency of twice per year. Collecting geochemical samples on a bi-yearly basis will ensure that subtle changes in production from the Sag and NOP will be seen and properly allocated to their respective zones. We hope that the Commission will agree with our analysis of the commingle test and grant permission to continue commingled production of well NK-43 and will allow production to be allocated between the NOP and Sag using geochemical analysis performed twice per annum. 5 If you have any questions, or wish to discuss this further, feel free to contact me. Sincerely, ((,,` Z�� 6-t,4 Mark Weggeland Greater Point McIntyre Area Resource Manager BP Exploration (Alaska), Inc. 900 East Benson Blvd. P.O. Box 196612 Anchorage, AK 99519-6612 Cc: Dave Roby, AOGCC Ellen Stevens, BPXA I #s by 0 DEC 0 4 2006 BP Exploration (Alaska)Inc. 900 East Benson Boulevard Alaska Oil & Gas Cons. ComrnISSIUflP0. Box 196612 Anchorage Anchorage, Alaska 99519-6612 (907) 561-5111 John Norman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Conservation Order 329B — BP Pilot Commingling of the Niakuk Oil Pool and Sag River Undefined Oil Pool, Prudhoe Bay Field, North Slope, Alaska November 20, 2006 Dear Mr. Norman, In light of the Alaska Oil and gas Conservation Commission's Conservation Order 329B, BP Exploration (Alaska) Inc. has proceeded with the commingled production of the Niakuk Oil Pool and the Sag River Undefined Oil Pool within well NK-43. Commingled production from NK-43 began on 2/3/2006. The well produced for approximately one month and on 3/19/2006 the well was shut-in due to well ;integrity issues. Numerous diagnostic tests were conducted, indicating the production tubing to have a leak. As a result a second amendment to C0329B was issued which extends the test period to 1/1/2007. On 6/17/2006 a tubing patch was deployed and the well was briefly online from 6/29/2006 to 7/10/2006 before a post patch integrity test indicated the tubing patch was a failure. Further diagnostics were conducted resulting in the tubing patch being pulled and redeployed on 9/15/2006. The patch was deemed successful when a post patch MIT -IA passed, the well was then returned to production on 10/11/2006. BP has been active in collecting data and samples for comparing allocation methods. Oil samples were collected on 10115, 10/22, 10/29, 11/15, and 11/12 and have been sent to OilTacers, L.L.C. for geochemical analysis. The first of four scheduled production profiles was acquired on 10/22. Due to the initial delay bringing this well on production, resulting from well integrity issues, BP will not have adequate time to collect sufficient geochemical and production profile data to determine the best way to allocate production from this well before the second administrative amendment to C0329B expires on 1/1/2007. In order to satisfy the requirements set forth in Conservation Order 329B and to accurately determine an allocation method, BP requests that the conservation order be extend for a period of 6 months, expiring 6/l/2007. This will allow BP to obtain the necessary data required by C0329B to accurately determine the best method of allocation for this well and prepare a final report. • 9 If you have any questions feel free to contact me. Sincerely, W Mark Weggeland Greater Point McIntyre Area Resource Manager BP Exploration (Alaska), Inc. 900 E. Benson Blvd. P.O. Box 196612 Anchorage, AK 99519-6612 Cc: Jane Williamson, AOGCC #7 by 0 � John R. Denis Subsurface Team Leader BP Exploration (Alaska) Inc. Alaska Consolidated Team (ACT) 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Phone: (907) 564-5049 Fax: (907) 564-4441 July 18, 2006 Email denisjr@bp.com Web: www.bp.com Jane Williamson Y RECEIVED Senior Reservoir Engineer i JUL I S 2006 Robert P. Crandall Senior Petroleum Geologist Alaska Oil &Gas Cons. Commission Anchorage Alaska Oil and Gas Conservation Commission 333 W. 71" Ave #100 Anchorage, AK 99501-3539 RE: Classification of the Kuparuk and Sag River Formations at Northstar Well NS34 Dear Ms. Williamson and Mr. Crandall: Thank you for the opportunity to present to you on June 27 and July 6 information we have acquired as we seek Commission concurrence that the Kuparuk and Sag River stratigraphic horizons do not represent major liquid hydrocarbon accumulations at the NS34 well location. Further to the technical presentations, we are submitting a written description and figures to support the Commission's determination. Background On March 15 and May 16, 2002, BPXA submitted to the Commission a package of material for the classification of the Kuparuk and Sag River reservoirs for locations NS-SO4, 05, S06, 12, 16, S17, S18, S21, and 23. Since the 2002 submittal, 18 additional penetrations of the Kuparuk at Northstar have occurred. Today's submittal augments the previous one by providing additional data that is germane to the NS34 evaluation. The NS34 well is currently temporarily suspended at a measured depth of 3,962 feet in the Sagavanirktok Formation where surface casing was Jane WilliamsoO Robert Crandall Alaska Oil and Gas Conservation Commission July 18, 2006 Page 2 set. BP will resume drilling the NS34 well this fall and expects to penetrate the Kuparuk Formation in early -mid November and the Sag River Formation later that month. Discussion Due to its geological situation, the NS34 well is prognosed to encounter zero feet of hydrocarbons in the Kuparuk. The prognosed depth of the top Kuparuk C of -9102 TVDss is below any Kuparuk C hydrocarbon encountered in any of the field wells. The Sag River Formation is a very low permeability sandstone. Nothing has occurred to change the interpretation that formed the basis of the 2002 submission regarding the Sag River Sandstone. Figure 1 shows the updated top Kuparuk C structure map for the field. This map was built by depth converting the Lower Cretaceous Unconformity horizon (which occurs at the base of the C zones within the Kuparuk Formation) and adding the three isopachs C1, C2, C3 together then subtracting their sum from the LCU surface. The LCU depth map is shown in figure 2. The three C zone isopachs are included as Figures 3, 4, and 5. All maps utilize available well control. Each of the zonal isopachs has the footage of net sand and average zonal porosity (where porosity logs are available) posted in green and red, respectively. The top Kuparuk map over the field area shows an antiform that is elongated in a NW to SE direction. The antiform is cut by minor NW -SE trending faults. Figure 6 shows an expanded scale version of the top Kuparuk structure that is focused in the NS34 area. Fluid contact information is annotated for the key wells that are on the map. The map shows that NS 34 will penetrate the Kuparuk on the southeast flank of an independent closure to the main field at the feature's spillpoint. Figure 7 contains the Kuparuk C geological prognosis for NS34. The Kuparuk is prognosed to have 0' of hydrocarbon in the well due to its location. Gross sand thicknesses have been mapped and values at the well are back -interpolated from the maps. Net sand values, while posted at the wells, have not been mapped. The Kuparuk C fluid contact on the eastern flank of the Kuparuk antiform is interpreted to be -9035, which is the interpreted contact for the majority of the wells in the field (Figure 8 — RFT data). This depth is consistent with all • Jane Williamso* Robert Crandall Alaska Oil and Gas Conservation Commission July 18, 2006 Page 3 eastern flank wells including those most proximal to the NS34 location (Seal A-02-A, NS12, NS30, NS09). Four field wells, at distance from the NS34 location, indicate variation from the -9035 HC/W contact. In each of the four cases, the different contact is associated with faults. The 4 variances and locations include: -9011 HC/water contact in NS29, -9058 lowest known HC in NS20, -9075 HC/water contact in NS05PB1, and -9097 lowest known HC in NS07. Kuparuk C contact information is summarized on Figure 9. The top LCU is the stratigraphic top of Kuparuk A zone. Figure 10, a map of the top LCU in the NS34 area, shows the Kuparuk A penetration point is on the flank of the same structure that exists at top Kuparuk and is out of closure, at a prognosed depth of -9270. This is 201 feet below the lowest known hydrocarbon in the A sands. Additionally, the A sand is low permeability, averaging 10mD, which strongly limits its flow rate. Figure 11 shows that 18 additional penetrations of the Kuparuk have occurred since 2002 bringing the total in the immediate field area to 30. The Kuparuk has been drilled year round and there have been no well control incidents. To mitigate the drilling risks at Northstar we continue to employ a number of precautions including having mudloggers on location while drilling the Kuparuk interval, monitoring gas concentrations in the drilling mud, using sufficient mudweights to control reservoir fluids and utilizing standard North Slope drilling practices. Figure 12 represents a summary of the situation. BPXA requests Commission concurrence to ADEC that there is low risk of major liquid hydrocarbon zones in the Kuparuk or Sag River Formations at NS34. Please contact Bill Bredar at 564-5348 if you have additional questions or need further information. Thank you, John Denis Jane Williams60 Robert Crandall Alaska Oil and Gas Conservation Commission July 18, 2006 Page 4 BPXA requests this submission be held CONFIDENTIAL. List of Figures (all figures in PowerPoint on CD; additionally all maps provided at full scale): Top Kuparuk C structure map LCU depth map C1 Isopach with rock properties posted C2 Isopach with rock properties posted C3 Isopach with rock properties posted Top Kuparuk structure focused in the NS34 area with fluid contact information Geological prognosis for NS34 Kuparuk R FT data Summarized Structure and Fluid Contact Information Kuparuk Penetrations since 6/2002 Top LCU depth map Summary of Prognosis and Schedule Attachments: March 15, 2002 letter to Commission from BPXA geologist Ken Lemley (text only). Provided under separate cover: NS08 snap file NS08 test information: Summary of Flow Periods & Volumes, Schlumberger Report, and Well Test Solutions Transient Pressure Test Data Interpretation Report NS34 proposed directional 7-06-2006 March 15, 2002 John D. Hartz Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission Robert P. Crandall Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Re: Classification of the Kuparuk and Sag Reservoirs at Northstar Dear Mr. Hartz and Mr. Crandall, Thank you for the opportunity to present to you on March 12t°, 2002 the information we have acquired regarding the Kuparuk Formation at Northstar. As requested, attached are several exhibits, which were presented to you and serve to describe the geology, hydrocarbon occurrence and reservoir nature of the Kuparuk reservoir at Northstar. Below is also a brief discussion describing the most important elements of our presentation to you and our current interpretation. The information attached include the RFT results from the NS27, NS13, and NS08 wells (figs. 1,2,3), porosity and permeability data from whole core taken at Northstar (fig. 4), structure map at the top of the Kuparuk "C" (fig 6), two structural cross -sections with interpretations of fluid types (figs. 5,7) and the Northstar anticipated summer 2002 drilling expected results (fig. 8). The NS15 and NS07 wells should be drilled and completed prior to the June Is` summer drilling restriction period. These two wells will furnish us additional points of control near the NS16 and NS05 summer drilling wells thus increasing our ability to forecast hydrocarbon occurrences in the Kuparuk interval Repeat formation tests (RFT''s) were taken in the NS27, NS13 and NS08 wells in the Kuparuk formation. The results from these tests are shown in figure 1. As can be seen, all three wells confirm a 0.11 psi/ft gas gradient down to a depth of 9035' TVDss. This is the lowest known gas (LKG) level. The separation in reservoir pressure between wells is presumed to be due to gauge drift. Figure 2 represents RFT pressures that have been gauge drift corrected. Below 9035' TVDss we observe both an oil gradient and a water gradient. The NS27 and NS08 wells both confirm a water gradient of 0.45 psi/ft. These pressure points were taken in the Kuparuk "Al and lower AT' horizons. This gradient also intersects at 9035' TVDss, coincident with the lowest known gas previously discussed. Also observed in figure 2 is an oil gradient of 0.31 psi/ft corresponding to a 38 degree API oil with a GOR of 400 scf/bo. A 38 degree API ail sample was acquired in the 'NS27. It should be noted that this sample took a very long time to acquire due to the lack of permeability in the Kuparuk "A" interval. The intersection of the oil gradient line in figure 2 and the gas gradient line is at 9035' TVDss, coincident with the lowest known gas. The oil sample and oil gradient observed in figure 2 is located deeper than the water gradient. Oil has only been confirmed in the Kuparuk "AT' horizon. All other horizons are either gas or water bearing. Figures 3 and 4 describe the permeability of the Kuparuk reservoir. Figure 3 is a permeability verses depth plot taken from the mobility data gathered in the RFT's from the NS08, NS27 and NS13 wells. Permeability decrease with depth with the Kuparuk "A" having permeabilities less than 20 mD and averaging less than 10 nil). The Kuparuk "C" has permeabilities in the 100 to 200mD range. Figure 4 describes the porosity and permeability relationship determined from core data gathered at Northstar. Porosities in the Kuparuk "A" are low averaging 16% with a corresponding decrease in the permeability averaging 1 OmD. Porosity s • • and permeabilities in the Kuparuk "C" horizon are much greater averaging approximately 20% and 100 mD respectively The NS29 well shown in figure 7 has an interpreted gas/water contact in the "Kuparuk C" horizon at a depth of 9015' TVDss without a corresponding oil leg. Figures 5 and 7 are well log cross -sections showing the interpretation of the RFT results in figures 1 and 2. There is no direct evidence of an oil column in the Kuparuk "C" horizon. The lowest known gas in the Kuparuk "C" is 9035' TVDss and the highest known water in the Kuparuk "C" is 9050' TVDss observed in the NS09 well. The Gas/Water contact observed in the NS29 well was determined from MWD driller's depths and not wireline depths as in all other wells. It is unknown as to whether this differential contact represents compartmentalization in the NS29 fault block at the Kuparuk level or a needed depth correction from MWD depths to wireline depths. The magnitude of this correction ranges from 10 to 20 feet TVD deeper in adjacent wells. Wireline depths are deeper than MWD depths in all instances. None of the summer drilling wells are planned to penetrate the NS29 fault block — see figure 6. We interpret the Kuparuk "A" sands to have low permeability and subsequently low producibility. We also believe that the Kuparuk "C" and "A" reservoirs are probably not hydraulically connected. The Kuparuk "C" structure map (fig. 6) shows the reservoir penetrations for each of the wells to date. Also shown are the penetration points for the summer 2002 drilling program and for each of the currently planned remaining wells. The Kuparuk structure is a faulted anticline oriented NW to SE. This map was created using the existing well control and 3D seismic interpretation. Wells currently planned for the Summer 2002 drilling program are in the close proximity to wells that have already been drilled. The expected results for the summer drilling wells are shown in figure 8. In general, the Kuparuk "C" is expected to be gas bearing except for the NS05, NS23 and NS12 wells, which are prognosed to be wet. There is an unlikely possibility that oil will be found in the Kuparuk "C" interval in the NS06 well. The NS06 well is located near the Seal A-3 well. The Seal A-3 well production tested the Kuparuk "C" interval at a rate of 2500 BWPD with no trace of oil. If the NS06 well were to encounter an oil leg in the Kuparuk "C" horizon, it would be less than 15' thick To mitigate the drilling risks at Northstar we have instituted a number of precautions including, having mudloggers on location while drilling the Kuparuk interval, monitoring gas concentrations in the drilling mud, using sufficient mudweights to control reservoir fluids and utilizing standard North Slope drilling practices. There have been 15 penetrations of the Kuparuk reservoir in the vicinity of the Northstar field. This database of information and consequent analysis has helped us to accurately predict the hydrocarbon occurrences in the Kuparuk at Northstar. Sincerely, Kenneth Lemley Northstar development geologist #6 MUM Ms. Jane Williamson Alaska Oil and Gas Conservation Commission 0 EcENE JUL 13 2006 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 333 West 7' Avenue, Suite 100 Anchorage, AK 99501 Alaska Oil & Gas Cons. C05"' )ua Anchorage RE: Conservation Order 329B - BP Pilot Commingling of the Niakuk Oil Pool and Sag River Undefined Oil Pool, Prudhoe Bay Field, North Slope, Alaska June 27, 2006 Dear Ms. Williamson, In light of the Alaska Oil and Gas Conservations Commission's Conservation Order 329B dated November 9, 2005, BP Exploration (Alaska) Inc. has proceeded with the commingling production of the Niakuk Oil Pool and the Sag River Undefined Oil Pool within well NK-43. On 1/3/2006, the cast iron bridge plug that separated to two oil pools was milled out; however, the well would not produce. Several coil tubing clean outs were required to bring the well on production and well first produced from the commingled reservoirs on 2/3/06. It produced well for several weeks however, on 3/19/2006 a well integrity issue arose and the well was shut-in. Further diagnostics indicated that the tubing was leaking. Due to the initial delay bringing this well on production and the well integrity issues, BP has not had adequate time to test the geochemical and production profile methods to determine the best way to allocate production from this well. To date, 7 of the 18 required geochemical samples have been taken and 1 of the 3 production profiles has been run. The conservation order is scheduled to expire 7/l/2006. In order to satisfy the requirements set forth in Conservation Order 329B and to accurately determine an allocation method, BP requests that the conservation order be extended for a period of 6 months, expiring 1/1/2007. This will allow BP to obtain the necessary data required by the AOGCC to accurately determine the best method of allocation for this well. If you have any questions, feel free to contact me. 0 • Sincerely, -IAkc,,L Lo -e��X c--j Mark Weggeland GPMA Subsurface Team Leader BP Exploration (Alaska), INC. 900 E. Benson Blvd. P.O. Box 196612 Anchorage, AK 99519-6612 #s Re: NK-43 Commingling tests results - Administrative amendment C... Subject: Re: NK-43 Commingling tests results - Administrative amendment C0329B From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Tue, 27 Jun 2006 13:29:55 -0800 To: "Weggeland, Mark C" <Mark.Weggeland@bp.com> CC: "Mower, Matthew" <Matthew.Mower@bp.com>, "Strait, David R" <David.Strait@bp.com> "Alta-Darkwah, Samuel" <attasl@bp.com>, "Sloan, Marian" <SloanM@BP.com>, Robert P Crandall <bob crandall@admin.state.ak.us>, Cathy P Foerster<cathy_foerster@admin.state.ak.us>,'Winton G Aubert <winton aubert@admin.stateak.us> Mark, When do you plan to restart commingled production in NK-43? C0329B expires on July 1 but there are some data requirements that should be addressed prior to granting an extension. C0329 B states "The operator shall submit a monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation." Have you sent this data to us for the tests you've performed? Per your letter there was production from both pools within this well in February and March. I've not seen anything on the geochemical analysis or production logs. (The well file is out being scanned, and it's possible they were already sent.) Marion sends allocation files to me each month, but the break out of NK-43 production between Niakuk and Raven looks suspicious to me. From what I can tell, nearly all of the well allocated production to the Raven pool within NK-43 was either NGLs or gas lift gas. I'm attaching the well test and allocation files for February and March that Marion sent me. It would be helpful for the appropriate staff involved in this testing come over and review this with us. We need to see the results of your geochemical analysis and production logging. We need to review the well tests and how you have allocated oil, gas, water, gas lift between the Niakuk and the Sag formation (Raven undefined) oil pools. Give me a call at 793-1226 if you have questions. Jane Weggeland, Mark C wrote: Jane, Enclosed is a letter requesting extension of the NK-43 commingling test. I will send the hardcopy today, but wanted you to get this electronic version as soon as possible. <<06092006 Request to AOGCC to extend Conservation Order fof NK-43 Commingle.doc>> Thanks, Mark Weggeland GPMA Subsurface Team Leader Office: +1 (907) 564-5351 Mobile: +1 (907) 229-1628 1 of 2 6/27/2006 1:46 PM Re: NK-43 Commingling tests results - Adminis ative amendment C... � i Email: weggelmc(a)_bp.com Mail: BP Exploration (Alaska) Inc. PO Box 196612 Anchorage AK, 99519-6612 Jane Williamson, PE <iane williamson(a,admin.state. A.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission ............ Content -Type: application/x-zip-compressed 03-06 WT.ZIP Content -Encoding: base64 Content -Type: application/x-zip-compressed 0206 WELL.ZIP Content -Encoding: base64 2 of 2 6/27/2006 1:46 PM Ms. Jane Williamson Alaska Oil and Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 RE: Conservation Order 329B - BP Pilot Commingling of the Niakuk Oil Pool and Sag River Undefined Oil Pool, Prudhoe Bay Field, North Slope, Alaska June 27, 2006 Dear Ms. Williamson, In light of the Alaska Oil and Gas Conservations Commission's Conservation Order 329B dated November 9, 2005, BP Exploration (Alaska) Inc. has proceeded with the commingling production of the Niakuk Oil Pool and the Sag River Undefined Oil Pool within well NK-43. On 1/3/2006, the cast iron bridge plug that separated to two oil pools was milled out; however, the well would not produce. Several coil tubing clean outs were required to bring the well on production and well first produced from the commingled reservoirs on 2/3/06. It produced well for several weeks however, on 3/19/2006 a well integrity issue arose and the well was shut-in. Further diagnostics indicated that the tubing was leaking. Due to the initial delay bringing this well on production and the well integrity issues, BP has not had adequate time to test the geochemical and production profile methods to determine the best way to allocate production from this well. To date, 7 of the 18 required geochemical samples have been taken and 1 of the 3 production profiles has been run. The conservation order is scheduled to expire 7/1/2006. In order to satisfy the requirements set forth in Conservation Order 329B and to accurately determine an allocation method, BP requests that the conservation order be extended for a period of 6 months, expiring 1/1/2007. This will allow BP to obtain the necessary data required by the AOGCC to accurately determine the best method of allocation for this well. If you have any questions, feel free to contact me. 9 Sincerely, Mark Weggeland GPMA Subsurface Team Leader BP Exploration (Alaska), INC. 900 E. Benson Blvd. P.O. Box 196612 Anchorage, AK 99519-6612 application to extend Niakuk NK-43 Commingling - administrative a... Subject: application to extend Niakuk NK-43 Commingling - administrative amendment 329B From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Tue, 27 Jun 2006 11:28:11 -0800 To: Jody J Colombie <jody_colombie@admin.state.ak.us>, Robert P Crandall <bob Crandall@admin.state.ak.us>, Cathy P Foerster <cathy foerster@admin.state.ak.us>, John Norman<john_norman@admin.state.ak.us>, Dan T Seamount <dan_ seamount@adminstate.ak.us> I thought I should pass this on to you. Apparently the approval of NK-43 pilot commingling test ends July 1, so little time to work on this. I don't see a problem with extending. I'll put a draft AA together. ------- Original Message-------- Date:Tue, 27 Jun 2006 11:10:08 -0800 From:Weggeland, Mark C <Mark.Weggeland(abp.com> ToJane williamson cr,admin.state.ak.us CC:Mower, Matthew <Matthew.Mower(dbp.com>, Strait, David R <David. Strait4)ibp.com>, Atta-Darkwah, Samuel <attas l (d),bp.com> Jane, Enclosed is a letter requesting extension of the NK-43 commingling test. I will send the hardcopy today, but wanted you to get this electronic version as soon as possible. «06092006 Request to AOGCC to extend Conservation Order fof NK-43 Commingle.doc» Thanks, Mark Weggeland GPMA Subsurface Team Leader Office: +1 (907) 564-5351 Mobile: +1 (907) 229-1628 Email: weppelmcC)bp.com Mail: BP Exploration (Alaska) Inc. PO Box 196612 Anchorage AK, 99519-6612 Jane Williamson. PE <iane williamson()admin.state.ak.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission _ Content -Type: application/msword 06092006 Request to AOGCC to extend Conservation Order fof NK-43 Commingle.doc'' Content -Encoding: base64 1 of I 6/27/2006 2:39 PM [Fwd: Re: Commingling request] Subject: [Fwd: Re: Commingling request] From: Jane Williamson <jane_williamson@admin.state. ak.us> Date: Mon, 24 Oct 2005 14:28:41 -0800 To: Jody J Colombie<jody_colombie@admin.state.ak.us> Jody, Place in Niakuk Commingling file. Jane -------- Original Message -------- Subject: Re: Commingling request Date: Mon, 24 Oct 2005 14:21:19 -0800 From: Jane Williamson <jane williamson@admin.state.ak.us> Organization: State of Alaska To: Weggeland, Mark C <weggelmc@BP.com> CC: Don.Ince@conocophillips.com, "Jeff Farr (Farr, Jeff (ExxonMobil))" <jeff.e.farr@exxonmobil.com>, Lamont.C.Frazer@conocophillips.com, "Threadgill, Greg (ExxonMobil)" <greg.b.threadgill@exxonmobil.com>, "Fataliyev, Vusal" <fatavl@BP.com>, "French, Samuel W" <frensw@BP.com>, "Kincaid, Les" <les.kincaid@BP.com>, "Strait, David R" <StraitDR@BP.com>, "Gustafson, Gary G (Alaska)" <GustafGG@BP.com>, Robert P Crandall <bob crandall@admin.state.ak.us>, Robert E Mintz <robert mintz@law.state.ak.us>, Dan T Seamount <dan seamount@admin.state.ak.us>, John Norman <john norman@admin.state.ak.us>, Cathy P Foerster <cathy foerster@admin.state.ak.us> References:<6CAFCC2466A6DC428475F3562EEA742203C81B6A@bplancex002.bp1.ad.bp.com> Mark, Thank you. The Commission has sufficient information to rule and the hearing is canceled. Jane Weggeland, Mark C wrote: Jane, Enclosed with this note is the full text of the report provided by OilTracers on the proposed geochemical allocation methodology. We respectfully request that this document be held confidential in accord with AS 31.05.035 and 20 AAC 25.537. Mark Weggeland GPMA Subsurface Team Leader Office: +1 (907) 564-5351 Mobile: +1 (907) 229-1628 Email: weggelmc@bp.com Mail: BP Exploration (Alaska) Inc. PO Box 196612 Anchorage AK, 99519-6612 ------------------------------------------------------------------------ *From:* Jane Williamson (mailto:jane williamson@admin.state.ak.us] *Sent:* Friday, October 21, 2005 3:24 PM *To:* Weggeland, Mark C *Cc:* Gustafson, Gary G (Alaska); Robert P Crandall; Robert E Mintz; Dan T Seamount; John Norman; Cathy P Foerster *Subject:* Re: Commingling request Mark, Please review the regulatory requirements within 20 AAC 25.215(b) for approval of 1 of 3 10/24/2005 4:07 PM [Fwd: Re: Commingling request] commingling of production within the same wellbore. We are not allowed to approve your application unless we can be assured that production can be properly allocated . While the summary you provided is good for the public, it is general in nature and does not provide the technical details we need. This technique of allocation has never been approved by the Commission before for production allocation purposes. I am advising the Commissioners that more detailed technical information is needed for Commission Staff to make a positive technical recommendation on your request. Based upon our quick glance of the report that Les allowed us yesterday, it appeared that this information may be within the body of this report. While the Commissioners would need to rule on this, it appeared to me that you have a good basis for confidential treatment of the report body. Please call if you have questions. Jane Weggeland, Mark C wrote: Jane, Enclosed is the summary section from the Geochemical analysis report prepared for the NK-43 commingling application. As discussed with you by Les Kincaid, we feel that this method for production allocation is accurate and reliable. Please call me if you have more questions. Mark Weggeland GPMA Subsurface Team Leader Office: +1 (907) 564-5351 Mobile: +1 (907) 229-1628 Email: weggelmc@bp.com Mail: BP Exploration (Alaska) Inc. PO Box 196612 Anchorage AK, 99519-6612 ------------------------------------------------------------------------ *From:* Jane Williamson [mailto:jane williamson@admin.state.ak.us] *Sent:* Thursday, September 15, 2005 5:55 PM *To:* Weggeland, Mark C; Gustafson, Gary G (Alaska) *Cc:* Robert P Crandall *Subject:* Commingling request Mark and Gus, Below are a few items that need more clarification in your application for commingling in NK-43. 1. Must have a description of strata (Depths top/bottom in well) 2. Rough OOIP in reservoir 3. Sag Maps - top structure and net pay 4. What is the reservoir pressure in the Sag and the Kuparuk formations within the well. 5. Log of NK-43 in Sag (like what you showed in your presentation today) - with contacts shown 6. Rock and fluid properties of Sag (to the extent you know. Particularly, what is solution GOR?) 7. If GOR above solution (18,000 scf/STB), you will require waiver 8. Will production without pressure support cause loss of reserves within the 6 mo. time period of pilot? (provide some evidence based upon material balance and/or analog estimate - model not required.) If there are losses anticipated, you will need a good justification of why the test is a good thing to do. 9. Any concerns with cross -flow? Why or why not? 10. Need more description on methodology of estimating production 2 of 3 10/24/2005 4:07 PM [Fwd: Re: Commingling request] i 0 splits 1. Details on the geochemical analysis methodology. 2. What types of production logs - how often Please call if you have questions. Jane Williamson, PE <iane williamsonpadmin. state. ak.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission 3 of 3 10/24/2005 4:07 PM [Fwd: NK-43A exhibits confidentiality justification] • Subject: [Fwd: NK-43A exhibits confidentiality justification] From: Jane Williamson <jape_williamson@admin.state. ak.us> Date: Thu, 20 Oct 2005 09:22:26 -0800 To: Jody J Colombie<jody_colombie@admin.state. ak.us>.:�,, Please add this to the Niakuk NK-43 Commingling request -------- Original Message -------- Subject: NK-43A exhibits confidentiality justification Date: Thu, 20 Oct 2005 08:05:40 -0800 From: Gustafson, Gary G (Alaska) <GustafGG@BP.com> To: jane williamson@admin.state.ak.us CC: Mark C Weggeland (Weggeland, Mark C) <weggelmc@BP.com>, StraitDR@BP.com Kincaid, Les <les.kincaid@BP.com>, bob crandall@admin.state.ak.us Jane, On October 17, 2005 Mark Weggeland sent you two documents responding to your Sept. 15, 2005 request for additional information related to our NK-43A commingle request. The Oct. 17 transmittal note requested that Exhibit 1, Exhibit 2, and Exhibit 3 be held confidential in accord with AS 31.05.035 and 20 AAC 25.537. We now wish to supplement this confidentiality request for the record. Confidentiality is necessary because these exhibits contain engineering, geological and other information relating to the valuation of unleased state land in the same vicinity. The NK-43A well is located in close proximity to unleased state oil and gas lease acreage located immediately north of the PBU and Niakuk PA. Thank you for your cooperation. Gus Jane Williamson, PE <iane williamson(Dadmin.state.ak.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission 1 of 1 10/21/2005 8:39 AM RE: Commingling request is 11 Subject: RE: Commingling request From: "Weggeland, Mark C" <weggelmc@BP.com> Date: Mon, 17 Oct 2005 16:25:29 -0800 To: Jane Williamson <jane—williamson@admin. state.ak.us>, Robert P Crandall <bob—crandall@admin. state. ak.us> CC: "Gustafson, Gary G (Alaska)" <GustafGG@BP.com>, "Fataliyev, Vusal" <fatavl@BP.com>, "French, Samuel W" <frensw@BP.com>, "Kincaid, Les" <les.kincaid@BP.com>, "Strait, David R" <StraitDR@BP.com>, Don.Ince@conocophillips.com, "Jeff Farr (Farr, Jeff (ExxonMobil))" <jef .e.farr@exxonmobil.com>, Lamont.C.Frazer@conocophillips.com, "Threadgill, Greg (ExxonlVlobil)" <greg.b.threadgill@exxonmobil.com> Jane, Enclosed are two documents containing our response to your request below. Please note that we request that Exhibit 1, Exhibit 2, and Exhibit 3 be held confidential in accord with AS 31.05.035 and 20 AAC 25.537. Thanks, Mark Weggeland GPMA Subsurface Team Leader Office: +1 (907) 564-5351 Mobile: +1 (907) 229-1628 Email: weggelmc@bp.com Mail: BP Exploration (Alaska) Inc. PO Box 196612 Anchorage: AK, 99519-6612 From: Jane Williamson [mailto:jane_williamson@admin.state.ak.us] Sent: Thursday, September 15, 2005 5:55 PM To: Weggeland, Mark C; Gustafson, Gary G (Alaska) Cc: Robert P Crandall Subject: Commingling request Mark and Gus, Below are a few items that need more clarification in your application for commingling in NK-43. 1. Must have a description of strata (Depths top/bottom in well) 2. Rough OOIP in reservoir 3. Sag Maps — top structure and net pay 4. What is the reservoir pressure in the Sag and the Kuparuk formations within the well. 5. Log of NK-43 in Sag (like what you showed in your presentation today) — with contacts shown 6. Rock and fluid properties of Sag (to the extent you know. Particularly, what is solution GOR?) 7. If GOR above solution (18,000 scf/STB), you will require waiver 8. Will production without pressure support cause loss of reserves within the 6 mo. time period of pilot? (provide some evidence based upon material balance and/or analog estimate - model not required.) If there are losses anticipated, you will need a good justification of why the test is a 1:12 RE: Commingling request is good thing to do. 9. Any concerns with cross -flow? Why or why not? 10. Need more description on methodology of estimating production splits a. Details on the geochemical analysis methodology. b. What types of production logs — how often Please call if you have questions. Content -Description: NK-43 Commingle Iinformation.pdf NK-43 Commingle Iinformation.pdf Content -Type: application/octet-stream Content -Encoding: base64 Content -Description: NK-43 Commingle Exhibits.ZIP NK-43 Commingle Exhibits.ZIP Content -Type: application/x-zip-compressed Content -Encoding: base64 • • NK-43 Commingle Information for Jane Williamson Request, September 15, 2005 Description of strata (Depths) Top Kuparuk 13,113 (-9260) Top Perf 13,121 (-9267) Base Perf 13,196 (-9333) Base Kuparuk 13,258 (-9388) Top Sag River 13,653 (-9745) Top Perf 13,674 (-9764) Base Perf 13,740 (-9825) Base Sag River 13,742 (-9827) OOIP in Sag River reservoir OOIP 6,426,000 STB - Black Oil OOIP 4,661,000 STB - Condensate OOIP 1,765,000 STB OGIP 34,200 MMscf - Total Free Gas OGIP 27,200 MMscf - Total Solution OGIP 7,100 MMscf Sag Maps — top structure and net pay Exhibit 1 — Top Sag River Depth Exhibit 2 — Sag River Gross Oil Thickness* Exhibit 3 — Sag River Gross Gas Thickness* * Note: Net:Gross is 55% Reservoir pressure in the Sag and the Kuparuk formations within the NK-43 SBHP 3255 psi -9200 TVDss August 2001 PBU (Pmax) 3915 psi. -9800 TVDss March 2001 Log of NK-43 Well Log over Sag River, with contacts shown Exhibit 4 — NK-43 • • Rock and fluid properties of Sag River Porosity: 20% N:G 55% SW 40% Boi 1.960 rb/stb Rsi 1600 scf/stb Bgi 0.62 rb/Mscf Black Oil 32 API Condensate 49 API Cond. Yield 65 bbl/MMscf Reserves loss in six month test period with no pressure support The estimated oil and gas production from a six month test of the NK 43 well in the Sag would be insignificant compared to the total hydrocarbons in place for the Raven Sag accumulation. Approximately 40,000 to 90,000 bbl oil and 560 MMscf to 1,300 MMscf gas are expected to be produced from the NK-43 Sag River during a six month time period based on volumetric analysis and decline curve analysis. An average GOR of 14,000 scf/stb was used for this 6 month time period. The average produced GOR was 14,000 scf/stb during the six weeks of NK-43 Sag production in 2001. There should be no significant loss of reserves from the Raven Sag River accumulation from a material balance standpoint. Results of this production test on NK43 will be used to evaluate the viability of a waterflood project in the Sag. A waterflood project would maintain pressure from dropping further and possibly increase pressure in the Sag reservoir back to near original reservoir pressure. Commingling the Kuparuk and Sag reservoirs in NK-43 would provide synergistic benefits that should actually maximize rate and recovery that may not occur otherwise. The SAG produces at high GORs (-14,000 SCF/B) and is expected to have difficulty producing by itself due to hydrate problems as liquid rates decline. The Kuparuk produces at high water cuts (-70%) and requires lift gas to flow. Kuparuk production would benefit the Sag by keeping temperatures in the tubing warm enough to prevent hydrates, while Sag production would benefit the Kuparuk by providing "lift gas" at a more efficient lifting point than that provided by gas lift mandrels. Cross -flow concerns A production log (spinner, temperature, and density) will be run once during the first month of production to determine whether significant dynamic and static crossflow occurs downhole between the Kuparuk and Sag. Methodology of estimating production splits (Geochemical & Production logs) The primary method for estimating Kuparuk/Sag production splits will be geochemical analysis. In August 2005 BP requested OilTracers LLC to test three different samples of Kuparuk/Sag oil mixtures for determining production splits. This work demonstrates that geochemical allocation of commingled production will yield highly accurate results (+/- 1.5 to 2.5% error). BP recommends sampling once per month for geochemical analysis to determine production splits. #4 STATE OF ALASKA ADVERTISING ORDER 0 NOTICE TO PUBLISHER 4j INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. /► O.02614013 A SEE BOTTOM FOR INVOICE ADDRESS F R ° M AOGCC AGENCY 333 W 7th Ave, Ste 100 Jody Anchorage, AK 99501 PHONE _ DATES CONTACT Colombie DATE OF A.O. September 13 2005 PCN ADVERTISEMENT REQUIRED: September 15, 2005 MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ON THE DATES SHOWN. o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 THE b ENTIRETY SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement X Legal ❑ Display ❑ Classified ❑Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 AncheraLae. AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 3 4 PIM AMnl INT CV (`(' P(3M I r ArrT GV NMR DIST LIQ 1 05 02140100 73451 2 3 4 REQUISITIONED BY: DIVISION APPROVAL: ! i Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Prudhoe Bay Field Niakuk Oil Pool Application to allow commingling of production from the Niakuk Oil Pool and Sag River reservoir (un-named oil pool) within Well NK-43A By letter dated September 1, 2005, BP Exploration (Alaska) Inc. as Unit Operator of the Prudhoe Bay Unit requested the Commission to issue an order in conformance with 20 AAC 25.215(b) allowing commingling of production from the Niakuk Oil Pool and Sag River reservoir (undesignated oil pool) within Well NK-43A. The bottomhole location of the well is in Section 29, T12N-R16E, Umiat Meridian. The Commission has tentatively scheduled a public hearing on this application for October 25, 2005 at 1:30 pm at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on September 30, 2005. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221 after October 10, 2005. In addition, a person may submit a written protest or written comments regarding this application and proposal to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Protests and comments must be received no later than 4:30 pm on October 17, 2005 except that if the Commission decides to hold a public hearing, protests or comments must be received no late the conclusion of the October 25, 2005 hearing. If you are a person comment or to attend the pi Colombie at 793-1221. / N Published Date: 9/15/05 AO: 02614013 may need special accommodations in order to ntact the Commission's Special Assistant Jody Re: Public Notice Subject: Re: Public Notice From: "Ads, Legal" <legalads@adn.com> Date: Tue, 13 Sep 2005 11:53:40 -0800 To: Jody Colombie <jody_colombie@admin.state. ak.us> Hello Jody: Following is the confirmation information on your legal notice. Please review and let me know if you have any questions or need additional information. Account Number: STOF 0330 Legal Ad Number: 601388 Publication'Date(s): September 15, 2005 Your Reference or PO#: 02614013 Cost of Legal Notice: $182.40 Additional Charges: Web Link: E-mail Link: Bolding: Total Cost To Place Legal Notice: $182.40 Your Legal Notice Will Appear On The Web: www.adn.com: XXXX Your Legal Notice Will Not Appear On The Web www.adn.com: Thank You, Kim Kirby •Anchorage Daily News Legal Classified Representative E-Mail: legalads@adn.com Phone: (907) 257-4296 Fax: (907) 279-8170 On 9/13/05 11:03 AM, "Jody Colombie" <jody colombie@admin.state.ak.us> wrote: Please publish 9/15/05. • 1 of 1 9/13/2005 1:04 PM AD # DATE PO ACCOUNT 601388 09/15/2005 02614013 STOF0330 Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER PER DAY CHARGES $182.40 $182.40 $0.00 STATE OF ALASKA THIRD JUDICIAL DISTRICT Teresita Peralta, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed 0.� Subscribed and sworn to me before this date: it l C 9/15/2005 OTHER OTHER OTHER OTHER GRAND CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL $0.00 $0.00 $0.00 $0.00 $182.40 Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: 0, ,'0 t tt V�� EItLY ,� �✓� LIC OF ALS Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Prudhoe Bay Field Niakuk Oil Pool Application to allow commingling of Production from the Niakuk Oil Pool and Sag River reservoir (un-named oil pool) within Well NK-43A By letter dated September 1, 2005, BP Exploration (Alaska) Inc. as Unit Operator of the Prudhoe Bay Unit requested The Commission to issue an order in conformance with 20 AAC 25.215(b) allowing com- mingling of production from the Niakuk Oil Pool and Sag River reservoir (undesignated oil pool) within Well NK-43A. The bottomhole location of the well is in Section 29, T12N-R16E, Umiat Meridian. The Commission has tentatively scheduled a Pub- lic hearing on this application and the Commission Proposal for October 25, 2005 at 1 :30 pm at the of- fices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, An- chorage, 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 September 30, 2005. If a request for a hearing is not timely filed, the Commission may consider the issuance of an or- der without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221 af- ter October 10, 2005. In addition, a person may submit a written protest or written comments regarding this application and proposal to the Alaska Oil and Gas Conserva- tion Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Protests and comments must be received no later than 4:30 pm on October 17, 2005 except that if the Commission decides to hold a public hearing, protests or comments must be received no later than the conclusion of the Oc- tober 25, 2005 hearing. If You are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact the Commission's Special Assistant Jody Colombie at 793-1221. John K. Norman Chairman AO: 02614013 Published Date: 9/15/05 02-902 (Rev. 3/94) Publishe*inal Copies: Department Fiscal, Departm*eceiving AOTRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A/� O.02614013 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 71" Avenue. Suite 100 Jody Colombie September 13. 2005 o Anrhnmue AK QQ5O1 PHONE PCN M 907-793-1221 -1221 ADVERTISEMENT REQUIRED: T Anchorage Daily News September 15, 2005 PLO„ Box 149001 Anchorage, A11 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS tlll g ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2005, and thereafter for consecutive days, the last publication appearing on the day of , 2005, 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 2005, Notary public for state of My commission expires 02-901 (Rev. 3/94) AOTRM 0 • Citgo Petroleum Corporation Mary Jones David McCaleb PO Box 3758 XTO Energy, Inc. IHS Energy Group Tulsa, OK 74136 Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft, Worth, TX 76102-6298 Houston, TX 77056 Mona Dickens Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 408 18th Street President Boise, ID 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman Schlumberger David Cusato Halliburton Drilling and Measurements 200 West 34th PMB 411 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Baker Oil Tools Ivan Gillian Land Department 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99507 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla Richard Wagner Cliff Burglin 399 West Riverview Avenue PO Box 60868 PO Box 70131 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl Williams Thomas North Slope Borough K&K Recycling Inc. Arctic Slope Regional Corporation PO Box 69 PO Box 58055 Land Department Barrow, AK 99723 Fairbanks, AK 99711 PO Box 129 Barrow, AK 99723 Public Notice 0 Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 13 Sep 2005 11:04:04 -0800 To: Cynthia B Mciver <bren mciver@admin.state.ak.us> Niakuk Commingling.doc Content -Type: application/msword Content -Encoding: base64 1 of 1 9/13/2005 11:05 AM Public Notice PBU Niakuk 43A 0 Subject: Public Notice PBU Niakuk 43A From: Jody Colombie <Jody_colombie@admin.state. ak.us> Date: Tue, 13 Sep 2005 11:05:16 -0800 To: undisclosed -recipients:; BCC: Robert E Mintz <robert_mintz@law. state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, trmjrl <trmjrl@aol.com>, jbriddle <jbriddle@marathonoil.com>, shaneg <shaneg@evergreengas.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tj r@dnr. state. ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD69BP.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.£fullmer@conocophillips.com>, bocastwf <bocastwf@bp.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesno 1 @gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud"<james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <j ah@dnr. state. ak.us>, Kurt E Olson <kurt_olson@legis.state. ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, loren_leman <loren_leman@gov.state. ak.us>, Julie Houle <julie_houle@dnr.state. ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan_hill@dec.state. ak.us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr. state. ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Bill Miller <Bill_Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks<kristin_dirks@dnr.state. ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe. gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>, jack newell <jack.newell@acsalaska.net>, James Scherr <james_scherr@yahoo.com>, david roby <David.Roby@mms.gov>, Tim Lawlor 1 of 2 9/13/2005 11:05 AM Public Notice PBU Niakuk 43A <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry. C.Dethlefs@conocophillips.com>, Jerry Dethlefs <nl617@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>, Harry Lampert <harry.lampert@honeywell.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Todd Kratz <ToddKratz@chevron.com>, Gary Rogers <gary_rogers@revenue. state.ak.us>, Arthur Copoulos <Arthur_Copoulos@dnr.state.ak.us>, Phillip Ayer <pmayers@unocal.com>, Ken <ken@secorp-inc. com> Niakuk Commingling.pdf Content -Type: application/pdf Content -Encoding: base64 2 of 2 9/13/2005 11:05 AM Public Notice 0 Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 13 Sep 2005 11:03:41 -0800 To: Legal Ads Anchorage Daily News <legalads@adn.com> Please publish 9/15/05. Content -Type: application/msword Ad Order form.doc Content -Encoding: base64 Niakuk Commingling.docContent-Type: application/msword ' Content -Encoding: base64 1 of 1 9/13/2005 11:05 AM #3 by BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 1907) 561-5111 BY FACSIMILE AND CERTIFIED MAIL September 1, 2005 Mark Myers, Director Division of Oil and Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, AK 99501 RE: Tract Operations — NK. - 43A Well ADL 034635 - PBUA Tract 32 Niakuk Participating Area Prudhoe Bay Unit Dear Dr. Myers: BP Exploration (Alaska) Inc. (BPXA), operator of the Niakuk Participating Area (NPA), the Prudhoe Bay Unit (PBU) and the ADL 034635 tract, on behalf of itself and Chevron U.S.A Inc., ConocoPhillips Alaska, Inc., ExxonMobil Alaska Production Inc. and Forest Oil Corporation, requests tract operation approval to use the existing NK-43A Well in ADL 034635 (PBUA Tract 32) to also conduct Sag River production. This tract operation will to produce from the Sag River reservoir and commingle with NPA Kuparuk production in the NK-43A well bore. BPXA requests approval of the tract operation as a 180-day pilot commingle project from September 15, 2005 through March 15, 2006. The location of the NK-43A Well, including well bore trajectory and bottomhole location, is depicted in Exhibit A. The NK-43A Well is currently producing approximately 206 BOPD, 656 BWPD and 514 MCFPD from the Kuparuk Reservoir within the Niakuk Participating Area (NPA). The NK-43A well originally penetrated the Sag River reservoir in early 2001 and produced approximately 500 BOPD and 8.1 MMCFD in the two months before it was shut-in on May 4, 2001. Exhibit B shows the NK-43A production plot with Sag River and Kuparuk production annotated. Exhibit C depicts the current NK-43A well bore configuration. The objectives of the pilot project are to gather production and geochemical data to determine a reliable and acceptable production allocation method. Production from the well during the pilot project will be commingled in the well bore and then flow to, and be processed at, the Lisburne Production Center (LPC). For royalty and production tax purposes, all production during the pilot project will be allocated to ADL 034635 and will be reported separately as either NPA or ADL 034635 tract operation production. Production taxes and royalty remain the responsibility of the respective NPA and ADL 034635 tract owners and production will be determined and allocated in accordance with the terms and conditions of the PBU Western Satellite Production Metering Plan. BPXA proposes that for purposes of nominating and calculating the percentage of Royalty -in -Kind (RIK) during the pilot project, allocation of produced volumes from the Sag River and Kuparuk reservoirs will be estimated using geochemical analysis and production profile logs. Any NGL's removed from the well's produced gas will be accounted for and reported separately as NPA or ADL 034635 tract operation NGLs. Any residue gas consumed or injected will be accounted for as NPA gas. BPXA staff representatives are available should you have any questions or need any additional information. We look forward to your timely action on this request. If you need any additional information, please contact Gary Gustafson at 564- 5304. Sincerely, Mark Weggeland GPMA Manager Attachments: Exhibit A — Location Map Exhibit B — NK-43A Production Plot Exhibit C — NK-43A Wellbore Schematic Cc; w/attachments: Sonny Rix, XOM Leonard Gurule, Forest Oil D. Kruse, CPAI G.M. Forsthoff, Chevron Don Ince, CPAI J. Farr, XOM G. Gustafson, BPXA Gary Benson, BPXA Art Copoulos, DO&G Jane Williamson, AOGCC 2 IN • I m z i (V .00 N m m � m go i R N i i Q7 i m � � m CV N 0 s � m V P a III g A Ct"I 10 BOPD & BWPD p 0 O O O N N O O W co O O A O N O (/q O O — — o O- =-0 O 08 AP' O --�- y _ m Pi O Z ...... _:� F► ._ ._ .:. _.. .d o � w W � o O Q C O i O A - O O \ O N A O W O O O O O O O O O O O O O O O O O O O O O O O O O O MCFPD r 0 • Exhibit C: NK-43 Wellbore Schematic TF= 4.1,'1G Wc:L.LHI'.7iDm 1a-s/6° KB. ELEV BF. ELEV = KCe 350' Artaz Angle = 54 @ 3798' € um PAD Datum TVD- 900'SS 18-314' CSG. 45.59, L-80, 5TC, la= 9.950- Minimum ID = 3.725" @ 12973' I 44J2" XN NIPPLE TBG, 12,69. L,80, .0152 bpi, 10= 3.958' 7" CM 26&fFG L-80, ID PERF,0PAT'iON SUMMARY RE=LM.: AD140WO O1 ANGLE AT TOP PERT 23t13710' We: Refs,- to Pr(xl w— DS for histo*?caf part data SEE SPF !LELT,AL :ATE 2-718' 6 13121 - 13171051c4r'O1 2-VS' 6 '3121 - 13l71O'r SMI 2J18' 6 '33185- 1319606,V,'O1 2-716' 6 > 3227. 13242O Faolsled 0,7101 2-718' B 13674- 13704 05104,'0i 2-7iF 6 '3'710- 13740 O.uOW01 N K-43 I -P-Y NOTES: 1 14.1?2' NFS FtXO LAt•%1kt.. NIP,10 = 3.813" I nA:l 1 i T AA.f.33M.F: ti ST MD jTVt)jMNj TYPE VLV LATCH FORT -DATE 6 3675 2975 KBO2 i- 16 057+02 6 7444 530 KBG2-LS,= 6dT6 0511V02 4 10077 7000 002-L&MOO DOAIE INT i8 06717J02 3 11768 810O KBG2 LS-MOD SO INT 24 06:17i02 2 12531 $750 KBG2 LS-t4OD DW Ik'T 1 12840 8020 KBL32-LS.MOD DMY INT- € F'.NTRY Gt{OE TOP OF E R'd 1-3vaff . X'OFSAND- 6127,b1 5' X7" BAKER ZXP UNI SAKER C3P ._.W... PRIIDIK}E BAY MR 'N�.L: NK-k3 PER?0No. 2010010 ARNoATOlTLH GATE R"r.V BY _ .... _._..--... (OPAki NTS __ DATE REV BY COk+WiTS VWSI Prmosed Cowalkm 0-1113,01 VlM9KAi( W-PE?FS GNK OR>,^Wt ONIPLFION 071201C1 PCib'DRS UPDATES JLAtto C(AR��JN3 W101L2 J'N4'Tlii GLVi1PD.ATE g12 Anil "ft SEC 36, T12N, RISE 144Y NSL 5 802'EV& Ci1KAK PERFS BF F,.rA—iion W-ska) d.AKAK AEk"EFiF58C6P #2 by 0 �1104091 SEP 0 2 2005 Alaska Oil & Gas Cons. Commissial Anchorage BY FACSIMILE AND CERTIFIED MAIL September 1, 2005 John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 • 0 BP Exploration (Alaska)Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 RE: Request for Approval for Pilot Project Approval to Commingle Production from the Kuparuk and Sag River Reservoirs in the NK-43A Wellbore Niakuk Participating Area - Prudhoe Bay Unit Dear Chairman Norman: BP Exploration (Alaska) Inc. (BPXA), operator of the Niakuk Participating Area (NPA) and the Prudhoe Bay Unit (PBU), on behalf of itself and Chevron U.S.A Inc., ConocoPhillips Alaska, Inc., ExxonMobil Alaska Production Inc. and Forest Oil Corporation, hereby requests approval to initiate a 180-day pilot project to commingle production from the Sag River and Kuparuk Reservoirs in the existing NK-43A well bore. The location of the NK-43A Well is depicted in Exhibit A. The Sag River penetration was completed on March 10, 2001 and produced approximately 35.8 MBO over two months. The Sag River was then temporarily shut-in on May 4, 2001 after producing approximately 500 BOPD and 8.1 MMCFD. The Kuparuk penetration was completed uphole on May 4, 2001 and has produced about 348 MBO. The NK-43A Well is currently producing approximately 206 BOPD, 656 BWPD, and 514 MCFPD from the Kuparuk Reservoir. Exhibit B shows the NK-43A production plot with Sag River and Kuparuk production annotated. Exhibit C depicts the current NK-43A well bore configuration. BPXA believes that combining production from both reservoirs will increase total production and maximize ultimate recovery. Objectives of the pilot project are to gather production and geochemical data to determine a reliable and acceptable production allocation methodology. Production will be commingled in the well bore and delivered to the Lisburne Production Center (LPC). The pilot project will use the following protocols. 1. The NK-43A well will be shut-in and the cast iron bridge plug will be removed. The well will then be put back into production. The pilot period will commence on the date when sustained oil flow is produced to surface. BPXA will inform the AOGCC within seven (7) days of this date. 2. BPXA will report oil, gas, and water production during the 180-day pilot project period. Plans are to meter total volumes of oil, gas, and water production using the Niakuk test separator. There may be periods in which production is routed to the Niakuk manifold without metering. In these instances, total produced volumes will be estimated. 3. Allocation of produced volumes to the Kuparuk and Sag River reservoirs will be estimated for each reservoir using geochemical analysis and production profile logs. After conclusion of the pilot project, BPXA will schedule a meeting with AOGCC staff to review the data acquired and pilot project results and determine the next steps. A request for tract operations approval to produce the Sag River reservoir from the NK-43 well has also been simultaneously submitted to the Division of Oil & Gas. 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. Sincerely, Mark Weggeland GPMA Manager Attachments: Exhibit A — Location Map Exhibit B — NK-43A Production Plot Exhibit C — NK-43A Wellbore Schematic Cc; w/attachments: Sonny Rix, XOM Leonard Gurule, Forest Oil Dan Kruse, CPAI G.M. Forsthoff, Chevron Don Ince, CPAI Jeff Farr, XOM Gary Gustafson, BPXA Art Copoulos, DO&G Jane Williamson, AOGCC 2 .. . .0 -41OR 0 0 • s 0 a c 0 r 0 I - a. co z m x w N y 3 'o rn 0 0 addOW N� 1 1 1 1 1§§ 0 0 O O O O O O O O O O O O O O co Cl)N N r O Ip adMG V ad08 LO 0 0 O s 0 N O O O n O Exhibit C: NK-43 Wellbore Schematic TREE= 4.111G ELUiF D" 13-5'IVN K- 43 SAFETY NOTES: ACTUATOR ., ELEV z .'µ.5- 102 102 W rZ DA TE REV 8Y I CCMNEWS DATE REV 8Y I COM M NTS FRUX HOE SAY UWr 12YJfN00 WSI RoWsed CAmp*tfon 07113fOi WWMAK WWRFS VNIM : W-43 =10,01 GNK ORIG—L COh1kFTIM 07MOT PaMM UPDATES PEFM1IT No: 2010010 017 001 JLAAp JOURRECTIONS OW8102 JMTLN GL Upn..ATe APY No' 50-029.22990 CK1l2m ATt nH ADO PEA SEC 98. T12JA R18E. 1441' NSL & 8OY EWL OWn"I CSMAK PERFS 0g/0 Dl JX"K ADPEIWS&COP S' Expbralroc(Ai9ska) #1 August 2005 OilTracers OT Report No. 05-313 CONFIDENTIAL