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Home My WebLink AboutCO 484 AConservation Order 484A Prudhoe Bay Unit 1. September 6, 2005 Notice of Hearing, affidavit of publication, email distribution, and mailings 2. October 13, 2005 Transcript 3. August 31, 2006 Email to operator re: reporting times 4. August 31, 2006 Prudhoe Bay Filed – Annual Surveillance Reporting requirements to AOGCC 5. May 23, 2007 Annual Surveillance Reporting Requirements (CO 484A.001) 6. April 1, 2014 BPXA’s request to modify the reservoir pressure monitoring requirements for the S/M-Pad North reservoir compartment (CO 484A.002) 7. November 2, 2015 Request for admin approval for waiver of monthly reporting of daily production allocation data (CO 484A.003) 8. October 23, 2018 Request for admin approval for conforming PBU Satellite Pool Rules for Consistency (CO 484A.004) 9. February 24, 2020 BPXA Request to amend CO 492 rule 3(a) and 6(a) (co484A.005)) 10. May 21, 2020 Notice of Hearing and mailing 11. ----------------- Emails 12. December 17, 2021 Request for admin approval to amend CO 484 by repealing Rule 1 (CO 484A.006) ORDERS ) ) STATE OF ALASKA ALASKA OIL AND GAS CONSERV A TION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: COMMISSION PROPOSAL to amend Conservation Order 484 ) ) ) ) ) ) ) Prudhoe Bay Field Polaris Oil Pool Conservation Order 484A November 30,2005 IT APPEARING THAT: 1. By application dated August 23, 2005, BP Exploration (Alaska) Inc. ("BPXA") in its capacity as Polaris Operator and Unit Operator of the Prudhoe Bay Unit ("PBU") requested an order from the Commission modifying Area Injection Order 25 ("AIO 25") to authorize the injection of enriched hydrocarbon gas for enhanced oil recovery purposes in the Polaris Oil Pool within the PBU. 2. In addition, the Commission, on its own initiative proposed amendment of Conservation Order No. 484, Rule 7, to add enriched gas injection as an approved enhanced recovery operation, and Rule 9, to update reporting requirements to include results of enriched gas injection; and, proposed to consolidate within a revised Conservation Order No. 484 all related existing orders affecting the Polaris Oil Pool. 3. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on September 6, 2005 concerning BPXA's application and the Commission's proposals. A public hearing was held on October 13, 2005 at the Alaska Oil and Gas Conservation Commission offices at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. 4.. The Commission received no comments or protests regarding BPXA's application or the Commission's proposals. FINDINGS: 1. CO 484, Rule 7: CO 484 and AIO 25 approved and required the use of water injection. AIO 25A sets ) ) Page 2 Conservation Order 484A November 30,2005 out rules for injection of enriched hydrocarbon gas for the purposes of enhanced oil recovery. Rule 7 of CO 484 should be updated to include enriched hydrocarbon gas injection as an approved depletion plan option for the Polaris Oil Pool. 2. CO 484, Rule 9: BPXA plans to monitor the composition of produced gas within offset producing wells to determine the breakthrough volumes of enriched gas. This surveillance is needed for evaluation of the effectiveness of the enriched gas flood. Rule 9 currently includes a requirement that a surveillance report be submitted by April 1 of each year and that a technical meeting with the Commission be conducted by June 1 of each year. While yearly reviews are still needed, it is appropriate to allow more flexibility for the date of such meetings. 3. Consolidation of Orders: CO 484 was approved on February 4, 2003. Since that time several new orders have been issued which affect the Polaris Oil Pool. These include the following: (a) CO 492 added rules concerning the regulation of annulus pressures of development wells. (b) CO 484.01 amended rules concerning the regulation of annulus pressures of development wells as adopted within CO 492. (c) CO 484.02 provided permanent approval of the Prudhoe Bay Unit Western Operating Metering Plan and required technical process review meetings at least annually. (d) CO 547 provided rules for use of Multiphase meters for well testing for the Prudhoe Bay Unit Fields, including the Polaris Oil Pool. (e) CO 556 added rules for waiver of "Application for Sundry Approval" for workover operations. CONCLUSIONS: 1. Enriched gas injection will significantly improve recovery, and CO 484 should be updated to allow for such injection. 2. Yearly reviews of injection performance are needed but specification of reporting dates is not necessary within this Order. 3. It is appropriate to consolidate Rules affecting the Polaris Oil Pool into one Order. NOW, THEREFORE, IT IS ORDERED: Conservation Order 484A November 30, 2005 ) Page 3 1. Pool Name. Classification. and Definition: The Polaris Pool is classified as an oil pool. This pool is defined as the accumulation of hydrocarbons common to, and correlating with, the interval between 5,544 feet and 6,012 feet measured depth MD in well PBU S-200PB 1. 2. In addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), the following rules apply to the Polaris Oil Pool within the following described area and supersede and replace the Rules adopted in Conservation Order No. 484. Umiat Meridian Township / Range Lease Sections T12N-R12E ADL 28256 Sec 22 S/2 S/2 and NE/4 SE/4 ADL 47448 Sec 23 S/2 NW /4 and SW /4 ADL 28257 Sec 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26,35,36 ADL 28258 Sec 27, 33 SE/4 SE/4, 34 E/2 W/2 and SW/4 SW/4 and E/2 T12N-R13E ADL 28279 Sec 31 SW/4 NW/4 and SW/4 T11N-R13E ADL 28282 Sec 6 W/2 and SE/4 and S/2 NE/4 and NW/4 NE/4, Sec 7 N/2 and N/2 SW/4 and SE/4 SW/4 and S E/4, Sec 8 W/2 SW/4 TIIN-R12E ADL 28260 Sec 1,2,11 W/2andNW/4NE/4, 12N/2N/2 and SE/4 NE/4 ADL 28261 Sec 3, 4 E/2 E/2, 9 NE/4 NE/4 and S/2 NE/4 and SE/4, 10 ADL 28263-1 Sec 15, 16 E/2 ADL 28263-2 Sec 21 NE/4 NW/4 and NE/4 SE/4 and NE/4, 22 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4 ADL 47451 Sec 14 W/2 and W/2 SE/4, 23 W/2 and W/2 E/2 and SE/4 SE/4 and SE/4 NE/4 ) ) Page 4 Conservation Order 484A November 30, 2005 ADL 28264 ADL 47452 Sec 26 N/2 N/2 Sec 27 NE/4 NE/4 Rule 1 Well Spacin2 (ref. CO 484) Spacing units within the Polaris Oil Pool shall be a minimum of 20 acres. The Pool shall not be opened in any well closer than 500' to an external boundary where ownership changes. Rule 2 Casin2 and Cementin2 Practices (ref. CO 484) a. In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75' TVD below the surface. b. In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500' TVD below the base of the permafrost. Rule 3 Automatic Shut-in Equipment (ref. CO 484) a. All wells must be equipped with a fail-safe automatic surface safety valve system capable of preventing an uncontrolled flow. b. All wells must be equipped with a landing nipple at a depth below permafrost, which is suitable for the future installation of a downhole flow control device. The Commission may require such installation by administrative action. c. Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the safety valve systems are in proper working condition. Rule 4 Common Production Facilities and Surface Commin2lin2 (ref. CO 484.02) Production from the Polaris Oil Pool may be commingled with production from other Prudhoe Bay Field oil pools and tract operations in surface facilities prior to custody transfer. a. All Polaris wells must use the GC-2 well allocation factor for oil, gas, and water. b. All wells must be tested a minimum of once per month. All new Polaris wells must be tested a minimum of two times per month during the first three months of production. The Commission may require more frequent or longer tests if the allocation quality deteriorates. c. Technical meetings with the Commission must be held at least yearly to review progress of the implementation of the Western Satellite Production Metering Plan. d. The Operator must submit a monthly report (in printed and electronic form) including well tests, daily-allocated production and allocation factors for the Pool. Conservation Order 484A November 30,2005 ) ) Page 5 Rule 5 Reservoir Pressure Monitorin2 (ref. CO 484) a. Prior to regular production or injection, an initial pressure survey must be taken in each well. b. A minimum of two pressure surveys shall be taken each year in the main area S/M- Pad North and the W-Pad \ Term Well-C reservoir compartments, and one reservoir pressure each year in the remaining compartments when at least one Polaris production well has been completed in the respective compartments. c. The reservoir pressure datum will be 5000' TVDss. d. Pressure surveys may be stabilized static pressure measurements at bottom-hole or extrapolated from surface (single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, or 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 Commission upon request. f. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. Rule 6 Gas-Oil Ratio Exemption (ref. CO 484) Wells producing from the Polaris Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) so long as requirements of20 AAC 25.240(b) are met. Rule 7 Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations (revised by this order CO 484A) Waterflooding is required for purposes of pressure maintenance and enriched gas injection is approved for enhanced oil recovery in strata correlative to PBU well S-200PB 1 between the measured depths of 5,603 feet and 6,012 feet (within the Schrader Bluff Formation of the Polaris Oil Pool). Production and injection operations must ensure that reservoir pressure is maintained above 1,633 psi at the datum depth of 5000 feet TVDss. Rule 8 Multiple Completion of Water Iniection Wells (ref. CO 484) a. Water inject wells may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission. b. Prior to initiation of commingled injection, the Commission must approve methods for allocation of injection to the separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. Conservation Order 484A November 30,2005 " Page 6 d. An approved injection order is required prior to commencement of injection in each pool. Rule 9 Annual Reservoir Review (revised this order CO 484A) An annual report must be filed yearly. The report must include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: a. V oidage balance by month of produced and injected fluids and cumulative status. b. Reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool. c. Results and, where appropriate, analysis of production and injection surveys, tracer surveys, observation well surveys, and any other special monitoring. d. Review of Pool production allocation factors and issues over the prior year. e. Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation studies. f. Results of monitoring to determine enriched gas injectant breakthrough to offset producers. The Operator shall schedule and conduct a yearly technical review meeting with the Commission to discuss the report contents and to review items that may require action within the coming year by the Commission. The Commission may conduct audits of technical data and analyses used in support of the surveillance conclusions and reservoir depletion plans. Rule 10 Waiver of "Application for Sundry Approval" Requirement for Workover Operations (ref. C.O. 556) a. Except as provided in (d) and (e) of this rule, the requirement to submit an Application for Sundry Approvals (Form 10-403) and supporting documentation for workover activities described in 20 AAC 25.280(a) (1), (2), (3) and (5) is waived or modified for development wells as provided in the Commission document entitled "Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules," dated July 15, 2005 (referred to below as "Sundry Matrix"). This waiver and modification does not affect the Operator's responsibility to submit a Report of Sundry Well Operations (Form 10-404) within 30 days following the completion of a workover operation. b. Except as provided in (d) and (e) of this rule, the requirement to submit an Application for Sundry Approvals (Form 10-403) and supporting documentation for workover activities described in 20 AAC 25.280(a) (1) and (5) is modified for service wells as provided in the Sundry Matrix. This modification does not affect the Operator's responsibility to submit a Report of Sundry Well Operations (Form 10- ) ) Page 7 Conservation Order 484A November 30,2005 404) within 30 days following the completion of a workover operation. c. The Sundry Matrix summarizes the sundry approval and reporting requirements that apply to various categories of operations in the specific well types under Commission regulations as modified by these rules. d. The waivers provided under (a) of this rule do not apply to wells that are required to be reported to the Commission under the provisions of Rule 11. e. The Commission reserves the discretion to require that an operator submit an Application for Sundry Approvals for a particular well or for a particular operation on any well. f. Each week the Operator shall provide the Commission with a report of workover operations performed the previous week that did not require submission of a Form 10-403. (These operations are listed in Column 2 of the Sundry Matrix.) The report must include the date, well, permit to drill number, nominal operation completed, and a brief description of that operation including depths of perforations, reperforations, and stimulated zones. g. Nothing in this rule precludes an Operator from filing an Application for Sundry Approvals (Form 10-403) in advance of any well work or from including Sundry authorized operations (listed in column 3 of the Sundry Matrix in the weekly report required by (f) of this rule. h. Unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any provision of this rule or administratively amend any provision including the Sundry Matrix, 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. Rule 11 Annular Pressures (ref. C.O. 492, C.O. 484.01) a. At the time of installation or replacement the Operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The Operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. c. The Operator shall notify the Commission within three working days after the Operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells processed through the Lisburne Processing Center and 2000 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. ) Page 8 Conservation Order 484A November 30, 2005 d. The Commission may require the Operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph 3 of this rule. The Commission may approve the Operator's proposal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The Operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. e. If the Operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the Operator shall notify the Commission within three working days and take corrective action. Unless well conditions require the Operator to take emergency corrective action before Commission approval can be obtained, the Operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The Commission may approve the Operator's proposal or may require other corrective action. The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The Operator shall give the Commission sufficient notice of the testing schedule to allow Commission to witness the tests. f. Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the Operator's notification to the Commission under (c) of this rule, unless the Commission prescribes a different limit. g. F or purposes of this rule, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casIng; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. Rule 12 Use of Multiphase Flowmeters in Well Testine (ref. C.O. 547) For purposes of satisfying well test measurement requirements of 20 AAC 25.230, the use of multi phase meters will be approved only in accordance with the provisions of the Conservation Order 484A November 30, 2005 ) ) Page 9 Commission's document, "Guidelines for Qualification of Multiphase Meters for Well Testing" dated November 30, 2004. The Commission may administratively waive a requirement of these Guidelines or administratively amend the Guidelines as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles. This rule expires on January 1, 2008. Rule 13 Administrative Action (ref. c.o. 484) Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will nQ~ result in fluid movement outside of the authorized injection zone. ~~~~ ;-~~Q~~' "'. \ ve 05. '.. / I ~ t'~~l\ Z0 ,\~ '---- hh/. . ...... .1). . '~'<:.,. . J 4!,·,,~ì.\. ~ ..\.;'",-,", ,.~<;.!,:";~, ~ : ....~~1'X~W(1i~;'~~:~~...~.I...:.,.~'.. \\~ ) ,.,..lì':~;'"1,., . 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An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). CO 484A and AIO 25A Prudhoe Bay Field Polaris Oil Pool ') ) Subject: CO 484A and AIO 25A Prudhoe Bay Field Polaris Oil Pool From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 06 Dec 2005 15 :50:06 -0900 To: unØisClqsed~(~cipielltS:;" ,,': ""/ "."..",' > " ' ".'."" 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';':',:" :: I ',:1,11';, ' ':"',:,: 'II': '".'1;' , :,: I:' ,I'" 1,1, " "", " " -::,!;:"", 1:1,:, ' : ':: , <:,!,' 1",1,,; :':':' ;::"",' " -:', "::;":1'11,;':; ,I: ,>,,':'1', ":::::,' ,,:"::: ',' " ;, ::: -<f~ed~st$ec~($sf~~¢i;~çl. us::f, rcrottx ~~çrpto/@£Þ.iin:çQl11~,j~jpp¢.s. .~ejQl1es@~ur9r~po~e.r,.c()111>~ . 4~pa' <fdap~~~1~s~å.t1~~;':Ij,~94~rick?rQ'1mìi8~(@~~ì;ll~~;..~Y~~~<~t4rtþý@~~~1 ~ti~~.~e~=t'~"J~es M., Ruud" <j~nl~~·111~'rµ~~@c8pocoR4illi p~.·~~m~ ,~tït~iv~lY6~rw:p~lf:ls~a@af·net>fj al},?jåh@4nt;·s~ate'.ak.us,>, ?uol1oje·:<buQn()jr~bp.c9~>; ¥~k~~lrY· ,~m~k~4an,l~Y@C111ad8Jko.9?tn>,loren~lÿméU1 <IQren _lem~@~oy~!state.ak. u~> ,1ulieJIRule<j~lie~h()ule@drr~:stflte~*:lJs>, John:VKatz <jw~atz@ss9.or~>,SuzagJ Hill~suzan~hill@d~~.stat~.?Lk~us>, tablerk <!ablerk~lJP.0c~Lcom>, Brady <brady@aQga.org»>,ßrian H~yelock <beh@dnr~sta~e.ak. us~,~popp. <bpopp@borough.kenaLak.us>, Jim White.<jiIl1white.@s~tx.rr..cop.>, It John S . Haw°rtl1" . <j ohn.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, gnammons <ghammons@aol.com>, rmclean<rmclean@pobox.alaska.net>, mkm 7200 <mkm 7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoi1.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>, jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@rnms.gov>, 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>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unoca1.com>, Todd Kratz <ToddKratz@chevron.com>, Gary lof2 12/6/2005 3:50 PM CO 484A and AID 25A Prudhoe Bay Field Polaris Oil Pool ') J ) R.0gers <gao/ _fo~efs~reY~1l~e..state.al$~üs>,.4rthur Çopoulos<Arthl1r _Coppulps@dnr.state.ak.us>, Ken <ken@secRrp~i~ç.~ow>~\SteveLamb~rt <sal~bert®lltlo~al.com>, J oeNicks <news(@radiokenai.com>, Jerry McCt1tche?t1<susitnahydrono\V@y~qq.co111>,Cynthia B Mciver' . <bren__mciver@admin.state.ak.us> 20f2 12/6/2005 3:50 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ) Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 ~, II David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: AN ORDER rescinding those rules within ) Docket Number: CO -10 -21 existing Conservation Orders relating to ) Other Order No. 66 well safety valve systems. ) ) Statewide, Alaska January 11, 2011 IT APPEARING THAT: 1. On October 13, 2010 the Alaska Oil and Gas Conservation Commission ( AOGCC or Commission) formally adopted new regulations relating to well safety valve systems, at 20 AAC 25.265. 2. The newly adopted well safety valve system regulations underwent final review by the Regulations Section of the Alaska Attorney General's Office and were forwarded to the Alaska Lieutenant Governor's Office on October 28, 2010. 3. The new regulations were signed by the Lieutenant Governor and took legal effect on December 3, 2010. 4. To ensure consistency with the new regulations, the AOGCC, on its own motion, proposed to rescind part or all of the outdated rules within existing Commission Orders relating to well safety valve systems. 5. On November 4, 2010, pursuant to 20 AAC 25.540, the Commission published in the Alaska Daily News notice of opportunity for public hearing on December 6, 2010. 6. The Commission received written comments in response to its public notice, and held a public hearing on December 7, 2010. 7. Oral testimony and written comments were provided at the December 7, 2010 hearing. FINDINGS: 1. Well safety valve systems are regulated under newly- adopted 20 AAC 25.265, which consolidates the requirements previously established in legacy documents, policies, and statewide guidelines relating to safety valve systems. 2. Thirty -four existing Commission Orders contain rules governing well safety valve systems. Twenty of those Orders contain broad regulatory requirements for safety valve systems that are now covered by the newly- adopted regulations. The remaining fourteen Orders include field- or pool - specific safety valve system requirements. . Other Order 66 • • Page 2 Statewide, AK January 11, 2011 3. Within existing Commission Orders are rules unrelated to well safety valve systems; these rules will continue in effect, unmodified. 4. Existing Commission Orders containing individual rules relating to well safety valve systems are enumerated in the attached Table. CONCLUSIONS: 1. Eliminating redundant requirements and standardizing wording for those field - and pool - specific safety valve system requirements deemed appropriate to retain will improve regulatory clarity. 2. Twenty existing Commission Orders that include rules relating to well safety valve systems are rendered unnecessary, and can be replaced by newly- adopted 20 AAC 25.265. As more fully set forth in the attached Table, those Orders are Conservation Orders 98A, 207A, 300, 311B, 317B, 329A, 341E, 345, 402B, 432D, 452, 457B, 471, 477, 484A, 505B, 553, 559, 570, and a Commission unnumbered Order signed March 30, 1994 (policy dictating SVS performance testing requirements). 3. Fourteen existing Commission Orders include field- or pool - specific safety valve system requirements that the Commission considers appropriate for retention. Wording for the same safety valve system requirements existing in different Commission Orders has been standardized. As more fully set forth in the attached Table, those Orders are Conservation Orders 406B, 423, 430A, 435A, 443B, 449, 456A, 458A, 562, 563, 569, 596, 597, and 605. NOW, THEREFORE, IT IS ORDERED THAT individual rules in thirty-four existing Commission Orders that relate to well safety valve systems are hereby rescinded or revised as enumerated in the Table. Remaining rules unrelated to safety valve systems within affected Commission Orders remain in effect, unmodified. DONE at Anchorage, Alaska, and dated - ary 11, 2011 ^ a Daniel T. Se. r ou , r., Commissioner, Chair • • ; • • it . • : , s Conservation Commission 1 � s .i� rman, Coer r -r, a Oi ,- , • a Conserva ion Commission TP .: c Cat y P. oerst r, Commissioner 114 "` ` Alaska it and Gas Conservation Commission Other Order 66 • ! Page 3 Statewide, AK January 11, 2011 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(6), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, January 11, 2011 4:08 PM To: Ballantine, Tab A (LAW); '(foms2 @mtaonline. net)'; '( michael .j.nelson @conocophillips.corny; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; 'caunderwood'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber'; 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; 'Marguerite kremer; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LM); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambet; 'Steve Moothat; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J ( DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @ alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.nobie @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk @alaska.gov); Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA) Subject: Other 66 Safety Valve Systems Attachments: other66. pdf Sari Ft A la4kcv Oi,Lavtdi auk Con 'vat.on'Covvun ovv (907)793 -1223 (907)276-7542 (fai) 1 • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 ■ Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Revised Rule - "Well safety valves stems' (2) Comment Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Regts from Order y systems" ( ) fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)( "In wells (excludin disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25 h arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months 25.265(h)(5) ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered b y Oooguruk Oooguruk - Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(a); 25.2659(b); 25.265(d)(1); arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or valve satisfies single check valve requirement; test every 6 months 25 readopted regulation SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(1); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Kuparuk 596 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with N/A deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Raven 570 5 yes deactivated SVS; sign on wellhead 25.265(m) tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered b y Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.26.r �(a); 25.265(b); 25.265(d)(2)(H); arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or q / 25 S CSSV satisfies the requirements of a single valve satisfies single check valve requirement; test every 6 months q n9 le check valve." readopted regulation fail -safe auto SSV and SCSSV; injection wells (except disposal) require (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25. on w Check valve requirements for injectors are not covered by Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25 h arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months 25.265(h)(5) ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered b y Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(a); 25.265(b); 25.265(d)(2)(H); arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or / 25 S CSSV satisfies the requirements of a single valve satisfies single check valve requirement; test every 6 months q n9 le check valve." readopted regulation fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Put River 559 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Deep Creek Unit Happy Valley 553 3 yes ssv or SSSV 25.265(a) N/A fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Orion 505B 3 yes prescribed by Commission 25.265(h)(5) ) 25.265 h 5 replaces SSSV nipple requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Polaris 484A 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Milne Point fail -safe auto SSV; SSSV landing nipple below per gas /MI 25.26 j require I p 25.265(a); 25.265(b); 25.265(d); N/A replaces SSSV 25.265(d) for all all wellsuire SSSV; Milne Point Unit Schrader Bluff 477 5 yes injection well re uire SSSV or injection valve below ermafrost; test 25.265(h)(5) every 6 months fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Borealis 471 3 yes injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wets fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500• Existing pool rule established a minimum setting depth for the Northstar Northstar 458A 4 no ft minimum setting depth for SSSV 25.265 ( a ), , 25.265(b); b ) . 25.265 ( d )( 1 ) " The minimum setting depth fora tubing conveyed subsurface safety valve is 500 feet." SSSV fail -safe auto SSV; SSSV landing nipple below permafrost; test every 6 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Aurora 457B 3 yes months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; gas /MI injectors require SSV and single check "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by 25.265(a); 25.265(b); 25.265(d); Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25.265(h)(5) SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; ( N/A Prudhoe Bay Unit Midnight Sun 452 6 yes flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for at wells fail -safe auto SSV and SCSSV; SSSV may be installed above or below 25.26.� ,- (a); 25.265(b); 25.265(d)(1); The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by pressure; test every 6 months 25.265(h)(5) arrangement." readopted regulation . fail -safe auto SSV and SCSSV (producers and gas injectors); water "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Alpine 443B 5 no injection wells require (1) double check valve, or (ii) single check valve 25.265(a); 25.265(b); 25.265(d)(2)(H) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or and SSV SCSSV satisfies the requirements of a single check valve." readopted regulation fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25.265(h)(5) SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Requirement to maintain a wellhead sign and list of wells with deactivated; maintain list of wells w /deactivated SVS; test as 25.265(x); 25.265(b); 25.265(h)(5); deactivated SVS was replaced with requirement to maintain a Kuparuk River Unit; N/A tag on well when not manned; administrative approval CO Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP P Milne Point Unit may be defeated on W. Sak injectors w/surface pressure <500psi wl 25.265(m) 432D.009 remains effective [re:defeating the LPS when surface notice when defeated and placed back in service injection pressure for West Sak water injector is <500psil Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Unit/Field Pool Conservation Rule Rescind Rule? Existing Order Requirement New Regulation Provisions Order (1) g q Addressing Reqts from Order Revised Rule - "Well safety valve systems" (2) Comment fail -safe auto SSV; gas /MI injectors require SSV and single check "I wells (excluding disposal injectors) m ust be equipped with(i) requirements / y 25.265(a); 25.265(b); 25.265(d); pil th(i) a double check valve Check valve re uirements for injectors are rmt covered b Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." q 9 SSSV requirement for MI injectors Milne Point - double check valve; test ect Sag fail -safe auto SSV; injection ion wells require Check valve requirements for injectors are not covered by Milne Point Unit River 423 7 n o every 6 months 25.265(x); 25.265(b); 25.265(h)(5) "Injection wells must be equipped with a double check valve arrangement." readopted regulation fail -safe auto SSV; gas /MI injectors require SSV and single check nipple; water injection wells require i double 1 (excluding disposal injectors) equipped with(i) Check valve requirements for injectors are not covered by valve and SSSV landing pP 1 q ( Injection wells excludin dis osal injectors must be a ui ed with i a double check valve readopted readopted re 9 P led 25.265 d 5 does not include Kuparuk River Unit Kuparuk - West Sak 406E 6 no check valve, or (ii) single check valve and SSV; test every 6 months; 25.265(a); 25.265(b); 25.265(d); arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or ()( ) CO 4068.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be SSSV requirement for MI injectors; administrative approval CO injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi." 40613.001 remains effective [re:defeating the LPS when surface placed back in service injection pressure for West Sak water injector is <500psij fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 402B 6 yes control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A submit test results electronically within 14days; SVS defeated /removed 25.265(m) only if well SI or pad continuously manned fail -safe auto SSV (SID well and artificial lift); sign on well if SVS 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265 m N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission ( ) tag on well when not manned fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must Prudhoe Bay Unit Prudhoe 341E 5 yes be maintained and tested as part of SVS; sign on well if SV 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells prescribed by Commission - Prudhoe Bay Unit Niakuk 329A 5 yes fail -safe auto SSV and SCSSV; maintain list of wells w/ removed o 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit Pt. McIntyre 3178 8 yes fail -safe auto SSV and SCSSV; SSSV may be rermoved as part of 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; routine well ops w/o notice 25.265(j); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit West Beach 311 B 6 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork West Fork (Sterling West 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A Prudhoe Bay Unit Lisburne 207A 7 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with w /deactivated SVS; test as prescribed by Commission 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a tag on well when not manned Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 yes suitable automatic safety valve installed below base of permafrost t Readopted 25.265(d) dictates which wells require SSSV; y prevent uncontrolled flow 25.265(d) N/A replaces SSSV nipple requirement for all wells Statewide N/A N/A N/A yes Commission policy dictating SVS performance testing AOGCC Policy - SVS Failures; issued by order of the y requirements 25.265(h); 25.265(n); 25.265(o) N/A Commission 3/30/1994 (signed by Commission Chairman Dave Johnson) Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded Page 2 of 2 • • Public Hearing Record And Backup Information available in Other 66 . ~V~VŒ lID~ ~~~~[{~ . AI/ASHA OIL AlQ) GAS CONSERVATION COMMISSION 333 W. 7th AVENUE,SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 484A.OOl SARAH PALIN, GOVERNOR Mr. Frank Paskvan GPB West Resource Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Paskvan: The Alaska Oil and Gas Conservation Commission ("Commission") is amending the reporting dates of Rule 9 Annual Reservoir Review of Conservation Order 484A - Prudhoe Bay Field, Polaris Oil Pool. The change is necessary so that the rule is not contradictory to the schedule agreed upon by the Commission and BP Exploration (Alaska) Inc. Rule 9 Annual Reservoir Review is amended to read as follows (additions are in bold and [deletions are bracketed]): Rule 9 Annual Reservoir Review An annual report must be filed yearly on a schedule agreed upon by the Commission and the operator. The report must include future development plans, reservoir depletion plans, and surveillance information for the period agreed upon by the Commission and the operator[prior calendar year], including: a. V oidage balance by month of produced and injected fluids and cumulative status. b. Reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool. c. Results and, where appropriate, analysis of production and injection surveys, tracer surveys, observation well surveys, and any other special monitoring. d. Review of Pool production allocation factors and issues over the prior year. e. Progress of enhanced recovery project implementation and reservOIr management summary including results of reservoir simulation studies. CO 484A.00 1 May 23,2007 Page 2 of2 . . e. Progress of enhanced recovery project implementation and reserVOIr management summary including results of reservoir simulation studies. f. Results of monitoring to determine enriched gas injectant breakthrough to offset producers. The Operator shall schedule and conduct a yearly technical review meeting with the Commission to discuss the report contents and to review items that may require action within the coming year by the Commission. The Commission may conduct audits of technical data and analyses used in support of the surveillance conclusions and reservoir depletion plans. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. rage, Alaska and dated May 23,2007. ~ ¡J Daniel T. Seamount, Jr. Commissioner Various Administrative Approvals for North S. . Subject: Various Administrative Approvals for North Slope From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Thu, 24 May 2007 06:39:39 -0800 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>, tnnjrl <tnnjrl@aol. jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.co , Mark D <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnell nocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjn <mjnels urvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skil <Skille BP.com>, "Deborah 1. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.c , Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <Po isG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel. Schultz .com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com> , doug_schultze <doug_ schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <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>, jej ones <jejones@aurorapower.com>, dapa <dapa@alaska.net>" eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <bl@mapalaska.com>, jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, Julie Houle <julie_houle@dnr.state.ak.us>, John W z <jwkatz@alaskadc.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havel h@dnr.state.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exx . .com>, marty <marty@rkindustrial.com>, ghammons <gharnmons@aol.com>, nnclean <nnclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <todd.durkee@anadarko.com>, Gary Schultz <gary _ schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, James Scherr <james.scherr@mms.gov>, 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>" Gary Rogers <gary Jogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <klyons@otsintl.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <carnmy_taylor@dnr.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoil.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg 1 of3 5/24/2007 6:40 AM Various Administrative Approvals for North S. . <jimJegg@admin.state.ak.us>, Catherine P Foerster <cathy_foerster@admin.state.ak.us>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <laura _ silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobil.com>, akpratts@ aska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve_moothart nr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>" Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple_davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegarner <jimwinegarner@brooksrangepetro.com>, Matt Rader <mattJader@dnr.state.ak.us>, carol smyth <carol.smyth@shell.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoil.com>, foms@mtaonline.net, Rudy Brueggeman <ru eggemann@international.gc.ca>, Cary Carrigan <cary@kfqd.com>, Sonja Frankllin <sfr . bloomberg.net>, Mike Bill <Michael.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, "Alan Birnbaum <\"\"Alan J Birnbaum \">" <alan _ birnbaum \"@law.state.ak.us>, Randall Kanady <Randall.B.Kanady@conocophillips.com>, MJ Loveland <NI878@conocophillips.com>, Dave Roby <daveJoby@admin.state.ak.us>, James B Regg <jim _regg@admin.state.ak.us> Jody Colombie <jody colombie~admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf AI04E-22.pdf Content-Encoding: base64 Content-Type: C0311B-002.pdf Content-Encodi application/pdf base64 Content-Type: applicati C0570-002.pdf . Content-Encodmg: base64 Content-Type: application/pdf I C0471-006.pdf Content-Encoding: base64 Content-Type: application/pdf C0484A-001.pdf . Content-Encodmg: base64 20f3 5/24/2007 6:40 AM Various Administrative Approvals for North S. . Content- Type: application/pdf C0457B-002. pdf Content-Encoding: base64 Content- Type: application/pdf C0317B-002. pdf Content-Encoding: base64 30f3 5/24/2007 6:40 AM Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, W A 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 '\e~ \01 ~~\~\fJ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF BP ) Docket Number: CO 14-007 EXPLORATION (ALASKA), INC. ) Conservation Order 484A.002 for Administrative Approval revising ) the reservoir pressure monitoring ) Prudhoe Bay Unit requirements for the S/M-Pad North ) Prudhoe Bay Field wells reservoir compartment. ) Polaris Oil Pool April 15, 2014 By letter dated April 1, 2014, and received April 2, 2014, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to modify the reservoir pressure monitoring requirements for the S/M-Pad North reservoir compartment to reduce the requirement to conduct two static bottomhole pressure surveys per year in this area to one due to a lack of production from the area during the previous reporting period. In accordance with Rule 13 of Conservation Order (CO) 484A, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to modify the reservoir pressure survey requirements for the S/M-Pad North reservoir compartment. BPXA has completed two producers, PBU S-200 (PTD 197-239) and PBU S-201 (PTD 200-184) in the subject reservoir compartment. The PBU S-200 Well has not produced since March 2011, and the PBU S-201 Well has not produced since November 2012. With no production occurring from this reservoir compartment conducting multiple reservoir pressure surveys in the area each year provides no additional benefit for reservoir management purposes. AOGCC's approval to conduct a single static bottomhole pressure survey in the S/M-Pad North reservoir compartment of the Polaris Oil Pool is conditioned upon the following: 1. A minimum of one static bottomhole pressure survey shall be conducted in this reservoir compartment each year; and 2. If production or injection activity resumes in the S/M-Pad North reservoir compartment the operator shall resume collecting a minimum of two static bottomhole pressure surveys in this reservoir compartment. DONE at Anchorage, Alaska and dated April 15, 2014. Cathy P. Foerster Chair, Commissioner Daniel T. Seamount, Jr. Commissioner CO 484A.002 • • April 15, 2014 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Wednesday, April 16, 201410:02 AM To: (michael j.nelson@conocophillips.com); AKDCWellIntegrityCoordinator, Alexander Bridge; Andrew Vandedack, Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Schultz, gary (DNR sponsored); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz, Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty, Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger, trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net, Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jilt.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Pollet, Jolie; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Woolf, Wendy C (DNR); William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, lames B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Turkington, Jeff A (DOA); To: Ace, Chris D (DOA) 0 Subject: Conservation Order 484A.002 Prudhoe Bay Unit Attachments: co484a.002.pdf Samantha CardsCe Executive Secretary 11 .Alaska Oi(and Gas Conservation Commission 333 'Nest 711 .Avenue, Suite ioo .Anchorage, .AX 99501 6907) 793-1223 (yhone) (907) 276-7542 (fax) CONFIDENTIALM 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@Alaska.Gov. • Or. Werner Schinagl Base Management Team Leader West End BP Exploration (Alaska), Inc. Post Office Box 196612 Anchorage, AK 99519-6612 E Penny Vadla George Vaught, Jr. Jerry Hodgden O 399 W. Riverview Ave. Post Office Box 13557 40818 081Golden, 8t n St. Company Soldotna, AK 99669-7714 Denver, CO 80201-3557 Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 Darwin Waldsmith James Gibbs Post Office Box 39309 Post Office Box 1597 j Ninilchik, AK 99639 Soldotna, AK 99669 .C�,p q/' • THE STATE °fALAS -KA GOVERNOR BILL WALKER Alaska Gil and Gas Canservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 50513.001 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 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: CO-15-013 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 34117; - 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 484A1; - 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 341F, 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 341F 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 457B, Rule 4(g) of CO 471, Rule 7(d) of CO 452, Rule 4(f) 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 341 F, 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 50513, 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 329B.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 Cathy . Foerster Daniel T. Se ount, Jr. 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 K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 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, P.O. Box 60868 P.O. Box 39309 Alaska Reservoir Development Fairbanks, AK 99706 Ninilchik, AK 99639 BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 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.pa lad ijczu k@a laska.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.waIlace@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 (pa u Lclecker@ al aska.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 J (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-mail message, including any attachments, contains information .fr mi the.ilaska Oiland Gas Conservation Conunission (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 disclosrire: 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 AOCCC is aware of the mistake in sending; it to vou, contact Samaultha Carlisle at (907) , 93-1223 or Samantha.Carlisle alaska.�ay. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Ms. Katrina Garner Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 452.004 CONSERVATION ORDER NO. 45711.006 CONSERVATION ORDER NO. 471.009 CONSERVATION ORDER NO. 484A.004 CONSERVATION ORDER NO. 505B.002 West Area Manager Alaska Reservoir Development BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -18-035 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 ww W . a ogcc.olaska.gov Request for Administrative Approval for Conforming Prudhoe Bay Unit (PBU) Satellite Pool Rules for Consistency Prudhoe Bay Unit Midnight Sun Oil Pool — Conservation Order (CO) No. 452 Aurora Oil Pool — CO 457B Borealis Oil Pool — CO 471 Polaris Oil Pool — CO 484A Schrader Bluff Oil Pool — CO 505B Dear Ms. Garner: By letter dated October 23, 2018, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to amend the pool rules in the above referenced orders in order to bring conformity and consistency to the well testing requirements and pressure survey requirements of these satellite pools in the PBU to improve efficiency of field management for the operator and compliance oversight for the Alaska Oil and Gas Conservation Commission (AOGCC). Initial Well Testing Requirement: BPXA requests that the requirement to conduct at least two well tests per month during the first three months of production from a new well be eliminated to make the testing requirements for these satellites consistent with those in place for the Prudhoe Oil Pool. All of these satellite pools are well established developments and the need for increased well testing in the early stages of a well's production no longer exists. Additionally, making well testing requirements consistent for these satellite pools and the POP will promote operation efficiencies on the numerous drill sites in the PBU that produce from more than one pool. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 AIO 2C.067 May 29, 2019 Page 2 of 7 Pressure Survey Requirements: Existing pool rules for the Aurora, Borealis, Orion, and Polaris Oil Pools require an initial pressure survey to be taken in each new wellbore before regular production commences from the well. Reliable estimates of the reservoir pressure can be obtained from the pore pressure survey fluid gradient study conducted prior to drilling a new wellbore and from reservoir response during actual drilling operations. Additionally, after so many years of development the pools in the PBU are well understood and have sophisticated reservoir models that make the arbitrary collection of pressure survey data on new wellbores unnecessary for proper development of the pools. A uniform approach to reservoir pressure monitoring provides more useful information than the arbitrary collection of pressure data in new wellbores that may be in portions of the pool where additional pressure data is not necessary for proper reservoir management. The pool rules for the Aurora and Orion Oil Pools relate the number of required pressure surveys to the number of governmental sections in the pool. Pool rules for the other satellite pools, which are completed in the same formations as the Aurora and Orion Oil Pools do not have this requirement. The age and geologic characteristics of the Aurora and Orion Pools makes reservoir pressure survey requirements based on governmental sections unnecessary to properly manage these pools. Developing a pressure survey program based on the representative areas (areas defined by major faulting) would provide uniform pressure survey data requirements that ensure that pressure survey data more accurately represent the actual reservoir pressure across the pool. Extrapolation of bottomhole pressure from the surface pressure of a well on water injection provides accurate results for the reservoir pressure. Requiring BPXA to submit a proposed reservoir pressure survey program for each pool each year as part of its annual surveillance report will provide AOGCC sufficient information to review and request changes if AOGCC determines they are necessary. At the minimum, AOGCC will collect at least one pressure survey per active representative area sufficient to ensure that an adequate reservoir pressure survey program is conducted in these pools. Changing the requirement to report reservoir pressure survey results for the Aurora Oil Pool from quarterly to yearly will bring Aurora's reporting requirements in conformance with the rest of the field. The pool rules for all the affected pools have an administrative approval clause that allows the AOGCC to administratively amend the rules as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. The AOGCC finds that these conditions are met and that the orders may be administratively amended. Now therefore it is ordered That the subject conservation orders are amended as shown below. Midnight Sun Oil Pool — Conservation Order No. 452 COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 AIO 2C.067 May 29, 2019 Page 3 of 7 Rule 7 Common Production Facilities and Surface Commingling a. Production from the Midnight Sun Oil Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 and detailed within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan — Policies and Procedures Document' dated August 1, 2002 is approved for allocation of production from Midnight Sun Wells. C. All Midnight Sun wells must use the Gathering Center 1 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. 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 8 Reservoir Pressure Monitoring a. A minimum of one bottom -hole pressure survey shall be measured annually for the Midnight Sun Oil Pool. b. The reservoir pressure datum must be 8,050 feet true vertical depth subsea. C. Transient pressure surveys obtained by a shut-in build up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressure from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from pressure surveys shall be reported annually on Form 10- 412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitter with the Form 10-412 but must be available to the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (d.) of this rule. Aurora Oil Pool — Conservation Order No. 457B Rule 4.Common Production Facilities and Surface Comminelin¢ (AA 457.02.9/11/03) a. The PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 effective August 1, 2002 governs satellite production within the Western Operating Area of the Prudhoe Bay Unit, including the Aurora Oil Pool. b. The Prudhoe Bay Unit Gathering Center 2 well allocation factor for oil, gas, and water COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 4 of 7 shall be applied to adjust total Aurora Oil Pool production. c. All wells must be tested a minimum of once per month. The Commission may require more frequent or longer tests if the allocation quality deteriorates. d. Technical process review meetings with the Commission shall be held at least annually. Rule 5. Reservoir Pressure Monitoring (C0457, 9/7M a. An annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Aurora Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Aurora Oil Pool. The minimum number of bottom -hole pressure surveys performed each year shall equal the number of Representative Areas (West of Crest, North of Crest, South East of Crest, Crest Area, and South of Crest as depicted on Map 1 of the October 23, 2018, application) within the AOP that contain active wells. b. The reservoir pressure datum will be 6,700 feet tvdss. c. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi -rate test, an interference test, drill stem tests, and open -hole formation tests are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from all relevant reservoir pressure surveys must be reported to the AOGCC annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but shall be available for inspection by the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph d of this Rule. Borealis Oil Pool — Conservation Order No. 471 Rule 4 Common Production Facilities and Surface Commingling a. Production from the Borealis Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 is conditionally approved for one year beginning August 1, 2002. c. As of August 1, 2002, all Borealis wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. Until August 1, 2002, the Borealis Oil Pool allocation factor shall be 1.0. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 5 of 7 d. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. A metering and allocation procedures document shall be submitted to the AOGCC by August 1, 2002. A draft copy of the procedures shall be provided to AOGCC staff for technical review by July 8, 2002. f Technical process review meetings shall be held quarterly to review progress of the implementation of the plan. g. Commission approval of the Prudhoe Bay Unit Western Operating Metering Plan will expire on August 31, 2003. Continued authorization of metering and allocation procedures will be determined at a hearing to be scheduled no later than July 31, 2003. Rule 5 Reservoir Pressure Monitorine a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Borealis Oil Pool Reservoir Surveillance Report by September 15 each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the BOP. The minimum number of bottom -hole pressure surveys performed each year shall equal the number of Representative Areas (North L -Pad, SW L -Pad, East V -Pad, North V -Pad, South V -Pad, and Z -Pad as depicted on Map 1 of the October 23, 2018, application) within the BOP that contain active wells. b. The reservoir pressure datum will be 6600' TVD sub -sea. c. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. 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. e. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Polaris Oil Pool — Conservation Order No. 484A Rule 4 Common Production Facilities and Surface Commineline Production from the Polaris Oil Pool may be commingled with production from other Prudhoe Bay Field oil pools and tract operations in surface facilities prior to custody transfer. a. All Polaris wells must use the GC -2 well allocation factor for oil, gas, and water. b. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. c. Technical meetings with the AOGCC must be held at least yearly to review progress of the implementation of the Western Satellite Production Metering Plan. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 6 of 7 d. 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 5 Reservoir Pressure Monitoring (ref. CO 484) a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Polaris Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15, of that year. These surveys are needed to effectively monitor reservoir pressure within the Polaris Oil Pool. The minimum number of pressure surveys performed each year shall equal the number of Representative Areas (S Pad N, S Pad S, W Pad N, and W Pad S as depicted on Map 2 of the October 23, 2018, application) that contain active wells. b. The reservoir pressure datum will be 5000' TVDss. c. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall- off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. 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. e. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Schrader Bluff Oil Pool — Conservation Order No. 505B Rule 4: Common Production Facilities and Surface Commingling a. Production from the Schrader Bluff Oil Pool may be commingled with production from Prudhoe Bay Oil Pool, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described by letter from BPXA dated April 23, 2002 and detailed within the PBU Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Schrader Bluff Oil Pool wells. c. All Schrader Bluff Oil Pool wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. Technical process review meetings shall be held at least annually. _Rule 5: Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Schrader Bluff Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 AIO 2C.067 May 29, 2019 Page 7 of 7 by October 15, of that year. These surveys are needed to effectively monitor reservoir pressure within the SBOP. The minimum number of pressure surveys performed each year shall equal the number of Representative Areas (currently active — 1, IA, 2, 2A, and 5S, currently inactive— 6N, 6S, 9, 8, 4, 5N, 3A, 3N, and 3S as depicted on Map 2 of the October 23, 2018, application) within the SBOP that contain active wells. The reservoir pressure datum will be 4400' TVDss. b. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom - hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. c. 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 Commission upon request. d. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (c) of this rule. DONE at Anchorage, Alaska and dated May 29, 2019. Daniel T. Seamount, Jr. Commissioner J ie L. Chmielowski mmissioner AND APPEAL 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 ran 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. TI Ili STATI ,,ALA S_ K_A GO%TiRNOR MICH.iE1, I DUNLIJA-Y Ms. Katrina Garner Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 452.004 CONSERVATION ORDER NO. 457B.006 CONSERVATION ORDER NO. 471.009 CONSERVATION ORDER NO. 484A.004 CONSERVATION ORDER NO. 50513.002 West Area Manager Alaska Reservoir Development BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -18-035 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaska.gov Request for Administrative Approval for Conforming Prudhoe Bay Unit (PBU) Satellite Pool Rules for Consistency Prudhoe Bay Unit Midnight Sun Oil Pool — Conservation Order (CO) No. 452 Aurora Oil Pool — CO 457B Borealis Oil Pool — CO 471 Polaris Oil Pool — CO 484A Schrader Bluff Oil Pool — CO 505B Dear Ms. Garner: By letter dated October 23, 2018, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to amend the pool rules in the above referenced orders in order to bring conformity and consistency to the well testing requirements and pressure survey requirements of these satellite pools in the PBU to improve efficiency of field management for the operator and compliance oversight for the Alaska Oil and Gas Conservation Commission (AOGCC). Initial Well Testing Requirement: BPXA requests that the requirement to conduct at least two well tests per month during the first three months of production from a new well be eliminated to make the testing requirements for these satellites consistent with those in place for the Prudhoe Oil Pool. All of these satellite pools are well established developments and the need for increased well testing in the early stages of a well's production no longer exists. Additionally, making well testing requirements consistent for these satellite pools and the POP will promote operation efficiencies on the numerous drill sites in the PBU that produce from more than one pool. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 2 of 7 Pressure Survey Requirements: Existing pool rules for the Aurora, Borealis, Orion, and Polaris Oil Pools require an initial pressure survey to be taken in each new wellbore before regular production commences from the well. Reliable estimates of the reservoir pressure can be obtained from the pore pressure survey fluid gradient study conducted prior to drilling a new wellbore and from reservoir response during actual drilling operations. Additionally, after so many years of development the pools in the PBU are well understood and have sophisticated reservoir models that make the arbitrary collection of pressure survey data on new wellbores unnecessary for proper development of the pools. A uniform approach to reservoir pressure monitoring provides more useful information than the arbitrary collection of pressure data in new wellbores that may be in portions of the pool where additional pressure data is not necessary for proper reservoir management. The pool rules for the Aurora and Orion Oil Pools relate the number of required pressure surveys to the number of governmental sections in the pool. Pool rules for the other satellite pools, which are completed in the same formations as the Aurora and Orion Oil Pools do not have this requirement. The age and geologic characteristics of the Aurora and Orion Pools makes reservoir pressure survey requirements based on governmental sections unnecessary to properly manage these pools. Developing a pressure survey program based on the representative areas (areas defined by major faulting) would provide uniform pressure survey data requirements that ensure that pressure survey data more accurately represent the actual reservoir pressure across the pool. Extrapolation of bottomhole pressure from the surface pressure of a well on water injection provides accurate results for the reservoir pressure. Requiring BPXA to submit a proposed reservoir pressure survey program for each pool each year as part of its annual surveillance report will provide AOGCC sufficient information to review and request changes if AOGCC determines they are necessary. At the minimum, AOGCC will collect at least one pressure survey per active representative area sufficient to ensure that an adequate reservoir pressure survey program is conducted in these pools. Changing the requirement to report reservoir pressure survey results for the Aurora Oil Pool from quarterly to yearly will bring Aurora's reporting requirements in conformance with the rest of the field. The pool rules for all the affected pools have an administrative approval clause that allows the AOGCC to administratively amend the rules as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. The AOGCC finds that these conditions are met and that the orders may be administratively amended. Now therefore it is ordered That the subject conservation orders are amended as shown below. Midnight Sun Oil Pool — Conservation Order No. 452 COs 452.004, 4576.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 3 of 7 Rule 7 Common Production Facilities and Surface Commingling a. Production from the Midnight Sun Oil Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 and detailed within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Midnight Sun Wells. C. All Midnight Sun wells must use the Gathering Center 1 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. 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 8 Reservoir Pressure Monitoring a. A minimum of one bottom -hole pressure survey shall be measured annually for the Midnight Sun Oil Pool. b. The reservoir pressure datum must be 8,050 feet true vertical depth subsea. C. Transient pressure surveys obtained by a shut-in build up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressure from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from pressure surveys shall be reported annually on Form 10- 412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitter with the Form 10-412 but must be available to the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (d.) of this rule. Aurora Oil Pool — Conservation Order No. 457B Rule 4.Common Production Facilities and Surface Commineline (AA 457.02, 9/11/03) a. The PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 effective August 1, 2002 governs satellite production within the Western Operating Area of the Prudhoe Bay Unit, including the Aurora Oil Pool. b. The Prudhoe Bay Unit Gathering Center 2 well allocation factor for oil, gas, and water COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 4 of 7 shall be applied to adjust total Aurora Oil Pool production. c. All wells must be tested a minimum of once per month. The Commission may require more frequent or longer tests if the allocation quality deteriorates. d. Technical process review meetings with the Commission shall be held at least annually. Rule 5. Reservoir Pressure Monitoring (C0457 9/7/01) a. An annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Aurora Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Aurora Oil Pool. The minimum number of bottom -hole pressure surveys performed each year shall equal the number of Representative Areas (West of Crest, North of Crest, South East of Crest, Crest Area, and South of Crest as depicted on Map 1 of the October 23, 2018, application) within the AOP that contain active wells. b. The reservoir pressure datum will be 6,700 feet tvdss. c. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi -rate test, an interference test, drill stem tests, and open -hole formation tests are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from all relevant reservoir pressure surveys must be reported to the AOGCC annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but shall be available for inspection by the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph d of this Rule. Borealis Oil Pool — Conservation Order No. 471 Rule 4 Common Production Facilities and Surface Commingling a. Production from the Borealis Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 is conditionally approved for one year beginning August 1, 2002. c. As of August 1, 2002, all Borealis wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. Until August 1, 2002, the Borealis Oil Pool allocation factor shall be 1.0. COs 452.004, 457B.006, 471.009,484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 5 of 7 d. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. A metering and allocation procedures document shall be submitted to the AOGCC by August 1, 2002. A draft copy of the procedures shall be provided to AOGCC staff for technical review by July 8, 2002. f. Technical process review meetings shall be held quarterly to review progress of the implementation of the plan. g. Commission approval of the Prudhoe Bay Unit Western Operating Metering Plan will expire on August 31, 2003. Continued authorization of metering and allocation procedures will be determined at a hearing to be scheduled no later than July 31, 2003. Rule 5 Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Borealis Oil Pool Reservoir Surveillance Report by September 15 each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the BOP. The minimum number of bottom -hole pressure surveys performed each year shall equal the number of Representative Areas (North L -Pad, SW L -Pad, East V -Pad, North V -Pad, South V -Pad, and Z -Pad as depicted on Map 1 of the October 23, 2018, application) within the BOP that contain active wells. b. The reservoir pressure datum will be 6600' TVD sub -sea. c. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. 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. e. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Polaris Oil Pool — Conservation Order No. 484A Rule 4 Common Production Facilities and Surface Commingling Production from the Polaris Oil Pool may be commingled with production from other Prudhoe Bay Field oil pools and tract operations in surface facilities prior to custody transfer. a. All Polaris wells must use the GC -2 well allocation factor for oil, gas, and water. b. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. c. Technical meetings with the AOGCC must be held at least yearly to review progress of the implementation of the Western Satellite Production Metering Plan. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 6 of 7 d. 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 5 Reservoir Pressure Monitoring (ref. CO 484) a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Polaris Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15, of that year. These surveys are needed to effectively monitor reservoir pressure within the Polaris Oil Pool. The minimum number of pressure surveys performed each year shall equal the number of Representative Areas (S Pad N, S Pad S, W Pad N, and W Pad S as depicted on Map 2 of the October 23, 2018, application) that contain active wells. b. The reservoir pressure datum will be 5000' TVDss. c. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall- off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. 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. e. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Schrader Bluff Oil Pool — Conservation Order No. 505B Rule 4: Common Production Facilities and Surface Commin ling a. Production from the Schrader Bluff Oil Pool may be commingled with production from Prudhoe Bay Oil Pool, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described by letter from BPXA dated April 23, 2002 and detailed within the PBU Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Schrader Bluff Oil Pool wells. c. All Schrader Bluff Oil Pool wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. Technical process review meetings shall be held at least annually. Rule 5: Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Schrader Bluff Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 AIO 2C.067 May 29, 2019 Page 7 of 7 by October 15, of that year. These surveys are needed to effectively monitor reservoir pressure within the SBOP. The minimum number of pressure surveys performed each year shall equal the number of Representative Areas (currently active — 1, ]A, 2, 2A, and 5S, currently inactive -6N, 6S, 9, 8, 4, 5N, 3A, 3N, and 3S as depicted on Map 2 of the October 23, 2018, application) within the SBOP that contain active wells. The reservoir pressure datum will be 4400' TVDss. b. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom - hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. c. 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 Commission upon request. d. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (c) of this rule. DONE at Anchorage, Alaska and dated May 29, 2019. //signature on file// Daniel T. Seamount, Jr Commissioner //signature on file// Jessie L. Chmielowski Commissioner 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. Bernie Karl K&K Recycling Inc. 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. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 1'HE STATE °fALASKA GOVERNOR Ivi1KL• DUNLFAVY Mr. Oliver Sternicki Alaska Gil and Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 83A.001 CONSERVATION ORDER NO. 207D.002 CONSERVATION ORDER NO. 311B.004 CONSERVATION ORDER NO. 317B.004 CONSERVATION ORDER NO. 329A.002 CONSERVATION ORDER NO. 3411.002 CONSERVATION ORDER NO. 345.003 CONSERVATION ORDER NO. 452.005 CONSERVATION ORDER NO. 457B.007 CONSERVATION ORDER NO. 471.010 CONSERVATION ORDER NO. 484A.005 CONSERVATION ORDER NO. 505B.003 CONSERVATION ORDER NO. 559A.002 CONSERVATION ORDER NO. 570.011 Well Integrity Engineer Hilcorp North Slope LLC P. O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Numbers: CO -20-004 and CO -20-008 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Request to amend normal operating limit for inner annulus pressure for non Lisburne development area wells from 2,000 psig to 2,100 psig and to add an administrative approval clause to Conservation Order No. 492 Prudhoe Bay Unit All Oil Pools Dear Mr. Stemicki: By application dated February 24, 2020, Hilcorp North Slope, LLC' (HNS) applied to modify Conservation Order No. 492 (CO 492) to raise the inner annulus (1A) normal operating limit (NOL) reporting threshold from 2,000 psig to 2,100 psig for all wells not processed through the Lisburne Processing Center (LPC)'. CO 492 was issued on June 26, 2003 and applied to all pools in the I The February 24, 2020, application was submitted by BP Exploration (Alaska) Inc. (BPXA) as operator of the Prudhoe Bay Unit (PBU) but effective on July 1, 2020, BPXA came under new ownership and was renamed HNS. HNS is currently the operator of the PBU. z The IA NOL for wells processed through the LPC is currently set at 2,500 psig. HNS is not seeking to modify this at this time. COs 83A.001, 207D.002,31 I B.004,317B.003, 329A.002,3411.002,345.003, 452.005, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 2 of 4 Prudhoe Bay Unit (PBU). The order established rules for dealing with sustained casing pressure for all producers in the PBU. Some, but not all, of the pools in the PBU area have incorporated the rules found in CO 492 directly into its pool rules. CO 492 itself did not contain provisions to allow it the be administratively amended, so providing public notice and opportunity to comment was required in order to amend the order. As such CO 492 will be amended separately and this letter will amend the individual pool rules for the PBU area oil pools. Due to operational changes over time in the PBU, namely increases in the gas lift header pressures, the 2,000 psig NOL for the IA that requires notification to the Alaska Oil and Gas Conservation Commission (AOGCC) when it is exceeded is triggering numerous notifications. These notifications do not on their own require any corrective action to be taken, but simply are a reporting burden on the operator and the AOGCC. Increasing the NOL from 2,000 to 2,100 would decrease the frequency of these notifications. Currently, the NOL for the IA for wells processed through the LPC is 2,500 psig. Exceeding the 2,500 psig NOL triggers a reporting requirement, but does not, standing alone, require corrective action. Another limit that is currently in place, and is not being changed by this action, is a pressure limitation of 45% of the casing's burst pressure rating. Exceeding the 45% pressure limitation requires that corrective action to be taken. Increasing the reporting threshold from 2,000 psig to 2,100 psig for the wells that are not processed at the LPC will eliminate many unnecessary notifications for wells where notification was triggered by the gas lift system pressure instead of an actual problem with the well that might indicate loss of containment. Increasing the IA NOL from 2,000 prig to 2,100 prig for production wells that are not processed at the LPC is based on sound engineering and geoscience principles. Now therefore it is ordered that the text below shall replace the text in the specified rules in the following orders: Conservation Order Oil Pool Rules being replaced 207D Lisburne 15 457B Aurora 11 and 123 484A Polaris 11 505B Schrader Bluff 11 559A Put River 10 570 Raven 12 3 In the current CO 457B, the pool rules for the Aurora Oil Pool, Rule I 1 contains paragraphs a. through f. of the annular pressure rules and Rule 12 contains the definitions in paragraph g. of the annular pressure rules. Paragraph g. is a part of the revised Annular Pressure of Production Wells shown here and thus Rule 12 in CO 457B is being eliminated. COs 83A.001, 207D.002, 311B.004, 317B.003, 329A.002, 3411.002, 345.003, 452.005, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 3 of 4 And be added as the new rule indicated in the following orders: Conservation Order Oil Pool Added rule 83A Kuparuk River 9 31113 West Beach 14 317B Pt McIntyre and Stump Island 17 329A Niakuk 13 341I Prudhoe Oil Pool 22 345 North Prudhoe Bay 12 452 Midnight Sun 15 471 Borealis 11 Annular Pressure of Production Wells a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each production well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. c. The operator shall notify the Commission within three working days after the operator identifies a well as having (1) sustained inner annulus pressure that exceeds 2500 psig for wells processed through the Lisburne Processing Center and 2100 psig for all other production wells, or (2) sustained outer annulus pressure that exceeds 1000 psig. d. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any production well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The operator shall give the Commission notice consistent with the requirements of Industry Guidance Bulleting 10-01 A of the testing schedule to allow the Commission to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a production well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10- 403) a proposal for corrective action. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. COs 83A.001,207D.002,311B.004,317B.003,329A.002,3411.002,345.003,452.005,45713.006,471.009, 484A.005, 50513.003, 559A.002, & 570.011 October 1, 2020 Page 4 of 4 Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1000 prig. However, a well that is subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under (c) of this rule, unless the Commission prescribes a different limit. g. For purposes of this rule, 1. "inner annulus" means the space in a well between tubing and production casing; 2. "outer annulus" means the space in a well between production casing and surface casing; 3. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) is not pressure that has been applied intentionally. DONE at Anchorage, Alaska and dated October 1, 2020. Jeremy Digitaalll ssigned by Date: 2020.1001 M. Price 13:5906 LW;0 Jeremy M. Price Chair, Commissioner Daniel T. Digitally signed by Daniel. Seamount Jr, Seamount, Jr. Data 202010.01 12moaa,,;o Daniel T. Seamount, Jr Commissioner Jessie L. Digitally signed by Jessie L. Chmielowski Chmielowski Date: 2020.10 D1 12:12:07-0e'00' Jessie L. Chmielowski Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is 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 atter 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. Gordon Severson Richard Wagner P.O. Box 58055 3201 Westmar Cir. P.O. Box 60868 Fairbanks, AK 99711 Anchorage, AK 99508-4336 Fairbanks, AK 99706 George Vaught, Jr. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 484A.006 December 21, 2021 Ms. Kyndall Carey, Land Representative Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: CO-21-027 Request for Administrative Approval to Amend Well Spacing for the Polaris Oil Pool Prudhoe Bay Unit Dear Ms. Carey: By letter dated and received December 17, 2021, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to amend Rule 1 of Conservation Order No. 484A 1 (CO 484A) to remove the 20-acre well spacing requirement and allow for unrestricted interwell spacing for the Polaris Oil Pool (POP). In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp’s request. CO 484A was issued on November 30, 2005. It superseded CO 484, which was issued on February 4, 2003. Since that time, drilling and completion practices have significantly advanced. Strict adherence to a rigid well spacing requirement can prevent smaller targets from being targeted and does not provide for wells to be placed for optimal development of the POP. Numerous pools in Alaska originally had rigid well spacing requirements, but over the years the spacing has been revised to eliminate the interwell spacing requirements while retaining the standoff restrictions from property lines to allow for optimal development of the pool while protecting the correlative rights of nearby landowners. Amending Rule 1 of CO 484A to eliminate the interwell spacing requirements while prohibiting wells from being completed within 500 feet of property lines where the owner or operator changes will allow for POP development to be optimized and correlative rights to be protected. 1 The letter referenced Conservation Order No. 484 but that order has been superseded by Conservation Order No. 484A. CO 484A.006 December 21, 2021 Page 2 of 2 Now therefore it is ordered that Rule 1 of CO 484A is repealed and replaced by the following: Rule 1 Well Spacing There shall be no well spacing restrictions within the Polaris Oil Pool, except that no well shall be opened to production within 500 feet of a property line where ownership and landownership are not the same on both sides of the property line. DONE at Anchorage, Alaska and dated December 21, 2021. Jeremy M. Price Daniel T. Seamount, Jr. 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. Jeremy Price Digitally signed by Jeremy Price Date: 2021.12.21 13:57:08 -09'00'Dan Seamount Digitally signed by Dan Seamount Date: 2021.12.21 14:27:01 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Conservation Order Nos. 457B.008, 452.006 and 484A.006 Date:Tuesday, December 21, 2021 3:00:39 PM Attachments:CO 457B.008.pdf CO 452.006.pdf CO 484A.006.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Conservation Orders granting Hilcorp North Slope, LLC’s request for amendments to well spacing requirements in the Aurora Oil Pool (CO 457, Rule 1), Midnight Sun Oil Pool (CO 452, Rule 3), and the Polaris Oil Pool (CO 484, Rule 1). Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 12/21/21 gs INDEXES North Slope, LLC Kyndall Carey Land Representative 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8386 Fax: 907/777-8301 kyndall.carey@hilcorp.com December 17, 2021 Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 RE: Proposed Amendment to Conservation Order No. 484 (Prudhoe Bay Field Polaris Oil Pool) Dear Chair Price: Hilcorp North Slope, LLC (“Hilcorp North Slope”), as the operator of the Prudhoe Bay Unit, respectfully requests that the Alaska Oil and Gas Conservation Commission administratively approve1 an amendment to Conservation Order (“CO”) No. 484 (February 4, 2003) by repealing Rule 1 in its entirety and replacing it with the following language. Rule 1: Well Spacing There shall be no well spacing restrictions within the Polaris Oil Pool, except that no well shall be opened closer than 500 feet to an external boundary where ownership changes. In addition to reducing administrative burdens, the proposed change is designed to prevent economic and physical waste and improve the ultimate recovery of remaining hydrocarbons. This proposed change does not modify the affected area provided in CO No. 484 and it does not jeopardize correlative rights. By eliminating intra-pool well spacing requirements, Hilcorp North Slope will be able to target smaller, undrained portions of the reservoir that cannot be reached by wells conforming to current spacing restrictions. If you need additional information, please contact Kevin Eastham at 907/777-8316. Sincerely, Kyndall Carey Land Representative Hilcorp North Slope, LLC cc: ConocoPhillips Alaska, Inc. ExxonMobil Alaska Production, Inc. Chevron U.S.A., Inc. Administrative Action is being requested pursuant to CO No. 484, Rule 10. By Samantha Carlisle at 9:34 am, Dec 17, 2021 'LJLWDOO\VLJQHGE\.\QGDOO&DUH\ '1FQ .\QGDOO&DUH\ RX 8VHUV 'DWH .\QGDOO&DUH\ >iotttbie, Jody J (CED) From: Rixse, Melvin G (CED) Sent: Wednesday, June 10, 2020 2:27 PM To: Sternicki, Oliver R Cc: Colombie, Jody J (CED) Subject: FW: June 25 hearing to amend 4 CO's Attachments: CO -20-008 Public Hearing Notice.pdf,, RE: CO -20-008 This is a clarification email to BPXA, Oliver Sternicki, that the AOGCC interpretation of any development well going through Lisburne Production Center, whether on gas lift or natural flow, will be allowed 2500 psig sustained inner annulus pressure before reporting is required. CO -20-008 as written should be fine. We will then administratively amend the COs per the notice. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 area n 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 Mel Rixse at (907-793-1231) or ( Melvin. Rixseg aIaska.Rovl. cc. Jody Colombie From: Colombie, Jody J (CED) Sent: Wednesday, June 10, 20208:59 AM To: Chmielowski, Jessie L C (CED) <Jessie.chmielowski(o)alaska.gov> Cc: Rixse, Melvin G (CED) <melvin.rixse6Dalaska eov> Subject: RE: June 25 hearing to amend 4 CO's No one has requested a hearing. Mel: Do you vote to vacate? Jody From: Chmielowski, Jessie L C (CED) <iessie.chmielowski(@alaska gov> Sent: Wednesday, June 10, 2020 8:57 AM To: Colombie, Jody1 (CED) <jodv.colombje_@alaska eov> Cc: Rixse, Melvin G (CED) <melvin.rixse(o)alaska.eov> Subject: June 25 hearing to amend 4 CO's Hi Jody, Were there any requests to hold the hearing that's scheduled for June 25? Wondering if we can vacate and administratively amend the CO's? Cor ombie, Jody J (CED) From: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Sent: Tuesday, June 2, 2020 3:43 PM To: Rixse, Melvin G (CED) Cc: Lau, Jack Subject: RE: CO -20-008 Mel, I was doing some work on the NOL increase and noticed something that might need slightly more clarification. The operator shall notify the AOGCC within three working days after the operator identifies a development well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig- The issue is that this wording could be interpreted as just applying to the gas lifted produces at LPC and excludes the natural flow producers at that facility and in the GPMA area. There are currently 69 wells this applies to. This part should read: ...for wells with supplied gas lift pressure from the Lisburne Processing Center or wells processed through the Lisburne Processing Center... Let me know what you think, Oliver V Sternicki Wo Sr. Well Integrity Engineer BP Exploration Alaska Cell: 1 (907) 350 0759 oliver.stern ickiCabp.com From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Friday, May 15, 20204:31 PM To: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Subject: FW: CO -20-008 From: Colombie, Jody J (CED) <iodv.colombie(@alaska.eov> Sent: Friday, May 15, 2020 3:16 PM To: AOGCC_Public_Notices <AOGCC Public Notices@list state ak us> Subject: [AOGCC_Public_Notices] CO -20-008 Docket Number: CO -20-008 Prudhoe Bay Field, All Pools dodv J Colombie Special Assistant Alciska Oil and Gas Conservation Commission 333 West Th Avenue Anchorage, AK 99501 (907) 793-1221 Direct (907) 2 76- 7542 Fax List Name: AOGCC Public NoticPs@list.state.ak.us You subscribed as: rvan.daniellabp.com Unsubscribe at: http://list.state ak us/mailman/options/aogcc public notices/roan daniel%40bp com STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMITINVOICE SHO%VING ADVERTISINGORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER p AO-08-20-024 FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O.AGENCY PHONE: 333 West 7th Avenue 5/152020 907 279-1433 Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: Anchorage Daily News LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchors e, Alaska 99514-0174 TYPE OF ADVERTISEMENT: P LEGAL r DISPLAY .r CLASSIFIED F_ OTHER (Specify below) DESCRIPTION PRICE CO-20-008 Initials of who re ared AO: Alaska Non -Taxable 92-600185 SUBMITINVOICE SHOWING ADVERTISING ORDER NO.,L RTHflED AFFIDAV170P PUBLICATION WTTHATTACHED COPV OF ADVERTISMENTTO: AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pae 1 of 1 Total of A)1 Pages $ REF Type I Number Amount Date Comments 1 PVN IVCO21795 2 AD AO-08-20-024 3 4 FIN AMOUNT SY Am Template PGM LGR Object FY I DIST LIQ 1 20 AOGCC 3046 20 2 3 4 5 u ri Tide: Purch n tmx Purchasing Audmrity's Signature Telephone Number .O.0 and receiving agency name must appearon all invoices and documents relating to this purchase. 2 estate is registeredfortaxfree transactions underChapter32. IRS code. Registraaonnumber92-73-0006K. Items are for the exclusive use of the state and M for resale. DISTRIBUTION: Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form: 02-901 Revised: 5/21/2020 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION Re: Docket Number: CO -20-008 Prudhoe Bay Field, All Pools BP Exploration Alaska, Inc., by application received February 24, 2020, requests the Alaska Oil and Gas Conservation Commission (AOGCC) revise Rule 3 of Conservation Orders 317, 505, 559 and 570 to include the following language: The operator shall notify the AOGCC within three working days after the operator identifies a development well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 prig. In addition, on its own motion AOGCC proposes to add the language that "unless notice and public hearing are otherwise required, upon proper application the AOGCC may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater." The AOGCC has tentatively scheduled a public hearing on this application for June 25, 2020, at 10:00 a.m. at 333 West 7s' Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on June 5, 2020. Due to health mandates issued as a result of the covid-19 virus, if a hearing is requested, the hearing will be held telephonically. Those desiring to participate or be present at the hearing should call 1-800-315-6338 and, when instructed to do so, enter the code 14331. Because the hearing will start at 10:00 a.m., the phone lines will be available starting at 9:45 am. Depending on call volume, those calling in may need to make repeated attempts before getting through. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1221 after June 7, 2020. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7"' Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 22, 2020, except that, if a hearing is held, comments must be received no later than the conclusion of the June 25, 2020 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the Jemy AOGCCSpecial Assistant, Jody Colombie, at (907) 793-1221, no later than June 20, 2020. M. Price Chair, Commissioner Bernie Karl K&K, Recycling Inc. Gordon Severson Richard Wagner P.O. Box 58055 3201 Westmar Cir. P.O. Box 60868 Fairbanks, AK 99711 Anchorage, AK 99508-4336 Fairbanks, AK 99706 George Vaught, Jr. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 3 BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 t*. February 24, 2020 Mr. Jeremy Price Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Request to amend Conservation Order No. 492 rule 3(a) and 6(a). Dear Mr. Price, BP Exploration (Alaska) Inc. requests an amendment to Conservation Order No. 492 rule 3(a) and 6(a) such that current notification and pressure limits are changed from 2000psi to 2100 psi for wells not processed through the Lisburne Processing Center. Current maximum gas lift header pressure in the Prudhoe Bay field for wells not processed through the Lisburne Processing Center regularly exceeds 2000psi. The field - wide IA (Inner Annulus) NOL (Normal Operating Limit) is set at 2000 psi for non -Lisburne development wells, excluding jet pump wells. Beginning in 2015 BPXA began installation of wireless digital annulus pressure gauges on all wells, this was completed in late 2019. Due to the increased accuracy of the annulus pressure readings and realtime monitoring/alerting capability, board operators are now very frequently responding to false alerts of IA NOL excursions on gas lifted wells due to gas lift header pressure exceeding 2000 psi, not sustained casing pressure as intended. BPXA requests that rule 3(a) and 6(a) be changed from 2000psi to 2100 psi (excluding jet pumps) for wells not processed through the Lisburne Processing Center to help minimize lb_o�ird and well pad operators responding to false alerts. If you have any questions, please call me at 564-5430. Sincerely, Ryan Daniel BPXA Well Integrity Team Lead Attachments: Technical Justification Technical Justification for Conservation Order No. 492 Amendment February 24, 2020 History and Status: Gas lift header pressure at many of the drill sites and pads in the Prudhoe Bay field (excluding wells processed through the Lisburne Process Center) regularly exceeds the 2000 psi IA NOL set for development wells. Gas lift compressor outlet pressures are commonly set at 2100 psi. Historical gas lift pressures can be seen in Figure 1 & 2 for reference. The legacy IA NOL value of 2000 psi was set to remain compliant with Conservation Order No. 492 rule 3(a) and 6(a). Prior to the installation and monitoring of wireless annulus pressure gauges this was not as large of a problem due to one IA pressure read being recorded via mechanical gauge daily per well. If a pressure read exceeded the 2000 psi NOL it was reported to Well Integrity and evaluated to determine if the excursion was SCP or not. Currently all wells in the Prudhoe Bay field have the inner annulus pressures monitored in real-time by either the EOA or WOA production center board operators. The board operators are notified with an alert when the IA pressure of a well exceeds the set NOL value of 2000 psi. This ensures a timely notification and response to any potential excursion event. With the utilization of the wireless annulus pressure gauge alerting it has become an ongoing problem where wells supplied with gas lift pressure are regularly setting off alerts due to the gas lift supply pressure exceeding the 2000 psi NOL and not due to SCP as intended. This excessive alerting has the potential to desensitize workers to possible hazardous occurrences. Increasing IA NOL from 2000 psi to 2100 psi for development wells would eliminate the majority of these false NOL excursion alerts and allow resources to be more focused on response and evaluation of probable SCP events. This increase of 100 psi to the IA NOL is well within the design parameters of development wells across the Prudhoe Bay field. All development wells are included in this request in an effort to reduce the complexity of the IA NOL change. While non gas lifted wells are not subject to the same false alerts there is an increased risk of operating the field with IA NOLs varying for different types of wells. The use of gas lift on development wells, including natural flow producers, is continually changing, some require gas lift for kick off purposes only while others need constant gas lift. Gas lift usage may also change as a well ages depending on depletion or may change due to well work such as add pert/ reperf interventions. The tracking of these dynamic changes would be very difficult and the continual changing of NOL between 2000 psi and 2100 psi for individual wells in multiple data and control systems would greatly increase the complexity and management of NOLs across the field. This inconsistency in IA NOLs would be difficult for field personnel to continually keep track of and would reduce their effectiveness in identification of potential SCP events and would potentially result in misreporting of excursions. The IA NOL increase would not reduce the ability to identify SCP excursions in non -gas lifted wells. BPXA currently monitors development wells for minimum tubing by IA differential pressure thresholds as an indicator of communication. In addition to this SITP of non - gas lifted wells is in excess of 2100 psi, which if seen on the IA would indicate a loss of tubing integrity and would flag as SCP. Based on this it is requested to increase the IA NOL for all development wells (excluding jet pump wells and those processed through the Lisburn Processing Center) to 2100 psi. Figure 1- EOA DS Gas Lift Header Pressure EOA Gas Lift Pressure - sponm snvnn —osw i --osw i —osos ii —us m —osw --mu —osn snnms v.vm.. .ronws 9M.n s:n+no:s vw:ma �nvm:< Me Figure 2- WOA Pad Gas Lift Header Pressure w0A Gas Lift Pressure —A PW —xPYa —oP -- x P.a —1 Pod —1 Pa —m Pae —x Pm PPM w Pea —s P. v roa Ptl Pet Y Potl iP.e October 23, 2018 Via USPS and Electronic Delivery Hollis French Commission Chair Alaska Oil and Gas Conservation Commission 333 West 78i Avenue, Suite 100 Anchorage, AK 99501 BP Exploration Alaska) Inc 900 East Benson Bowevanc PO Box 596612 Anchorage. Alaska 99519 6612 (907) 561-5111 L ; L I t 2b t Re: Application for Administrative Approval Conforming PBU Satellite Pool Rules for Consistency Amendments to Conservation Orders: 457 A/B, Rules 4b, 5b, 5e Aurora Oil Pool; 471, Rules 4d and 5b, Borealis Oil Pool; 505B, Rules 4d and 5b, Orion Oil Pool; 484A Rules 4b and 5b, Polaris Oil Pool, 452 Rule 7d, Midnight Sun Oil Pool, governing initial well testing requirements and pressure surveys Dear Chair French, 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 one of the Satellites in the PBU. This administrative relief is sought under Rule 10 of CO 457 and its equivalent 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 to pressure survey requirements are in line with recent commission -approved changes to CO 341 F for the Prudhoe Oil Pool. Initial Well Testing Requirements The current pool rules for the five satellites require two well tests per month during the first three months of production. BPXA requests that the commission eliminate this requirement, as the five satellites are now well established fields and we see no continuing purpose served by requiring two well tests per month during the first three months of production. This change to initial well testing requirements will align pool NA Application for Administrative Approval Amendment of COs 457 A/13, 471, 50513, 484A, 452 October 23, 2018 rules for the five satellites with how new wells are tested in the Prudhoe Oil Pool. Operating efficiency will also be improved with a consistent testing requirement at L and V Pads where Orion and Borealis production occurs at the same location as Prudhoe Oil Pool production, at Z Pad where Borealis and Prudhoe Oil Pool production both occur, at S Pad where Polaris, Aurora, and Prudhoe Oil Pool production occurs, and at W Pad where Polaris and Prudhoe Oil Pool both occur. Pressure Survey Requirements Rule 5a for the Aurora, Borealis, Orion, and Polaris Oil Pools requires that prior to regular production or injection, an initial pressure survey must be taken in each well. BPXA requests elimination of that rule for these pools as exists for the Prudhoe Oil Pool. In order to safely drill any new well, BPXA conducts a pore pressure fluid gradient study at the well's location to determine drilling mud weight; furthermore, during the course of drilling, an estimate of reservoir pressure is provided by responses from the reservoir itself. Additionally, greater ultimate recovery is encouraged by not requiring the operator to shut a well back in after initial clean-up to obtain an initial pressure that will not provide materially useful information before placing a new well on production. Such pressures may be acquired as part of obtaining the minimum requirement for a Representative Area (see below). The pool rules for the Aurora and Orion Oil Pools currently relate the required number of annual pressure surveys to the number of governmental sections in the pool, yet the pool rules for the other satellite pools, in the same reservoirs, do not contain this requirement. BPXA requests that all 5 satellite pools address pressure surveys on the same basis, by using the Representative Area for the purpose of determining the number of required pressure surveys. Representative Areas are bounded by significant faults. BPXA manages all Satellite Pools by Representative Area. The revised rule would ensure area] spread of pressure surveys across the Pools, where the existing Aurora regulations allow the same location to be surveyed many times over. The revised rule would also be consistent with the Prudhoe Oil Pool pressure survey Rule 6 which defines seven development areas; these are broadly equivalent to Satellite Representative Areas. Regarding what constitutes an acceptable pressure for reporting requirements, we request to modify the language in the Aurora, Borealis, Orion and Polaris rules by closely aligning with what is in CO 341F (Prudhoe Oil Pool), and permitting calculation of bottom -hole pressures from surface data for any wells on water injection. In terms of frequency of pressure surveys, BPXA proposes to move to a minimum of one per annum per Representative Area, provided the Representative Area contains active well(s). As for the Prudhoe Oil Pool, each year's ASR report will propose the minimum number of pressures that will be acquired per active Representative Area for the next plan year. BPXA proposes AOGCC have the ability to object to the proposed number within the first month after ASR submittal. 2 Application for Administrative Approval Amendment of COs 457 A/B, 471, 5056, 484A, 452 October 23, 2018 We also request revision of reporting of all pressure surveys in Aurora's rule 5e to remove the quarterly requirement and make it annual, thereby bringing conformity with the other satellite pools. These proposed amendments are shown in the following section and summarized in the table on page 8. Proposed Amendments to Rules Note: Use of [ J's means delete existing order word(s). Use of underline denotes proposed new text. Aurora Oil Pool (AOP) Rule 4b. All wells must be tested a minimum of once per month. [All new Aurora wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. Rule 5a. [Prior to regular production or injection, an initial pressure survey must be taken in each well.] Rule 5b. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunction with the Annual Aurora Oil Pool Reservoir Surveillance Report by September 15 of each year. This elan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Aurora Oil Pool The minimum number of bottom - hole pressure surveys performed each year shall equal the number of [governmental sections] Representative Areas within the AOP that contain active wells. [A minimum of four such surveys shall be conducted each year in representative area of the AOP. Bottom -hole surveys conducted pursuant to paragraph "a" of this Rule may be used to fulfill the minimum requirement.] With reference to the attached map (Mapl), the AOP currently contains 5 Representative Areas: West of Crest, North of Crest, South East of Crest, Crest Area, South of Crest). Rule 5d. Transient p[P]ressure surveys obtained by a shut in buildup test [may be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase fluid conditions),] an injection well pressure fall-off test, a multi -rate test[s], an interference test drill stem tests, and open -hole formation tests are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water iniection. Other quantitative methods may be administratively approved by the AOGCC. 3 Application for Administrative Approval Amendment of COs 457 A/B, 471, 50513, 484A, 452 October 23, 2018 Rule 5e. "Data and results from all reservoir pressure monitoring tests on surveys must be reported to the Commission annually [quarterly] on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but shall be available for inspection by the Commission upon request." Borealis Oil Pool (BOP) Rule 4d. All wells must be tested a minimum of once per month. [All new Borealis wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. Rule 5a. [Prior to regular production or injection, an initial pressure survey must be takin in each well.] Rule 5b. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunction with the Annual Borealis Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Borealis Oil Pool The [A] minimum number of bottom -hole pressure [of four] surveys performed [shall be required] each year shall equal the number of [in] Representative Areas [of the Borealis Pool] within the BOP that contain active wells. JBottom-hole surveys in paragraph (d) may fulfill the minimum requirement.] Rule 5d. "Transient [P]pressure surveys obtained by a shut-in build up test an injection well pressure fall-off test a multi -rate test or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for any well on water iniection. Other quantitative methods may be administratively pproved by the AOGCC. [may be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase service fluid conditions]), pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests.] With reference to the attached map (Map 1), the BOP currently contains 6 Representative Areas: North L -Pad, SW L -Pad, East V -Pad, North V -Pad, South V -Pad, Z -Pad. Orion Oil Pool (OOP) Rule 4d. All wells must be tested a minimum of once per month. [All new wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. 4 Application for Administrative Approval Amendment of COs 457 AB, 471, 50513, 484A, 452 October 23, 2018 Rule 5a. [Prior to regular production or injection, an initial pressure survey must be takin in each well.] Rule 5b. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunction with the Annual Orion Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan Year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Orion Oil Pool The [A] minimum number [of one bottom - hole] pressure surveys performed [per producing governmental section] each year shall equal the number of Representative Areas within the OOP that contain active wells.Abe run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements.] Rule 5d. Transient P]pressure surveys obtained by a shut-in build up test an injection well pressure fall-off test a multi -rate test or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection Other quantitative methods may be administratively approved by the AOGCC. [may consist of be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase service fluid conditions), pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests.] With reference to the attached map (Map 2) the OOP developed portion contains Representative Areas with active well(s) labeled 1, M, 2, 2A, 5S.. Orion representative Areas without at least one active production well are 6N, 6S, 9, 8, 4, 5N, 3A, 3N, 3S. Polaris Oil Pool (Sat -POP Rule 4b. All wells must be tested a minimum of once per month. [All new Polaris wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. Rule 5a. [Prior to regular production or injection, an initial pressure survey must be takin in each well.] Rule 5b. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunction with the Annual Polaris Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Polaris Oil Pool The [A] minimum number of [two] pressure surveys performed [shall be taken] each year shall equal the number of Representative Areas within the Sat -POP that contain active wells [in the main area S/MPad North and the W -Pad \ Term Well -C reservoir compartments, and one reservoir 5 Application for Administrative Approval Amendment of COs 457 A/B, 471, 50513, 484A, 452 October 23, 2018 pressure each year in the remaining compartments when at least one Polaris production well has been completed in the respective compartments]. With reference to the attached map (Map 2), the POP -Sat currently contains four Representative Areas labeled S Pad N, S Pad S, W Pad N, W Pad S. Rule 5d. Transient [P]pressure surveys obtained by a shut-in build up test an iniection well pressure fall-off test, a multi -rate test or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. Imay be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase fluid conditions), pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, or open -hole formation tests.] Midni¢ht Sun Oil Pool Rule 7d. All wells must be tested a minimum of once per month. [All new Midnight Sun wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. Rule 8c. [Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface, pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests.] Transient pressure surveys obtained by a shut-in build up test an iniection well pressure fall-off test a multi -rate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water iniection Other quantitative methods may be administratively approved by the AOGCC BPXA respectfully requests the commission rule on this request before by first quarter 2019, as July 1 is the beginning of a new plan year. It will be more efficient if these rules were in effect for the entirety of the next plan year. This submission was initiated after consulting with commission staff beginning in the summer of 2017. Implementation of these changes to the satellite pool rules will promote BPXA's ability to manage the reservoirs in support of a greater ultimate recovery of oil and gas. 0 Application for Administrative Approval Amendment of COs 457 A/B, 471, 505B, 484A, 452 October 23, 2018 If the commission has any questions please contact Bill Bredar at William bredarna by com (907) 564-5348. Sincerely, Jnr/ Katrina Garner West Area Manager Alaska Reservoir Development Attachments: Maps I and 2 (Public and Confidential versions) Cc: D. Sturgis, ExxonMobil Alaska, Production Inc. J. Farr, ExxonMobil Alaska, Production Inc. E. Reinbold, CPAI D. White, Chevron USA D. Roby, AOGCC 7 0 req co NYM IIm<XrIYr CunrM rriY4nun Y N RYMYIe ChryYi IHY/meMIrM MN )mwkb 'hgebY .. Gnwt MrMYrrn Yet XMWn MeM YrWbrC MYWlomtq minMmTY IPwaeMf pTeWfPBonm 9W YmGxrp RYMYm C�YY FevwY LYYYY)Pe•)wNIM Xevsn NeN PIWIYY PW Yb a•WY BriYYm�Y _ '' 11 cuiamiu Pov •_ _ eav II /prne•mrcnlal whom wf tpn ryr Malin Xra M.', akwAro & IP Sf mJYe pwbrlV trurrva•... i'�/rvn , 'r• e!.rrnn.•Ir � AU i 1 1 Sa NunrMlr nliue weYli nMrJ f4h YrX rn I 11y11mIJni Xlli2 'rU.. I Ilpn wxlxr 611J hmn 4w VMwl1 •rt`n V , rPr yM Irve 4eN _ _ _ _ __ yrrl s LI OYNpmin %M. ',..I IM IrgfIPn1JIM MfJ W-11yt00—w BNP _ kn..ar',r pl q rbnmuV Mf / I !.a elu/hPat r• ' IUX tpdaXO Xhw NOm eurlxe Nlanmr XN b1.rIM N14Uri� a'.! I /n I I � VO.n rnlrrbnlalMXra1 .'_.. w,lta�.. _ wglf(IIVJltl Y1E[II®_ XNrOw NUN Peek: . Sp lmlam la POP. '. i � ilprrrpeefenlalnY Xra PF^I'I fJNWXUMMBNP _ Urrlm� 'USX 9a rlrrninJh Jtl a 't im µapwnp pnerm•Yn1J1 IMI Inmxlne boor awlxe tl+fahgn Xry ._ frafmn _... I•. wtl wNa mM1M'n _ Um10>/M GnalMutmrpXinvnr � S6 (cMamlu l'OP• I.0 IfYgplµxr ld plMUrlrcM Inmq cakUPNP lt.n) IWPJdI(Nm YJNII 1pn rfpefmlJlwe XPJ Xpnflulxn do, pXa M1pn yry Pn14••' JMrI Ia rUnPkJlr• JU ] 1rnVXhrrrk11.81N INIfMIJyNxIM wYN rnwJIM MP'flnln •MIrwJ Puk Se maYr uMn meal }a Mlm�ndip }If xP�reluim aw'MPhIrM � wNN•) Represenative Areas by Orion / Polaris Schrader Bluff LEGEND Schrader Bluff Representative Areas (Approximate) Orion (1, 1A, 2, 2A, 2AS; 3A, 3S, 3N, 4,5N, 5S, 6N, 6S, 8,9) Q Polaris (SPadN, SPadS, WPadN, WPadS) Pool Q Polaris Q Orion Participating Areas ORION POLARIS j Prudhoe Bay Unit • Perf Midpoint OA Faults OA Depth (ft TVDss) High : -3100 r Coordinate System: I NAD 1927 StatePlans Alaska 4 FIPS 5004 Projection'. Transverse Mercator Datum: North American 1927 Data Sources: Well, Units, Coastline maintained by BPXA Cadography. � Exploration Nass 900 E. Benson BIW Anchorage, AK MAP 2 560000 570000 580.000 590000 600000 610,000 620000 63D000 by Represenative Areas N Orion / Polaris0 0 0 o 0 Schrader Bluff o LEGEND -- ------- ----------------------------- --------_ -- r_—__------ i Schrader Bluff Represenative Areas !i _.. 1 ! ---------- (Approximate) I I Orion (1, 1A, 2, 2A, 2AS; 3A, 3S, 3N, 4, 5N, v I r --.--:—,-1 1 5S, 6N, 6S, 8, 9) Q Polaris (SPadN, SPadS, WPadN, o WPadS) m Pool ^ Q Polaris L L -----------t L-203 OL -223 - -a -----------------1 • Orion r L-200 212 �\ { 1 L-� =•L-216 \ L.L-25� x-215-- 5-201 • Participating Areas ORION 7 L-202 •L-219 - o __-^-^_ L_. - �` ( ,.- -` • \ - S Pad N POLARIS o 1 t 1 �L-201 L-222 L 2 Prudhoe Bay Unit 7 • -2 114A L-210 - -; 3 L-213 L-204 •V-221 �� . s Perf Midpoint 1 • • V-20 0 • V-210 0 "22 -, .- S -213A • „-. • V-220 • 1 L -205#-221V-202 • •V -20T V -2140V S-217 • • L-220 a V -216V-213 •.-224 •S-218 • SPad S -?11 V-�4• o f •V-212 V-222 - m i V-217 21 -..._ ............. W-221 i 1 ••V 2250 V-223 V-219 V-205• • W-220 • m ' • V-215 ... W-2180 218 W-202 d, I i 1 `-----------; j W W--217 W Pad N 217 1 I g . . _. ........ _... -2160 W_201 1 W-214 • W- s_ j13 • W-219 • W-205 �— I `------------------ OW -212 00o •W-20 L-------` 1 i rtt • N ' 211• -- -210 W-203 i - 7 1 0 1 a I • Miles y W Pad S Coordinate System: i NAD 1921 Stale Plane Alaska 4 FPS 5004 t Projection: Transverse Mercator t- Datum: North American 1927 ti.. o Data Sources: m - o n N Well, Units, Coastline maintained by 3PXA Cartography. s TIrAM BPM aP Exploration Alaska me Anon MAMA 560000 900 E. Benson Blur Anchorage, AK MAP 2 REV.3 570000 580000 590000 600000 610000 626000 630000 — x. soau,Ea one.tBv REVIEW B. RREMR ones, ton by RECEIVED NOV 0 4 2015 BP Exploration A® '` '"® RO Boxlaska) Inc. 900 t19e6612Anson Bouleva d 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 Fiver 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.-, � 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 1 (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). If 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: 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) [mailto:dave.roby('Oalaska.gov] Sent: Tuesday, December 15, 2015 6:11 PM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane and/or Caroline, I'm putting the finishing touches on the admin approval for this request and I have a question for you. In the request you asking us to waive Rule 4b in CO 3296.003. 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.robv@alaska.gov. From: Richmond, Diane M [mailto:Diane. RichmondC@bl2.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.roby(cbalaska.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 13th, 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.roby@alaska.gov. 2 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 ] 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 (Ce11) #6 � RECEiVED APR 0 2 2014 Dr. Werner Schinagl Base Team Leader West End Dave Roby Reservoir Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 AOGCC BP Exploration (Alaska) Inc. P.O. Box 196612 900 E Benson Boulevard Anchorage AK 99519-6612 USA April 1st 2014 Re: Polaris Oil Pool — C.O.484A Rule 5b (Reservoir Pressure Monitoring) Dear Mr. Roby, I have had a review with my team regarding the surveillance requirements for each of the West End fields. In the Polaris Oil Pool, we have one area where we would kindly like to ask your permission to deviate from the stated requirement of two static pressures per annum (Figure 1). The reason for asking permission to deviate from the stated requirement is due to the fact there has been no production from S Pad North wells (S-200 or S-201) for all of the 2013 ASR reporting period. The production plots below highlight this (Figure 2 & Figure 3). We have already planned to get one static, however we would be grateful if you could grant us permission not to do a second static in this compartment. Please do not hesitate to contact me should you have any further questions. I appreciate you looking into this matter. Respectfully, L `ZA1101 '" cxt�7'� Dr. Werner Schinagl Base Management Team Leader West End Page 2 0 • 0 3 O Page 3 0 1201'1999 120 r2001 120 t2003 120 F2005 120MN 12131 f2009 120 J2011 120 C 013 -Oil Vol (bbls) -(-Water Vol (bbls) -*-Gas Vol (mscf) -WOn-LineJOff-Line Figure 2: Production chart of well S-200 -*-Oil Vol (bbls) (Water Vol (bbls) -*-Gas Vol (mscf) tnn-Line/Off-Line Figure 3: Production chart of well S-201 i ~ Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC Group 1 IPA Group 2 GPMA Group 3 Satellites ----- Annual Surveillance Report 15-Mar 15-Jun 15-Sep --.. .- Annual Overview Presentation 22-Mar 22-Jun 22-Sep ---.- Production Period to be Covered Jan 1-Dec 31 Apr 1-Mar 31 Jul1-Jun 30 . Amends Order/Rule Order Date Comment G~()!lP_1=-~~_º!!~C)o~~.._.___ ..- Prudhoe Oil Pool --... ----. '-~._.'. - ---- -~-'-'-----'".~._~---.-...--.-.- Put River Oil Pool C0341D Rule 11 C0559 11/30/2001 11/22/2005 Note C0341 E (modified Pool Definition to include a portion of Put River SandstonE!) -- Corrected 2/14/2006 ~r~~.e.2._:_ G~~A Oil~oo~.__~_. Lisburne Niakuk --- .... --.-- .~.._._-_.---_._---_. North Prudhoe Bay pt. Mcintyre . .------- ... ..._--_..._--_..__.__..~~----::- Raven Oil Pool West Beach Oil Pool -~-- C0207, 207 A C0329A Rule 9 C0345 Rule 8 C0317B Rule 15 C0570 Rule 10 C0311B Rule 13 --. --f--. 6/4/1996 12/16/1994--- ----------- 4/19/2000 8/9/2006 8/1/2000 No rule on Surveillance reports .- . -- ---- - -'---"".--- ---"-_.._----- - . .-- _______,___.·..__....__._n__ -- -- -~-------------- ----".,--_.,--_._-----_...._----~-_._--- ._u -_..__._._-~-----_._.~~- . ... Group 3 - Prudhoe Satellite Oil Pools _...__..._.-..._...._-_._..._._---~---_.~,~_._----_. - Aurora C0457B Rule 8 ---------. ..-----..-..-.-..---.-~-- r--..--.- Boreallis C0471 Rule 4 --.- --. --..-..---.-..--.-.--------.- ¡---.-. Midnight Sun C0452 Rule 11 -. ·-··-·------·-·-·--Orion--C0505A Rule 9 -.. -- ---- ._u_.__._ ..-...-.--.-.-------.-----.c---- .--. Polaris C0484A Rule 9 --- --- .-.-- 6/25/2004--- -- - - 5/29/2002 11/15/2000 4/28/2006 -- ----"1-1/3/2065----- -.---.--------------.----- (corrected 8/9/2004) -- -- -.------...--..-.--------.--------- #4 Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC Group 1 IPA Group 2 GPMA Group 3 Satellites ~..._~-~-~_.~---_.._-----~-----_. -- -~--- --~----~-~~---~- Annual Surveillance Report 15-Mar 15-Jun 15-Sep --~ -~------~~~-~._------ ----~------~-~_.~ --~~~- _._-_._...~-_._~--_.._-_. ~--------~-~ _._----_._----_...._.------_.._~._-_..- --- -~----~- ----~~--~ -- Annual Overview Presentation 22-Mar 22-Jun 22-Sep --~----------------~ ---~---~--- ---~----~-'-- ---~~--- ------ Production Period to be Covered Jan 1-Dec 31 Apr 1-Mar 31 Jul1-Jun 30 . Amends Order/Rule Order Date Comment Group 1 - IPA Oil Pools . .n___ ..n~d~:.Oi~:OOII ------.--..- ,-.,-.-'-----....---....-..-- Put River Oil Pool . _._---_._~._~------_. C0341D Rule 11 -----_.._----_..~---~_.~- C0559 11/30/2001 11/22/2005 Note C0341 E (modified Pool Definition to include a portion of Put River Sandstone) ._-,--_._~---_._-~- Corrected 2/14/2006 Groue 2:-º~M~ºi~J~e».()ls__________ --_._--------~---------_._-_.- Lisburne C0207, 207 A - ~-,---_._._._.------~."._._-_. -.---_.~_._-------~--,---_. Niakuk C0329A Rule 9 _0-' ______...____~_._____~___ ..___ ".._,.________ _ _______~orthprudhoe Bay . C0345 Rule 8 ___~_ .~~____~_.f!:._~~"tyre____n~9317B Rule 15 Raven Oil Pool C0570 Rule 10 --.--..-.. -_._.._--_..__......_._~"---------_..._-----~...._.._- .._._--_._-,-._._--~---_.,._---_._-.- West Beach Oil Pool C0311 BRule 13 ---~---_._._.- _J'!~!.l:I~<?n SUi".~!lIa~ce reP<?!:Ì~__ 6/4/1996 12/16/1994 4/19/2000 8/9/2006 --~_..~---- 8/1/2000 ---..---..---'---.--.-"- ._._-~~---_._._-_.._.~ --~---_.._-~--~--- ~-----_.__.~.~--_._..__._~,--~-- . Group 3 - Prudhoe Satellite Oil Pools - u..·..· .un ~m ~-----. . ·-----_~:~-------=~lJrorã m~=~=~º_'!~iErRu~~~_==_m~m-m- 6/25/2004 m-~=t m:==I~~~~f~~ted 87~(~Q~) :=__ __ .~__~__m n_~m_.. Bo!eallis _~ Cq,!!_1 Rul~_,!__ ___ 5/29/2002 ______Lnn___~_______~___________ Midnight Sun C0452 Rule 11 11/15/2000 i -~---m_-6no-n -----C0505ARule"9 ---- 4/28/2006-m---r--------~--- __~__n__ ___ _~____,_ ____ ___~_____~..__..,____,..,.~ ________~~._.__.,_______.._____,_.__L___n__.__ _ .__. __________...,___._.'_ _______..______...__.____.. Polaris C0484A Rule 9 11/3/2005· - ---.-.. '-- '----.-.-.-- ,----..'---...--.- l""- ........ l'" ..-. ~~_. --........ ._.~.................._- ...-t".......... --"-~Jj . . Subject: [Fwd: [Fwd: Re: surveillance report dates]] From: Jane Williamson <j ane _ williamson@admin.state.ak.us> Date: Fri, 20 Apr 2007 13 :03 :59 -0800 To: Jody J Colombie <jody_colombie@admin.state.ak.us>, Dave Roby <daveJoby@admin.state.ak.us>, Cathy P Foerster <cathy_foerster@admin.state.ak.us>, Alan J Birnbaum <alan _ bimbaum@law.state.ak.us> cc: Stephen E Mcmains <steve_mcmains@admin.state.ak.us>, art Saltmarsh <art_saltmarsh@admin.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us> There is sornething I didn't get around to before I left and that was to adrninistratively arnend the COs for PBU to include reporting dates agreed to verbally with BP (and DNR). Really, only pt. Mcintyre and Borealis have the wrong dates in the eo's. The others are either ok, or not explicit. Attached are the COs affected. I'm not sure how you want to handle. Jody. Please put this in the following CO files along with the attachrnent. Group 1 - IP A Oil Pools Prudhoe Oil Pool C0341D Put River Oil Pool C0559 Group 2 - GPMA Oil Pools Lisburne C0207,207A Niakuk C0329A Rule 9 North Prudhoe Bay C0345 Pt. McIntyre C0317B Raven Oil Pool C0570 West Beach Oil Pool C031lB Group 3 - Prudhoe Satellite Oil Pools Aurora C0457B Boreallis C0471 Midnight Sun C0452 Orion C0505A Polaris C0484A -------- Original Message -------- Subject:Re: surveillance report dates Date:Thu, 31 Aug 2006 17:27:45 -0800 From:Jane Williamson <jane williamson(â!admin.state.ak.us> Organization:State of Alaska To:Lenig, David C <David.Lenig(â!bp.com> References:<CBF4D8E92B5A 704 79F64416582F6A17CB81 AEO(â!bp lili'lcex005.bp 1.ad.bp.com> Oops Lenig, David C wrote: Hi Jane, 10f3 4/23/2007 9:50 AM ll&- .V...... L" ........ ..,,-~............. ._L....-......__ ...-1""""'...... ...-..............Jj . . ! didn't get the attachment. David From" Jane W'III'lamson [n¡,;o¡¡!:n'1;o:1,;:' -i¡,/,j;:;r,i::('i·((ù.",-'m>-'~-:-;:';-" :ok .:;] . ,..~.j.__,;....J."... .J,!..--o'.,___,. _...:=. ~_.,.,._,.,,::.;J__,___,_,..o_...._ Sent: Thursday, August 31,20065:14 PM To: Lenig, David C Subject: Re: surveillance report dates E-mail is fine. Attached is a list of the pools and orders/rules that will be amended with the Admin approval. Take a look and see if this looks right to you_ (Note, I'm only listing the rules that are affected by the new dates - there may be additional amendments unrelated to the surveillance requirements that I've not listed.) I'm flexible on the date for the Overview presentation. I'd be fine with specifying it to be within one or two months of the report date rather than the POD overview that you've noted. What would you prefer? Lenig, David C wrote: Jane, Here is a table showing the dates for the various Reports and Presentations. I've added the production period as well. The IPA review date remains problematic due to the proximity to spring break but we seem to work around it each year. Would you prefer that I put this in a letter requesting the changes? I know we talked about this a little while ago I just haven't found the time. Thanks, David Plan of Development Production Period Jull-Jun30 IPA GPMA March 15 June 15 September 15 March 22 June 22 September 22 March 30 June 30 September 30 Janl-Dec31 Aprl-Mar31 Satellites Annual Surveillance Report Annual Overview Presentation -----Original Message----- From: Jane Williamson [mailto:jane williamson@aQ~in.state.ak.us] Sent: Thursday, August 31, 2006 2:30 PM To: Lenig, David C Subject: surveillance report dates Hi David. When you get a second, could you please send back an e-mail that lists all the surveillance report dates that we've agreed to for all PBD pools (including GPMA)? Also, do you have dates for surveillance reviews? I'll go through the list and make sure the Conservation orders are correctly worded, then put out administrative amendments as necessary. I checked with Cammy and she said an e-mail is fine for starting the 200 4/23/2007 9:50 AM l" ........ l'" ..-. ~..._......-... .-........-.....-- ..-t'......... -......-.....JJ . administrative action process. Thanks. '\;)~illiçn11sc'n~ PE <j EH1e ·vv'illiamsorl{Ji¿ad}Tlir~.state. 211(. us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission . Content-Type: application/vnd.ms-excel surveillance report. xis Content-Encoding: base64 3 on 4/23/2007 9:50 AM *3 [Fwd: Re:. Request Surveillance reporting peri.arificatiOn] . , Subject: [Fwd: Re: Request Surveillance reporting period clarification] From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: Thu, 31 Aug 2006 13:37:23 -0800 To: Jody J Colombie <jody_col ie@admin.state.ak.us> CC: Cathy P F ster <cathy _foerster@admin.state.ak.us>, Camille 0 <cammy_tayl law.state.ak.us> Please put this e-mail in the CO 505a and Ç0484A files. -------- Original Message -------- Subject:Re: Request Surveillance reporting period clarification Date:Thu, 31 Aug 2006 13:33:53 -0800 From:Jane Williamson <¡ane williamson(a¿admin.state.ak.us> Organization:State of Alaska To: West, Taylor <Taylor. West(a¿bp.com> CC:Sullivan, Claire (Claire.Sullivan(a¿BP.com) <Claire.Sullivan(a¿bp.com>, Bajsarowicz, Caroline J <Caroline.Baisarowicz(a¿bp.com>, Holloway, Emberley L <Emberley.Holloway(a¿bp.com>, Lenig, David C <David.Lenig(a¿bp.com> References:<C 11 D74A5F 1 DF 194DB3A9 ADF4DBC4EDEOC9B99D(a¿bp lancex005.bp l.ad. bp.com> Taylor, Yes, both reports will be due on September 15 each year, and both reports for this year should cover July 1, 2005-June 30, 2006. The requirement to report on the period from January 2005-June 2006 was in error as you had provided that information in last years report. Thanks so much for bringing this to my attention. Jane West, Taylor wrote: 10f2 8/31/20062:03 PM [Fwd: Re~ Request Surveillance reporting peri.arificatiOn] . , Jane: Per our phone conversation today, I would like Commission clarification on two annual surveillance report requirements: 1. Orion (CO 505A) Rule 9 states: "An annual report must be filed by September 15.. ..must include... surveillance information for the period July 1 of the prior calendar year through June 30 of the current calendar year (except the report due on September 15.2006 must cover the period from January 2005 through June 30. 2006)" The last Orion Surveillance report submitted to the Commission on September 15, 2005 covered the period September 1, 2004 through July 31, 2005. Would it be acceptable for the current report to cover the period Julv 1.2005 throuah June 30. 2006? This will keep Orion aligned with the other satellite assets, and will actually provide a one month (July 2005) overlap with last year's report. It's not clear to me if there is value in restating the Jan 2005 through June 2005 data in the current report. 2. Polaris (CO 484A) Rule 9 contains the historic reporting language: "The report (covers)... the prior calendar year". Please confirm that the current report should cover the period Julv 1. 2005 through June 30. 2006 per prior conversations, and in keeping all satellite assets aligned. As with Orion, the current report will overlap last year's report by one month. Thanks Taylor West Production Engineer BP Exploration (Alaska), Inc. Greater Prudhoe Bay - Polaris I Orion Viscous Oil 907.564.4647 907.632.0111 cell 907.564.5016 (fax) WestTL(â2bp.com Jane Williamson, PE <jane williamson(a¿admin.state.ak.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission 20f2 8/31/20062:03 PM #2 ") ) 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: John K. Norman, Chairman Daniel T. Seamount Cathy Foerster 3 4 In the Matter of the Application of ) BP EXPLORATION (ALASKA) INCORPORATED ) 5 to amend AREA INJECTION ORDER 25 and ) to Amend CONSERVATION ORDER 484 for ) 6 POLARIS OIL POOL, Prudhoe Bay Field ) ) 7 8 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska 9 October 13, 2005 1:30 o'clock p.m. 10 11 VOLUME I PUBLIC HEARING 12 BEFORE: John K. Norman, Chair Daniel T. Seamount, Commissioner Cathy Foerster, Commissioner 13 14 15 16 17 18 19 20 21 22 23 24 25 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) ) TABLE OF CONTENTS Opening Remarks by Chair Norman . . . . 03 . . . . Disclosure by Chair Norman. . .07 Testimony of Frank Paskvan . . . 06 . . . R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ) ) 1 PRO C E E 0 I N G S 2 Tape 1 3 0015 4 (On record - 1:30 p.m.) 5 CHAIR NORMAN: Good afternoon. I'll call this hearing to 6 order. This is a hearing before the Alaska oil and Gas 7 Conservation commission being held on the afternoon of 8 Thursday, October 13th, 2005. The time is 1:30 p.m. And this 9 comes before the Commission upon the application of BP 10 Exploration (Alaska) Inc. as unit operator of the Prudhoe Bay 11 Unit. 12 The application seeks to amend Ala 25 for the purpose of 13 authorizing underground injection of enriched gas into the 14 Polaris oil Pool. 15 The legal description generally speaking of the area of 16 the proposed injection is Township 12 north, range 12 east, 12 17 north 13 east, 11 north 13 east, 11 north 12 east, all Umiat 18 Prime Meridian. 19 Notice of this hearing was duly published in the Anchorage 20 Daily News on the 6th of September. Any persons desiring to 21 receive a copy of the notice may see the Commission's special 22 assistant, Jody Columbie, who is standing in the rear of the 23 room. 24 A transcript will be made of these proceedings and any 25 persons that wish to have a transcript following the conclusion R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 3 ) 1 of the hearing can contact Ms. Columbie or may contact R & R 2 Court Reporting directly who will be doing the transcribing. 3 If there are any persons present at this meeting that have 4 any sort of a disability that may require a special 5 modification or accommodations, please, let us know and we will 6 do our very best to accommodate you to ensure that you have the 7 ability to participate in the hearing. If you need to move 8 forward, if you have any problems with access or hearing or 9 anything else, please, indicate and the Commission will, as I 10 said, do our best to accommodate you. 11 In a hearing such as this that we are going to embark upon 12 the Commission does not ordinarily allow cross examination. If 13 there are questions, however, that you would like asked of the 14 Applicant, any of the witnesses, you may write them out and get 15 them to us and we will do our best to see that your questions 16 are answered. 17 We'll hear first from the Applicant and then if there are 18 any members of the public that wish to offer testimony on this 19 matter you will also be given an opportunity to do so. 20 The Commission ordinarily ask that testimony be given 21 either under Oath or affirmation. Should you choose not to 22 provide testimony under Oath or affirmation that choice of 23 yours will be respected, but the Commission does give greater 24 weight to testimony given under Oath or affirmation. 25 If you are testifying as an expert witness we'll ask you R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 ) ) 1 to identify briefly your educational background and experience 2 in sufficient detail so we can determine your area of 3 expertise. 4 Finally, you'll see two microphones in front of you and it 5 is necessary to speak into both microphones. One of the 6 microphones is for amplification so that everyone in the room 7 can hear what you're saying, the other microphone is for the 8 benefit of our Court Reporter who is preparing the transcript. 9 As you are giving testimony, please, keep in mind that we 10 are making a record and occasionally it's necessary many years 11 later to go back and review the record. Therefore, if you have 12 slides or maps or other documentary testimony keep in mind that 13 we must correlate your testimony to whatever you're referring 14 to. 15 So if the slides are numbered, that's helpful. If they're 16 not numbered then, please, be sure to read the caption on the 17 slide and we will ask that you provide a copy that we can 18 attach to the transcript of this meeting. 19 Try to avoid saying this location right here or this place 20 here because a reader of the transcript at some future point 21 will not know what you're referring to. Instead try to refer 22 to either one of the cardinal locations or in the lower left 23 hand corner of the slide, things of that nature, so that the 24 words you're speaking when transcribed will tie into whatever 25 diagrams or maps that you have. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5 ) ) 1 The Commissioner on my right is commissioner Dan Seamount. 2 On my left, Commissioner Cathy Foerster. A quorum is present 3 for the conduct of legal business. 4 Commissioner Seamount, do you have anything to add? 5 COMMISSIONER SEAMOUNT: I have nothing, Mr. Chairman. 6 CHAIR NORMAN: Commissioner Foerster. 7 COMMISSIONER FOERSTER: Yes. First, I want to thank you 8 guys for preparing the testimony you're going to present to us 9 today and for preparing the excellent documentation that you've 10 already submitted to our technical Staff. 11 The reason that we're having this hearing today is not 12 because of major conflicts or a lack of information, but rather 13 because we recognize that what you're doing is of ground 14 breaking importance. You're attempting an EOR process in one 15 of the greatest resources on the North Slope so we wanted to 16 make it publicly available, get it on the record and have the 17 opportunity to understand it better yourselves, so thank you 18 very much. 19 MR. PASKVAN: You're welcome. 20 CHAIR NORMAN: Anything more, Commissioner Foerster? 21 COMMISSIONER FOERSTER: That's it. 22 CHAIR NORMAN: Okay, thank you for that. Very well. We 23 will then proceed to hear from the Applicant and you, sir, are 24 here to testify for the Applicant, BP? 25 MR. PASKVAN: Yes, I am. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 6 7 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 R & R C 0 U R T R E P 0 R T E R S 25 so we can proceed and we always want to make any disclosures in 24 conflict, that's why we have three Commissioners and a quorum CHAIR NORMAN: Okay. If any persons do feel like that's a 23 COMMISSIONER SEAMOUNT: I see no conflict. 22 21 witnesses sisters would disqualify me? 20 with -- she was my former law partner, with one of the 19 I'll leave it to you to determine whether my acquaintance 18 And, Commissioner Seamount, as the senior commissioner 17 the record. 16 of that acquaintance, but I do want to make that disclosure on 15 information that would be of relevance to this matter by virtue 14 attorney here in Anchorage. I do not believe that I have any 13 and I have a high opinion of her. She is a very well regarded 12 disclosure that I am well acquainted with Ms. Bonnie Paskvan CHAIR NORMAN: I see. commissioners, I need to make a 11 MR. PASKVAN: She is my sister. 10 CHAIR NORMAN: Related to Bonnie paskvan? 9 MR. PASKVAN: Yes. 8 CHAIR NORMAN: P-a-s-k-v-a-n? 7 MR. PASKVAN: My name is Frank Paskvan. 6 CHAIR NORMAN: Your name, please? 5 TESTIMONY BY FRANK PASKVAN 4 MR. PASKVAN: I do. 3 (Oath Administered) 2 CHAIR NORMAN: Would you raise your right hand, please? 1 ) ') ) ) 1 fairness to all parties. So I have made the disclosure and if 2 anyone wants to speak up I will not be offended if you think I 3 may give greater or lesser weight to Mr. Paskvan's testimony, 4 but I was the law partner of his sister for probably 15 years. 5 Okay. I think with that out of the way, Mr. Paskvan, 6 please proceed. 7 MR. PASKVAN: Okay. I would like to be..... 8 COMMISSIONER FOERSTER: Do you want to get his expert..... 9 CHAIR NORMAN: I'm sorry, I got sidetracked. We will ask 10 you -- your intention is to testify as an expert witness? 11 MR. PASKVAN: Yes, if it pleases the Commission. 12 CHAIR NORMAN: And if you, please then, give us your 13 educational background and work experience? 14 MR. PASKVAN: Thank you, Mr. Chairman and Commissioners. 15 I am a reservoir engineer for BP Alaska, Incorporated currently 16 working as the team leader for both the Polaris and Orion 17 viscous oil development projects in Prudhoe Bay. 18 I received a Bachelor of Science Degree in Petroleum 19 Engineering from the University of Alaska-Fairbanks in 1985. 20 In that year I joined ARCO Alaska, Inc. which was later 21 acquired by BP. 22 I've worked as a reservoir engineer for a variety of 23 Alaskan projects including the Prudhoe Bay, Kuparuk, Lisburne, 24 Midnight Sun, Aurora Borealis and polaris fields. 25 In 1994 I transferred to ARCO Indonesia, Inc. as a R & R C 0 U R T R E paR T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 8 ) 1 reservoir engineering specialists where I was responsible for 2 training Indonesian reservoir engineers for development 3 planning in the offshore northwest Java sequence of fields. 4 And for appraisal planning and reserve certification for the 5 super giant Tangguh LNG gas fields. 6 I've been working for the -- in the Prudhoe Bay west end satellite team since November of 1998 as development lead for the Aurora and Borealis fields and since 2004 for Polaris and 7 8 9 Orion. 10 I have testified as an expert witness in Alaska in prior 11 hearings before the AOGCC and I would like to be acknowledged 12 today as an expert witness. 13 CHAIR NORMAN: Questions, commissioner Seamount? 14 COMMISSIONER SEAMOUNT: I have no questions. Mr. Paskvan 15 is very qualified in my opinion. 16 CHAIR NORMAN: Commissioner Foerster? 17 COMMISSIONER FOERSTER: I agree. 18 CHAIR NORMAN: Thank you, Mr. Paskvan. The Commission 19 accepts your qualifications as an expert witness in the area of 20 reservoir engineering. 21 MR. PASKVAN: Thank you. 22 CHAIR NORMAN: Please proceed. 23 MR. PASKVAN: Well, we have prepared the Polaris Pool Area 24 Injection Order 25 modification. The application submitted on 25 August 23rd, 2005 and supplemented on August (sic) 4th and as R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 9 ) ) 1 of this date October 13, 2005. 2 with regards to today's submission I've left a copy of 3 this with commission staff and upon review of the 4 confidentiality of the exhibits we've agreed to waive 5 confidentiality for the five exhibits and have submitted those 6 today to your staff. 7 CHAIR NORMAN: Mr. Paskvan, is it correct then, just as a 8 general statement, that confidentiality has been waived as to 9 all of the information that we now have before us? Is there 10 anything submitted to us that you are seeking to invoke 11 confidentiality for? 12 MR. PASKVAN: There is one item remaining. It's the in 13 the original application Exhibit IV-3 and with regards to that 14 Exhibit we would request that it be held confidential. We've 15 provided an Exhibit IV-3A which has a portion of the material 16 redacted from it and that will be reviewed in the -- today's 17 presentation. 18 with regards to IV-3 we've agreed to waive confidentiality 19 while reserving the claim that trade secrets are entitled to 20 protection even if relevant to a Public Hearing issue and 21 introduced to the record and relied upon by the AOGCC in its 22 decision, so..... 23 COMMISSIONER FOERSTER: What is the context of Exhibit 24 IV-3? 25 MR. PASKVAN: It pertains to an oil/gas PVT experiment. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 10 ) ) 1 CHAIR NORMAN: It's IV-3, the Roman Numeral..... 2 MR. PASKVAN: IV. 3 CHAIR NORMAN: .....IV-3? 4 MR. PASKVAN: Yes. 5 CHAIR NORMAN: And without disclosing the contents -- yes, 6 um-hum, I see it. We have it here. without disclosing the 7 contents of that would you briefly describe it? That is our 8 practice so if there are any persons present that wish to raise 9 a question about it they would have a description of generally 10 what it is. 11 MR. PASKVAN: Certainly. It is the results of a multiple 12 contact experiment between well W-203 oil and Prudhoe Bay MI. 13 The slide will be shown in a revised form IV-3A during the 14 presentation and so you can have a view of that, but certain 15 information has been redacted from that in the non-confidential 16 version. 17 CHAIR NORMAN: Very good. You can remind us of that when 18 we come to it, so go ahead and please proceed. 19 MR. PASKVAN: Thank you. We ask that the Commission enter 20 in its entirety this application to the record. 21 CHAIR NORMAN: Commissioner Seamount, any objection? 22 COMMISSIONER SEAMOUNT: No objections. 23 COMMISSIONER FOERSTER: No (ph). 24 CHAIR NORMAN: without objection the application is 25 entered into the record. R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 11 ") ) 1 MR. PASKVAN: Thank you. And then for purposes of this 2 hearing we would offer to present certain excerpts from that 3 application if it does please the Commission? Thank you. 4 And I should note that with me are several members of the 5 Polaris team including geologist Jonathan Williams and 6 production engineer Taylor West, reservoir engineer Bharat 7 Jhaveri, geologist Aaron Liesch and reservoir engineer Rydell 8 Reints. So we may need their assistance to more fully answer 9 your questions upon occasion. 10 I will now present the application and its exhibits for 11 the Commission. Essentially what I'd like to do is provide a 12 brief overview of what the scope of the application is and then 13 spend a little bit of time on the recovery processes that we 14 intend to employ in the Polaris oil pool. 15 On the screen you see slide number 1 which is an agenda. 16 Slide number 2 is the Application Overview. Again, the 17 intention is to modify the existing Polaris Area Injection 18 Order which is primarily under waterflood at this time to 19 include the allowance of injection of the Prudhoe Bay Unit 20 miscible injection gas for enhanced recovery operations 21 purposes. 22 We plan a fourth quarter 2005 start-up if we're allowed to 23 proceed and in the application we're requesting authorization 24 for three injection wells now which are presenting being 25 equipped for -- with facilities. Future wells will be covered R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 12 ) ) 1 by sundry approval request filed with the Commission. 2 It's our intention to use the existing Prudhoe Bay 3 miscible injection gas supply provided by the central gas 4 facility, but it's important to note and fundamental to this 5 application to recognize that the mechanism employed here given 6 the viscous oil API gravity and composition it may not all be 7 miscible injection -- fully miscible with the gas. 8 And so the process, the mechanism is, in fact, a viscosity 9 reducing mechanism which I should mentioned that this is 10 documented in an SPE paper 93914 and is published in the 2005 11 SPE Western Regional Meeting in March, so quite a bit of 12 technical detail available on that. And note that we are 13 looking at a nominal operation wellhead injection pressure on 14 gas injection on the order of 3,200 psi. 15 Moving to slide number 3 this exhibit shows the Polaris 16 wells as of 7/31 2005 and I provided this -- it was taken not 17 from our application, but from our annual surveillance review 18 of the Polaris oil pool which we reviewed with the Commission 19 Staff, I believe, last month. 20 And as this exhibit shows the current well status in the 21 Polaris pool is there are eight producers, three of which are 23 multi-lateral producers and five are conventional frac'd producers and there are six injectors. On the figure the multi-lateral producers are noted as the long, straight reddish 22 24 25 colored lines and the injectors in the pool are noted as blue R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 13 ) 1 triangles. 2 There is one well, W-201, which is -- we'll originally 3 complete it as single, lateral well which we exclude from the 4 three multi-lateral count because it was subsequently 5 hydraulically fractured at -- near the heel of the well and is 6 effectively acting, we believe, as a vertical frac'd producer. 7 80 that gives a flavor for the current scope of development 8 within the Polaris oil pool. 9 Note also that the development is occurring off of two 10 pad and the W pad locations in the WOA portion of pads. The 8 Prudhoe Bay. On slide 4 the Polaris Area Injection Order, this figure 11 12 13 is showing the three proposed PBU MI injection wells. Wells 14 number S-215i, W-215i and W-209i. And in this diagram it shows 15 the overall location of the Polaris oil pool, all existing 16 injection wells, production wells, abandoned wells, dry holes 17 and any other wells within the pool as of July 1st, 2005. This 18 is derived from Exhibit V-l of the application and just wanted 19 to show you the location of the three injectors at that -- that 20 we're seeking approval at this time. 21 These wells have satisfied the mechanical integrity 22 requirements as required and are being equipped for MI 23 injection. When they are originally installed we utilize the 24 I premium thread tubulars to provide integrity during the 25 injection of MI. R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 14 \ ) ) 1 And we've run cement evaluation logs on all these 2 injectors. These logs indicate we do have cement present 3 providing isolation across and above the Schrader formation in 4 each injector so we're satisfied and have provided what we 5 believe is sufficient evidence to satisfy the mechanical 6 integrity aspects of this injection process. 7 On slide number 5 this is a typical injection well 8 schematic also taken after an exhibit in the application. This 9 is injection well W-215. And you can see the type of 10 completions that are currently being run in the Polaris oil 11 pool injection wells now. 12 These are notionally conventional, deviated wells. Trying 13 to keep relatively low hole angles so as to enable slick line 14 operations to enable us to go in and selectively set and remove 15 chokes across particular intervals and improve our ability to 16 manage the reservoir from the injection side of the flood 17 process. 18 This is one of our more recent wells. Note that not all 19 injection wells in the pool have this level of zonal isolation 20 capability. 21 That really summarizes the physical, logistical aspects of 22 the project and I would like to discuss now the physical 23 mechanisms, the reservoir mechanisms associated with the 24 viscosity reduction WAG process. 25 COMMISSIONER FOERSTER: Before you do that, Mr. Paskvan, R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 15 ) ) 1 could you characterize for me the difference in performance and 2 cost of the horizonal, multi-Iat wells versus the traditional 3 frac wells? 4 MR. PASKVAN: On the production side there -- our wells 5 are typ- now curr- -- our current generation have -- we've 6 gone to the horizontal, multi-lat. On the injectors we're 7 still -- see the most effective way to complete and control the 8 reservoir is with the vertical or conventional injectors, but 9 for the record the horizonal, multi-lat producers have 10 substantially improved the rate of oil recovery from the 11 reservoir. 12 And where the first generation of wells were typically 13 vertically drilled and hydraulically fractured to improve the 14 natural completion efficiency, we were typically expecting on 15 the order of a few hundred barrels a day. It's called a two or 16 300 barrels a day as a substantially average conventional 17 frac'd production rate. 18 Whereas in our current generation of horizontal multi-lat 19 wells -- and when I say multi-lats, the original series of 20 horizontal wells were just that, a single, horizontal and have 21 progressed over the years in complexity, capabilities on the 22 drilling side and on the completion side to enable as many as 23 -- our S213-A has five horizontal, laterals each of which can 24 range from 3,000 to six or 7,000 foot long of completion 25 interval. R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 16 ) ) 1 And the production rate of that type of a well because of 2 its exceptional degree of net pay is an order of magnitude 3 better than the vertical well, so you're talking about a two, 4 three, four, even a 5,000 plus barrel of oil a day producer. 5 COMMISSIONER FOERSTER: Thank you. 6 MR. PASKVAN: So onto slide number 6 which is Exhibit 2-A 7 (sic), Viscosity Rèduction of the W-203 oil Sample by Prudhoe 8 Bay MI in a Multiple Contact Experiment. 9 The contemplated operation addressed in this application 10 is a tertiary recovery project using enhanced oil recovery 11 techniques of miscible gas flooding. And viscosity reducing, 12 immiscible enriched gas flooding to increase recoverable oil. 13 The project involved cyclical injection of water 14 alternating with injection of enriched hydrocarbon gas into the 15 oil column of the Schrader Bluff sandstone of the pool. 16 The gas to be used in the project, the Prudhoe Bay MI, 17 will be comprised of hydrocarbon gas enriched with intermediate 18 hydrocarbons principally ethane and propane. 19 In this slide it clearly shows the degree of viscosity 20 reduction of the W-203 oil in a multi-contact experiment. The 21 W-203 sample is a commingled oil sample with a nominally -- 22 about a 40 centipoise oil viscosity and a 17.5 degree API 23 gravity. 24 And you can see that with repeated contact of the oil with 25 increasing levels of injected Prudhoe MI, PBU MI, that the R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 17 ') ) 1 initial viscosity, anomaly 40, is substantially reduced by over 2 an order of magnitude down to about two and a half or three 3 centipoise and that's one of the fundamental mechanisms 4 associated with the improved recovery associated with this 5 injection process. And..... 6 CHAIR NORMAN: Just curious, what if you had extended 7 those lines -- do those -- how do those trends -- does it 8 flatten out eventually -- at some..... 9 MR. PASKVAN: It certainly does, asymptotically 10 flatten. It's important to recognize and note that the 11 viscosity reduction is substantial even with a variety of 12 injection pressures. 13 This data shows the injection of ga- -- where the 14 reservoir or laboratory cell pressures maintain bot- -- at 15 2,100 psi. In an alternate case the pressure is 1,800 psi. 16 Both show this substantial reduction in viscosity substantially 17 similar to one another across the range of pressures tested 18 here. 19 And also it's worthwhile to note that the data presented 20 shows both the laboratory data represented by the dots and the 21 lines are the equation of state representation which is used in 22 our fully compositional mechanistic modeling which 23 I substantiates the application and the equation of state is I 24 supported and demonstrated to show a good match by the 25 laboratory data. R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 18 ) ) 1 It's also worthwhile to note that this is -- experiment is 2 far below the minimum miscibility pressure that would be 3 required to achieve miscibility between this type of oil and 4 the injectant and you'll see that in a slide coming up. 5 Slide number 7 is Exhibit IV-3A and this shows the density 6 of both the oil phase and the gas phase as it's changing during 7 the experiment with the increasing injection of the PBU MI. 8 And again, note that the laboratory data demonstrates the good 9 job that it's doing predicting the experimental laboratory 10 data. 11 The information presented here is showing that the density 12 of the oil and gas phases are substantially changing which is 13 indicating amass balances occurring at phase behavior changes 14 occurring between the oil phase and the gas phase and you're 15 moving moles of the light injectant gas into the oil and 16 changing the oils properties. 17 In slide number 8, Exhibit IV-4A, this is the W-203 oil 18 slimtube experiment with PBU MI at the reservoir temperature. 19 And this is showing a pressure scan with increasing -- with -- 20 it's the slimtube experiment run with increasing pressures and 21 calculating the recovery for each of those experiments. 22 And the original reservoir pressure of the Polaris oil 23 pool is on the order of 2,200 psi which is on the far lower end 24 of the graph of data that's shown here in the experimental 25 range. And you can see miscibility is not developed with -- R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 19 ) ) 1 between these two fluids until greater than 3,500 psi which is 2 far above the original reservoir pressure. 3 But the viscosity reduction benefits that were shown on 4 the exhibit two slides earlier were developed at the low end of 5 this and, in fact, below the low end. This demonstrates that 6 you can clearly improve the viscosity of the oil through the 7 injection of the miscible gas. 8 And lastly, again, the equation of state quality is shown 9 is demonstrated by its good match with the lab data. 10 CHAIR NORMAN: Could I ask you to help me make sure I 11 understand what you're saying. Your underst- -- what you're 12 illustrating here is that miscibility is not pressure 13 dependant, but you would -- am I understanding that right? But 14 you get -- you achieve miscibility before you -- well, before 15 the 3,500 now, that's what I was trying to follow the 16 significance of that. 17 MR. PASKVAN:- Okay. What this experiment -- the slimtube 18 experiment is classically used to analyze is what is the 19 minimum miscibility pressure or minimum richness alternatively 20 of an injection fluid, how rich does it need to be to achieve 21 miscibility for a given pressure -- or fluid. 22 So if you -- if one were to take a straight line through 23 the four data points below 3,500 psi and intersect that with a 24 second straight line for the two points 400 -- or 4,000 and 25 4,500 psi, the intersection of those two points is effectively, R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 20 ) ) 1 classically taken as the minimum miscibility pressure. 2 So this demonstrates that Prudhoe Bay MI and this 3 composite oil sample from Polaris well W-203 would not be 4 miscible in the reservoir. 5 Our reservoir pressure is on the order of 2,200 psi 6 originally. So we cannot depend upon miscibility as a 7 mechanism for improved oil recovery if this were -- in this 8 type of oil in the reservoir under the reservoir temperature 9 and pressure conditions, but I would like to say that the -- we 10 do through the mechanics -- or the thermodynamics of molecular 11 exchange the ga- -- the intermediate gas phase molecules of 12 propanes and ethanes, they do transfer into the oil phase and 13 significantly reduce the viscosity of the oil even though there 14 is no miscibility established. 15 COMMISSIONER FOERSTER: Mr. Paskvan, at what pressure do 16 you intend to maintain the reservoir during this injection? 17 MR. PASKVAN: That's a good question. The current Area 19 Injection Order specifies the Polaris oil pool pressure is to be maintained at -- at/or above 1,633 psi which is corresponding to the bubble point pressure of the fluid. 18 20 21 And in classical waterflood reservoir engineering planning 22 purposes the maximum waterflood recovery occurs at or above the 23 bubble point pressure. And, in fact, can be maximized at near 24 1 25! bubble point pressure so it's our intention to for the to maintain the area pressure at or above 1,633. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 21 ) ) 1 We cannot achieve miscibility as this slides demonstrates, 2 but we will substantially increase the oil recovery by the 3 addition of the PBU MI all the way down to the bubble point 4 pressure. 5 COMMISSIONER FOERSTER: Does your viscosity reduction 6 benefit continue to increase as you raise the pressure above 7 the bubble point? 8 MR. PASKVAN: As shown in the Exhibit IV-2A there is a 9 slight change in the viscosity with pressure, but your biggest 10 impact -- but these basically track each other all the way 11 through over one mole of MI per mole of oil. So since we are 12 so far below the bubble point -- in the range of pressures from 13 original reservoir pressure on the order of 2,200 pounds down 14 to the bubble point pressure of 1,633 psi we expect to see the 15 same level of viscosity reduction. 16 COMMISSIONER FOERSTER: I'm done (ph). 17 MR. PASKVAN: These concepts are further demonstrated in 18 the next exhibit, slide number 9 which is Exhibit IV-5A and 19 it's entitled, Minimum Miscibility Pressure variation with oil 20 C7 through C13 Concentrations. 21 In a part of the project area where the reservoir oil has 22 sufficient concentrations of C7 through C13, the MI does form a 23 miscible bank with the reservoir -- with the reservoir oil 24 through the exchange of hydrocarbon components and effectively 25 displaces nearly all of the contacted oil resulting in residual R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 22 ) ) 1 oil saturations significantly lower than with waterflooding 2 alone. 3 The oil develops miscibility with MI at reservoir 4 conditions by the condensing vaporizing multiple contact 5 miscibility mechanism. 6 In areas of the reservoir project area where the 7 biodegradation of oil is high, the oil lacks sufficient 8 concentration of C7 through C13 components to be miscible with 9 the PBU MI at reservoir conditions. 10 In this project area although the injection PBU MI does 11 not develop miscibility with reservoir oil in all the zones, 12 the multiple contact, condensing, vaporizing, mass transfer 13 mechanism between the C02 and the C2 through C4 rich PBU MI and 14 the reservoir oil causes a significant reduction in the 15 reservoir oil viscosity. 16 The magnitude of the tertiary oil rec- -- of the tertiary 17 oil recovery by this viscosity reducing, immiscible, enriched 18 gas flood mechanism is, in fact, very close to the tertiary oil 19 recovery in the project area with the miscible gas flood 20 mechanism. And injected water helps maintain reservoir 21 pressure, retards gravity segregation of the miscible injectant 22 and controls channeling. 23 COMMISSIONER FOERSTER: Mr. Paskvan, I apologize, but when 24 I look at that graph what it tells me is that where you've got 25 a lot of C7 through C13s you gain recovery up to about 2,300 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 23 24 ANCHORAGE, ALASKA 99501 810 N STREET (907)277-0572/Fax 274-8982 R & R C 0 U R T R E paR T E R S 25 The prior Exhibit showed that a portion of the oil in the 24 ranges. 23 injection for Polaris oils with medium to high viscosity 22 review of the incremental oil recovery with the Prudhoe Bay MI The next Exhibit, slide number 10, Exhibit IV-6A, is a 21 20 swelling and viscosity reduction. 19 miscibility mechanism, but also incorporating the impacts of 18 oil recovery that we've predicted based upon not only the .....and, if I may, review the incremental MR. PASKVAN: 17 COMMISSIONER FOERSTER: So -- go ahead. 16 ..... and 15 14 is what we rely upon in the viscosity reducing WAG mechanism 13 different than that of a slim tube, silica packed system which 12 fluid flow between an injector and a producer that are 11 But there are other mechanisms going on in the reservoir 10 characteristic of the gas/oil phase behavior. 9 and so it's made to be very sensitive to that particular 8 designed to clearly demonstrate where miscibility is achieved 7 clearly demonstrate -- it's an experimental that -- which is 6 which is a slimtube experimental cell and it's designed to MR. PASKVAN: That is an accurate reading of this graph 5 4 still gets you something, am I reading that graph correctly? 3 something, but that every pound that you go up above this 1,633 2 again, you'd have to get up to 3,400 -- 3,300 pounds or 1 pounds and that in the -- where the degradation has occurred, ) ') ) ) 1 reservoir will be miscible and another portion of the oil in 2 the reservoir will be immiscible. 3 What this exhibit demonstrates is that the better quality 4 oils in this case represented by the 15 centipoise oil will 5 achieve substantial incremental recovery -- incremental oil 6 recovery above the waterflood,..... 7 COMMISSIONER FOERSTER: okay. 8 MR. PASKVAN: .....but also that the intermed- -- the 9 lower quality, in this case the 56 and 117 centipoise oil, also 10 demonstrates significant incremental recovery above the base 11 waterflood and substantially similar to each other. 12 I will note that these incremental recoveries are those 13 represented -- or developed in a two dimensional type pattern 14 model and so we don't anticipate when we implement it in the 15 field to see these -- this magnitude of incremental oil 16 recovery, this -- we're missing aerial sweep and the interzone 17 impacts and real world oil field reductions from this type 18 behavior, but that all three do substantially improve oil 19 recovery and of the same order of magnitude as each other, both 20 the immiscible viscosity reducing WAG mechanism and the fully 21 miscible. 22 We believe that the -- in the viscosity reducing WAG in 23 the lower quality oils that what you're doing is assisting the 24 processes which are at work in a waterflood. The swelling 25 I mechanism by which -- I mean, the mass transfer of hydrocarbon R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 25 26 ANCHORAGE, ALASKA 99501 810 N STREET (907)277-0572/Fax 274-8982 R & R C 0 U R T R E P 0 R T E R S 25 it's independent -- it's somewhat independent of pressure, .....because you're telling me COMMISSIONER FOERSTER: 24 MR. PASKVAN: I..... 23 22 is at 1,630,..... COMMISSIONER FOERSTER: Do you have one that shows what it 21 MR. PASKVAN: In this case, yes. 20 19 a minimum, but your modeling is based on 2,200? (simultaneous speech) so 1,633 is COMMISSIONER FOERSTER: 18 17 targeted at near original conditions, like, 2,200 psi. 16 of one, hold the reservoir pressure nominally constant and we 15 following a primary and then with a voidage replacement ratio 14 would have established an initial waterflood period at -- MR. PASKVAN: These would be held at essentially -- we 13 12 were you holding the reservoir at for these behaviors? 11 what injection withdrawal ratio did you assume or what pressure COMMISSIONER FOERSTER: So in conducting these experiments 10 9 this project. 8 mechanisms which are predominant in the immiscible portion of 7 established from the injector to a producer and those are the 6 more able -- more readily to flow given a pressure differential 5 The other impact is the viscosity reduction which makes it 4 oil mobility. 3 that pore and allows with increased oil saturation increased 2 order of 10 percent and so that increases the oil saturation in 1 components into the gas phase increases the volume by on the ) ") ) 1 yet..... 2 MR. PASKVAN: Right. 3 COMMISSIONER FOERSTER: ..... the pressure you ran it at 4 is a higher one than what you -- so do you see what I'm 5 where I'm trying to get? 6 MR. PASKVAN: I do understand where you're heading. In 7 this case the materials we've provided we don't have a case 8 which is run at a variety of pressures, but what the -- when we 9 look at this and as an expert interpreting this information 10 what we are demonstrating is that the mechanisms are 11 effectively providing the same degree of recovery. 12 And that as -- if you -- if one were to take the quality 13 variations between the highest quality oil and the lowest 14 quality oil, those can also be transposed in effect to a single 15 quality oil run at a variety of pressures and you can see that 16 the incremental recoveries of the mechanism that we're 17 intending to employ we see have substantially the same degree 18 of incremental recovery over the base waterflood. 19 So in that context and given the operational 20 considerations of running a waterflood and that the waterflood 21 process can, in fact, be expected to be maximized at or near 22 the bubble point we see the -- again back to the earlier 23 question about what's the targeted pressure, we see no reason 24 to try and seek to raise the reservoir pressure in order to 25 marginally improve this gas injection project incremental, R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 27 ) ) 1 perhaps, at the prejudice of the base waterflood operation. 2 COMMISSIONER FOERSTER: So increasing the pressure above 3 the 1,633 in the waterflood operation could lose reserves? 4 MR. PASKVAN: Yes. Yes, the -- it depends though upon 5 many, many characteristics of the particular reservoir. One of 6 the things which in a -- again in a classical sense waterflood 7 recovery is substantially -- or slightly improved near the 8 bubble point. 9 You have the -- you're taking advantage of the mechanisms 10 of the gas -- or the oil expands as pressure is dropped and so 11 you get the swelling benefits in the waterflood. Your 12 viscosity goes down as you reduce the pressure until you get to 13 the bubble point and also as you go even slightly below the 14 bubble point. 15 And if the average reservoir pressure is at the bubble 16 point than some is below, you'll be generating a local area of 17 gas which is coming out of solution, but has not yet actually 18 developed into a gas tongue (ph) and so when it's below the 19 critical gas saturation can remain in the reservoir and as a 20 gas bubble it's displacing oil and improving the recovery of 21 the oil. 22 COMMISSIONER FOERSTER: So for the non-reservoir engineers 23 that might be reading this testimony or listening to it right 24 now, what I'm hearing you say is that you've got a couple of 25 different reservoirs mechanisms that might be competing with R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 28 ) ) 1 each other for impact on viscosity? 2 What you're -- increasing the pressure while it might help 3 reduce the viscosity behavior from this slimtube type effect 4 you have exactly the opposite effect in the waterflood and that 5 the offset is in favor of the waterflood? 6 MR. PASKVAN: That's correct. 7 COMMISSIONER FOERSTER: Okay. 8 MR. PASKVAN: That's correct. And further if we have a 9 bottomhole injection pressure constraint, let's say on our 10 water injection or gas injection well, if we are able to 11 maintain a somewhat lower reservoir pressure, well, then that 12 injector is able to put more injectant into the ground and 13 you're able to, in effect, run the reservoir at a faster flood 14 rate and advance -- mature the mechanism more rapidly. 15 COMMISSIONER FOERSTER: Thank you. 16 MR. PASKVAN: Thank you. So on slide number 10, Exhibit 17 IV-6A these are representations of the incremental oil recovery 18 of the mechanism above the waterflood. And it's a fully 19 compositional, mechanistic type pattern model which were 20 conducted using the Polaris equation of state for a W pad 21 reservoir description. 22 And varying oil quality which ranges from a miscible OBc 23 sand oil to a high viscosity below MMP OA sand oil with a 30 24 percent slug hydrocarbon four (ph) volume slug injection of PBU 25 MI at a water/gas ratio of one. R & R C 0 U R T R E paR T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 29 ) ) 1 And these simulations do show that the incremental 2 recovery of the WAG process minus the waterflood process for 3 the below miscible, but very efficient viscosity reducing WAG 4 flood in the OA sand was very close to the incremental recovery 5 for the miscible WAG flood for the OBc sand. 6 In slide number 11, IV-7A this is indicating the phase 7 viscosity after .5 hydrocarbon pore (ph) volumes of Prudhoe Bay 8 MI injection. And it clearly indicates the -- or shows the 9 reduction in oil viscosity by the condensing, vaporing, mass 10 transfer process in a one dimensional slimtube displacement. 11 And this is experimental data -- or this is a numeral 12 model of the experiment that wa- -- the data that was shown 13 before and you can see in this the significant reduction in the 14 oil viscosity along the slimtube there. 15 When we look at the overall project, exhibit -- or slide 16 number 12 which is Exhibit IV-1A which is showing the Polaris 17 oil pool production and recovery profiles with both water and 18 with PBU miscible gas injection you can see a significant 19 improvement in oil production rate in the waterflood plus MI 20 injection case for the pool as compared with the waterflood 21 only scenario. 22 That concludes my testimony and in summary the application 23 i is to modify the Polaris Area Injection Order for PBU MI I 24 injection. And at this time we're seeking authorization for 25 three injection wells now and permission for sundry approval in R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 30 ) ) 1 the future for further injection wells as -- with the passage 2 of time. 3 CHAIR NORMAN: Thank you, Mr. Paskvan. Questions, 4 Commissioner Seamount? 5 COMMISSIONER SEAMOUNT: Yes. How much gas is going to be 6 used in this project? 7 MR. PASKVAN: The Exhibit IV-1A previously shown has the 8 gas injection rate over a course of about 15 years at -- on the 9 order of five million a day. 10 COMMISSIONER SEAMOUNT: Do you believe that this process 11 would work over -- how much of the viscous oil resource on the North Slope would this work on the -- would it work on all of it or a small percentage or. . . . . 12 13 14 MR. PASKVAN: Well, it may be as much limited by the 15 source of the available injectant as any -- the portion of 16 viscous oil that we're -- is currently under development in the 17 Polaris oil pool is what we might call the floodable portion. 18 And that comprises on the order of a quarter of the viscous oil 19 resource if you look at that as compared to the entire Ugnu. 20 I should say that the West Sac IJ project is envisioning 21 use of this -- a similar type process, viscosity reducing WAG 22 and that the SPE paper referenced does have some discussion 23 I about the employment of this mechanism in the area where we, in 24 the Prudhoe Unit, have access to -- or we're directly connected 25 to the facilities linking us to the central gas facility. In R & Reo U R T R E paR T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 31 32 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 R & R C 0 U R T R E P 0 R T E R S 25 ¡ improve efficiency of allocation of that scarce resource by And with this expansion we intend to MR. PASKVAN: 24 COMMISSIONER SEAMOUNT: Okay. So we're constrained by resource then? MR. PASKVAN: Yes. COMMISSIONER SEAMOUNT: okay. 23 I 22 21 20 the Prudhoe Unit at this time. 18 191 that from the nominal eight bcf a day of gas being processed in .....the process does strip out the bulk of MR. PASKVAN: 17 COMMISSIONER SEAMOUNT: Okay. 16 15 and the --..... 14 many ethane, propane molecules in the gas stream coming through MR. PASKVAN: To the limit of there's only so many -- so 13 12 increase, is that right? COMMISSIONER SEAMOUNT: So you'd have to expand to 11 10 to various reservoirs and Aurora and Borealis and..... everything the Slope has to offer now in terms of -- all of the manufactured MI from the central gas facility is currently being employed every day and allocated within the Prudhoe unit 9 8 7 MR. PASKVAN: Well, in effect we are using all of the -- 6 5 process over the entire resource? 4 take everything the North Slope had to offer to apply this COMMISSIONER SEAMOUNT: So do I understand that it would 3 2 injectant and I believe with the import of natural gas liquids. 1 West Sac they're blending their own viscosity reducing ) ) ) ) 1 allowing injection -- or causing injection to be made into a 2 new reservoir which is a target for improved efficiency of 3 recovery. 4 COMMISSIONER SEAMOUNT: And the MI will some day be 5 recovered, is that correct? 6 MR. PASKVAN: That is correct. If does, in fact, fairly 7 rapidly cycle through the reservoir and is produced back into 8 the facilities which are then gathered and flowed back to the 9 central gas facility for, again, cryogenically extracted from 10 the main gas stream mixed with lean gas to manufacturer the 11 miscible -- PBU miscible injectant and then recycled back out 12 to another injection well. 13 COMMISSIONER SEAMOUNT: Okay. Thank you, Mr. Paskvan. 14 It's very interesting and exciting, I think. 15 CHAIR NORMAN: Commissioner Foerster? 16 COMMISSIONER FOERSTER: Now for the unpopular (ph) 17 question. How will major gas sales from the North Slope effect 18 this already scarce resource that potentially holds the key to 19 unlocking substantial portions of this enormous oil, heavy oil 20 resource? 21 MR. PASKVAN: Well, we intend to employ this process at 22 least until major (ph) gas sales. And our -- the current 23 development is the portion of the reservoir of the viscous oil 24 resource which is the floodable portion. So by implementing 25 this project today we're targeting it at the portions of the R & Reo U R T R E paR T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 33 ) 1 reservoir which we believe can be flooded and, therefore, see 2 benefits from this. 3 The question of the other three-quarters of the heavy oil 4 resource, whether it could be successfully employed under that 5 application has yet to be demonstrated. So for that process I 6 don't think it could be clearly stated that this -- that this 7 injection process and these molecules would hold any benefit 8 for the bulk of the resource to which you are describing. 9 COMMISSIONER FOERSTER: Would the executive summary be we 10 don't know? 11 MR. PASKVAN: The executive summary is we are aggressively 12 evaluating the recovery mechanisms to be employed in the three- 13 quarters of the resource we have yet to develop. And I should say, if I may, you know, I went to school in Fairbanks. I was born in Fairbanks. I came and I started at 14 15 16 the bottom which was Prudhoe Bay and Kuparuk and in my career 17 have moved into the Kuparuk reservoirs and now into the 18 Schrader reservoirs. 19 And I used to believe that the North Slope reservoirs were all very forgiving and kind to those of us trying to make a living in their development and resource management, but as I 20 21 22 move to the shallower horizons into the viscous oils it is 23 much, much more difficult. And I would say there is a step 24 change between what we term the light oil reservoirs and what 25 is currently under development here, the viscous oil, Polaris R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 34 ') ). 1 and Orion and West Sac. 2 I'd say in my mind, in my working career I can clearly see 3 a break in the difficulty of operations. What we've lumped 4 then in this current development which is a floodable portion, 5 the lower viscosities, the 10 centipoise to say 150 centipoise, 6 this floodable portion is what we're currently developing now 7 and it's taking a lot of work. 8 What we're envisioning is continued development and trying 9 to seek economic ways to develop the shallower, more 10 biodegraded, much, much more viscous, 300 centipoise to 100,000 11 centipoise oil. So the executive summary would be we're doing 12 our level best. 13 COMMISSIONER FOERSTER: Mr. Paskvan, I agree with you that 14 the shallower you get, the heavier you get, the harder it gets. 15 And I want to applaud BP and ConocoPhillips for continuing to 16 try to crack those hard nuts. And I hope that the AOGCC can be 17 a help and not a hinderance towards those ends because it is 18 part of our mission to maximize hydrocarbon recovery and 19 minimize waste. 20 MR. PASKVAN: Thank you. And I would like to say I do 21 enjoy working with your Staff and have enjoyed reviewing this 22 application with the Commission today. 23 COMMISSIONER FOERSTER: Thank you. 24 CHAIR NORMAN: Anything else? 25 COMMISSIONER FOERSTER: No. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 35 ) ) 1 CHAIR NORMAN: Thank you very much. I think you've done a 2 good job of taking a very complicated subject and probably 3 making it as understandable as is possible. 4 MR. PASKVAN: Thank you. 5 CHAIR NORMAN: This is the type of thing I'm going to have 6 to review again to internalize, but as Commissioner Seamount 7 said this is very interesting. 8 will there be any other testimony from BP? 9 MR. PASKVAN: No. 10 CHAIR NORMAN: Okay. I think what we will do is take a 11 brief recess, perhaps, five to seven minutes and we'll compare 12 notes to see if we have any final questions. We'll come back 13 on the record and then we'll conclude the hearing. 14 (Off record - 2:34 p.m.) 15 2700 16 (Tape Change) 17 Tape 2 18 0015 19 (On record - 2:40 p.m.) 20 CHAIR NORMAN: We're back on the record at approximately 21 2:40 p.m. The Commissioners have taken a brief recess to see 22 if there are any follow up questions. The consensus is that 23 the presentation was extremely thorough and well done. And the 24 Commission has a good understanding of what is being proposed 25 I and I believe we have what we need to go forward and rule upon R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 36 ) ) 1 it. 2 So we thank you very much, Mr. Paskvan and since I have 3 disclosed that your sister was a former partner of mine I will 4 also add that she is one of the smartest lawyers I've ever 5 worked with and one of the most pleasant to work with, also and 6 I hope you will give her my regards. 7 MR. PASKVAN: I certainly will, thank you, Mr. Chair. 8 CHAIR NORMAN: Commissioner Seamount, anything to add? 9 COMMISSIONER SEAMOUNT: Nope, thank you. 10 CHAIR NORMAN: Commissioner Foerster? 11 COMMISSIONER FOERSTER: No. 12 CHAIR NORMAN: Okay. with that we are adjourned. 13 (Recessed - 2:42 p.m.) 14 0060 15 16 17 18 19 20 21 22 23 24 25 R & Reo U R T R E paR T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 37 ) 1 C E R T I F I CAT E 2 UNITED STATES OF AMERICA ) ) ss. 3 STATE OF ALASKA ) 4 I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R 5 Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing Public Hearing In the Matter of the Application of BPEXPLORATION (ALASKA) 7 INCORPORATED to amend AREA INJECTION ORDER 25 and to Amend CONSERVATION ORDER 484 for POLARIS OIL POOL, Prudhoe Bay Field, 8 was taken by Suzan Olson on the 13th day of October, 2005, commencing at the hour of 1:30 p.m., at the Alaska oil and Gas 9 Conservation commission, Anchorage, Alaska; 10 THAT this Hearing Transcript, as heretofore annexed, is a true and correct transcription of the proceedings taken and 11 transcribed by Suzan Olson; 12 IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 20th day of October, 2005. 13 15 &~~)_QS:_,e. c~~\(-r-"~::. Notary Public in and for Alaska My Commission Expires: 10/10/06 14 16 17 18 19 20 21 22 23 241 25 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 Agenda 1. Application Overview 2. Recovery Processes ~ I A ?plication Overview · Modify Polaris AIO for PBU MI · Plan 4Q 2005 Start-Up · Requesting authorization for 3 Injection wells now · Future wells covered by sundry approval request · Utilize Prudhoe Bay MI · Viscosity Reducing Injection Mechanism · Operating WHP -3200 psi ~,c ~7· L Polaris Wells as of 7 /31/2005 ASR r~ Polaris Production Vilell ~ Current Well Stock 8 Producers -3 ML - 5 Conv. Frac'd 6 Injectors Activity in last year 1 M L sidetrack 1 Inj conversion Current Status All in-servce except one (L TSI Mechanical) ,-' ~ -3 Polaris AIO - 3 Proposed PBU MI Injection Wells I ¡¡...CI..~. ",- - L.,., ~ .\, ¡¡' ,u" ~ \ _ 5.978.000 "- :¿¿.~ ,~~~- ~Un II j - - ----.-- _.. --., .------. ~ 26 ~-='.... ~ -/';. ~ 30 d "'''1 -. 36 ~~ i I --.... ~.\.. .:. --'Y- r 4] 10 ..... , ~' I) 18 1:> ~~ ß·~ ... 24 19 --...... .... ..;. '" ~.... -".- .~-, ·_~-r""-_--··=, \ OR ~ ¡'{eel Uutline .. Polaris ¡;,Iool Boundary and Injection Area Area I - ---1__~_--1_--!_...l.-___1---L-I~ I I I I I I " I II I 608.000 612.000 616.000 620.060 62MOO 628.000 632.000 ;'36.000 · ~:~n Wdl Iclnclor81wthp 010 ffi,.-- -----., 1/4 MleRa_lar<ll around OJ .~ pH_.n point \. _ .J ~~:!. or...~~OPO"d POl lilt WI a nOIW'OIann/U .. ".I.u1, ..I. "'euIi.n W.. , P.IIIII H4111""". P......CII.n Well ---- 20 - 5.990.000 5.986.000 29 - 5.982,000 , S-116i ;- ~ " \ . "- ..;;] ,¡jj r'l - 5.970,000 5.966,000 17 - 5.962.000 2G ~.9:>1I.000 :>.9:>4,000 1- 2,\ \.. ' ~ rJ . \101ooI01, ~~\ 1¡~"-1 ( ~.'. ) \. ./ .-.......~_................ -it- LY- n· {¡¡ ':.,;w-'13 ~~~ . "'.'11 /.>~-----.......".. " \ ~ ~ ) \·'(:;t~ 2~) " ?- 11121." "_ .".&1 // ~._-~--¿ .,=-~ ... IY-'~t h---~ ., ""-- Ii .... - - --- J,. TREE = 4 -1/16" CI\N wau-ifAO= FM: Äë:TíJÄfoo;-·----Nï\· KB. ELEV = BO.8' Bf. B.EV = 54.4' KOf' = 300' MIx Angle = 66 @ 2341' !:Øtum t.t) = 9638' !:ØtumTVO= 5OOO'5S I 9-518" CSG, 40#, L-80, 10 = 8.835" H 4334' r-- IMlnlmUm ID = 2.81311 @ 9923' I 3·1/211 HES X NIPPLE 14-112" TBG, 12.6#, L·SO, .0152 bpi, D = 3.958" H 9630' I Fm'"ORA TDN SlJWMt\R\' REF LOO SWS VISION Resìsliviy ANG.EAT TOPPffiF: 57° @9825' /'i>Ie: Reier Ð Production œ lor historical perf data SIŒ SPF NTi:tWAL Opn/Sqz DA.II=. 4-112" 5 9825 - 9855 0 09120103 4-112" 5 9972 - 10012 0 09120103 4-112" 5 10096 ·10166 0 11/15/03 13-112" TOO, 92#, L·80, 0087 bpf, D = 2992" H 10075' I 3906' H 4-1/2" liES X NP,ID= 3813" I ~ GAS LFr tMN)R8.S I. S;15: ~~ r:1 ::~ ~ 1~~I~T1:~31 ~ WA~LOODtM~S L ST t.t) WO ŒV TYFE VLV LATCH FORT DAII: - 4 9787 5162 57 tvt.1G-W DMY AI< 0 09l21Æ)3 3 9815 5177 57 r-.tAG-W RKfS RK 11115Æ)3 2 9955 5253 58 M'oiG-W DMY AI< 0 09121Æ)3 1 9983 5268 57 M>iG-W RKFS RK 11/15Æ)3 W-215 = ;g 8---f r :::¡Ù I SAfETY NOleS: TYJica~ In-=ec-:ion We~~ =--1 1026' H 9·5/8"TAMFORTCOLLAR I " Sc -1ema-:ic 9610' H 4-112"HESXNP,D=3.813" I 9630' II 7"X4-112"B<RFREMA<R,1O=3.87S" 9638' H 4-112" X3-1J2"XO, ID = 2.930" I 9750' H 1"tMRKERJTW/RA TAG I -/ X &---I 9875' H 7" X 3-112" BKR FREM A<R, ID = 2875" I 9895' H 1"t.V\RKERJTW/RA TAG I 9923' J 3-1/2' HES X NP, D= 2.813" I 10033' H 3-112" X 4-1/2" XO, ID = 2. 930" I 10034' I I 1"X4-112"SKRS·3A<R,1O=3.87S" 10038' H 4-112" X 3-1/2" XO, D = 2.930"1 10050' H 3-1J2"HESXNP,ID=2.813" I 10060' H 3-112" tiES X NP, [) = 2813" 10083' H 3-112" WLEG, ID = 3.00- I -~-' 0 I FÐTO H 10495' I 'n~xn . IrCSG,26#, L-SO, 10=6276" H 10580' ~ DAII=. REV BY oot.t.t:Nl~ DAlE ÆV BY otl21/OS JLM/KK 0At0&NAL COMPLE1ION 10128103 ATIYTLH wF tMl'Ða OOmECllON 11/15100 MJ-flLH ~SGlNSFRt:u&GLVCIO cot.tÆNTS I 10365' HS' X 1-112" STEM w/5' SWS FIRNG HEAD I 1& 90' OF ÆRF GUNS (100' OAL) R)LA RIS LNIT WElL: W-215 PERMTNo: 2031310 AA No: 50-029-23172-00 SEe 21, T11N. R12E, 4313' NSL & 1186' WEl aP Exploration (Alaska) 5 Exhibit IV-2A: Viscosity Reduction of W-203 Oil by Prudhoe Bay MI in a Multiple Contact Experiment 100 --. Q. (.) - >- :t::: ø o (.) ø :> i .. Data P=21o~-1 *h' I I ~ I ~ L> = = = EOS I ~ t i ~, ! . Data P=1800 I ...., I I . ioi, I ==- ~ =-EOS I 10- ____u_n_ ....~~l----- __ __U~! '________ . _____ ~I~~, i '>q if 'w i ~~ ~ I ... -- ~ I Ii.i¡¡"",,,"",",,~~ ¡ "" ~ '" ~ .......... -- '"" ... -c. .......,.. - Q G.J Q ... .., ,.._ - 1 --,- 0.0 1.0 2.0 3.0 Mole PBU Mllnjected IMole Oil l2 Exhibit IV-3A: Density of Polaris W-203 Oil by Prudhoe Bay MI in a Multiple Contact Experiment -~---- ---- ----- -------- - ------ ----------~~----~------------------ ---------- W 203 PBMGP Gas Multiple Contact 1,-__ I: I I , a ¡¡¡¡¡ ¡¡¡¡¡ - . _ I __ I~ _. i w ~ ~.. ' '. I ~ ~ ~ ye ~ i OM ~ tit wl~ ~ ~_ 0.75 _H ----- - u --------- -------~--I-------- i - I ! . ~____L______ ------- ..-.. CJ CJ ........ æ "-" i í I ! 'iI ~.Iiii iòi Oil Iii I ¡ I i ! i_ G ___.__ _____.__~_+_------~---~ w. wlj~ [.¡ as I :' I i ¡",¡ 'iOJo ..... ..,.¡. >- 0.5-~ .:t:: tn C C1) C 0.25 --- ____m_.__ ------- lid ~--~--~ ~ -"'" ,"-' """ ~j - ------- i I -------- o 0.00 . I i , I , , I I I 0.50 1.00 1.50 2.00 2.50 3.00 Cum Moles Gas Injected/Mole Oil -- -- - - - - -------~ ------------------------- -------------------- ----- ----- i ---~ Gas-Oil Density q Exhibit IV-4A: W-203 Oil Slimtube Experiment with PBU MI at Reservoir Temperature ~_.~~~ W203 Slim Tube Recovery versus Pressure 1 ø g P .. , 1- p- I I ~ý>~øø I ! I _... , , ... I :=- I I 4Y .1 ¡ t-' s: 0.9 -.-- -- ----·-r-----·--------t-----~ ~ ø ~---~-I-~-~----. -- ~ I! ~~., I i I ,... I ø: ! ~ I ~~q i ' ~ 0.8 - -- ---.------ ----t-~-- --- q> ...--I~----~ ! 8 I ¿; q I -- --~--- CI) I q . Data , a: I ~ ~ I II I .. - EOS i == ., , ¡ ! C-=------=--=----r.J ~ 0.7 '.' -- - - ----~--r--·-----------¡------------I ~ ~ I ! 4' II I tit'" I I ¡ I ----- t ,I ß i -------- ----- 0.6 -- 2000 i i I I I I 2500 3000 3500 4000 4500 5000 Pressure (psia) ;"."..~;..'.4'";;""i'·..=~7.=:.tIi:....,.-~"=~=.~==....~.,=< -.- - -- .' '3 Exhibit IV-5A: MMP Vari·ation with Oil C7-C13 Concentrations --- --------------- --------- -------.-------------- ~- ----------- -- ------- Viscous Oil MMP ~ 1.10 , ¡ i W200 OBed, 20 0/oC7-C13, MMP 2250 psia 1.00 ------- n_ ------------~--:--~-----I~ ____~ -. ~..~==~~J.-=---=-----~~---=-- j ~ i ~ ------ I L.. - - ..~~.~~~.~~ T ~~----'"--...~~=<.=""T' ~ 0.90 -------- -1'--1-. -u/~t\ -~---- ----- ,..: 0.80 ----- _________u______ t--------~---+..-· W205 OA, '100/0 C7-C13, MMP 3200 psiar IH\ I! '::!I I! ------r------------+------- ~----------~----- u : ~ ! a: 0 60 -- --- n__ ~----+-----~-------------1-----------n-----u--------i- ..J. -u______n__ · I I I I· W205 OA , I I . O ¡ Iii 0.5 --------------------I--------------T----~----¡-l. W200 OBcd------- I I I ~ i : ¡ I I -~~ 0.40 -- 1500 2000 2500 3000 3500 4000 Pressure, PSIA ---. -- - -. -----.-- ------ -------.-------- ------ ---------- I ----__~__J o Exhibit V-6A: ncrementa Oil with Prudhoe Bay M njection for Polaris Oil with Medium to High Viscosity Range -l I I I Recovery Incremental Oil ,-/ .~ 25 20 15 10 5 ..-.. ?fl. "'-" ~ Q) > o u Q) a: o - 0.0 o I .0 1 0.4 0.6 0.8 HCPV (PBU MI + Water) Injected .. 0.2 Total ,-' '-' ;~ J"h ._. " .,,,,,,,l,,. ".~.," ,-,' .. :--,',1'''''4'';¡'*;¡:;'~ . · Oil Phase -Medium Viscosity ;~~1 ,~; - Gas Phase -Medium Viscosity Oil ;~\ ~ Oil Phase -High Viscosity Oil -~] -~ Gas Phase -Medium Viscosity Oil J it(~~~~~~~f~~"~~~iiì~~~~~~I~~~~ 10 1 1 Exhibit V-7A: Phase Viscosity after 0.5 HPV PBU M Injection Oil Viscosity During 1-D Displacement 1000 100 o. c. (J i: UJ o (J .!!æ > CI) UJ co J: C. UJ co " ... - 6 r I 1 Producer 0.8 0.6 Distance Along Slim Tube 0.4 0.2 0.01 . 0 InJector Exhibit IV-1A: POP Production and Recovery Profiles with Water and PBU Miscible Gas Injection - - -------- ------------------------------ I -e- WF+MI I! c- -- -- -.. WF O~!J 14,000 Oil Production 12,000 ~ 10,000 -e 8,000 ~ ~ C':I 6,000 " Ô 4,000 2,000 ~ " ~ o I _ 99 04 09 19 14 24 29 Year --.- -----------~-----~ ----- ----- -----------~ Gas ------- I ~.:..- MI Injection, mscfþd : __ Production, mscfþd L_- GOR. scf/stb 99 04 09 14 19 24 29 Year --------- .--. -------------- 34 ¡----- ! I I I ¡ ~ I ..c B ------ -..;.- I~ection, bwipd __ Production, bwpd l ----------1 I I I I I Water 45,000 ! 40,0001 35,000 ~ 30,000 ~ 25,000 - " 20,000 ð:s ~ 15,000 ~ 10,000- 5,000 ,-/~k- ;~.L._~:;'-.!a~r..A ./- /' .,ß ~/~ !~"'i."~/¿- .r ~ -~~ f .Y"' = ,j . _.--?\ 99 04 09 14 19 24 10000 - 9000 8000- ~. 7000 u g 6000 5000 - 4000 . 3000 - J~ 2000 - 1000 - Nt \4, ~ 1..1-. ¡¡¡-~-'¡'¡-"''-ioHJ-'''-:';-'--~~ o ï ......~.....a:, , I Year -~--- ----------------- ~-~-- ----~ Oil Recovery, Field Pressure 25% ¡-.--- -----~ i-Recovery To Date I 20% - i __ Recovery Forecast ~ i . ¡ ~ Field Pressur~ Model ~ 15% - ;;.0 ~ u ~ ~ 10%- ð 5% - 0% - 99 04 09 14 19 24 29 Year ----- --------~----- ~ 29 34 ¡ I I ____---1 2500 2400 ô.. 2:f ::;) ~ 2300 ~ £: I-< - 2200 .~ I-< ~ CJ} ~ -- 2100 ~ 2000 34 /2 A ?p:ication · Modify Polaris AID for PBU MI Injection · Requesting authorization for 3 Injection wells now - ~ /3 ') ) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Modification of Area Injection Order #25 Polaris Oil Pool October 13, 2005 at 1 :30pm NAME - AFFILIATION (PLEASE PRINT) Del J.::.1 l~lI.j -,;;¡ lor- t(¡e..s-r JONATf.lM tJiLLIAMS ~ 1\ ~ ¡.\ -r 'I-(A" é~ AOLroV\ L..;' e)C-'~L J¿fP hí'/' R Y dfl.J ( te~i ~·f:5 ~ ~\.tVlvr' ~ ' Ai é~&?"'4f' ~'f- PMWM ADDRESS/PHONE NUMBER TESTIFY (Yes or No) ,Ii . ~r,57~( /YØ2::;k<íh'¿'ZG~r Á~~ 4k- jI]? I :3100 J<Z-o/Q4 6~{~ AAJ1c}" Ak. 531-û¿ô 2030 RE:J Stz£ [¡R.iLE J 4V1("~ Ài( ~I¡.b" 7753 tJ 0 ) &,2.0( Ii e,«-dlo-vt. lc¡ C#,r .' A 1'\ ~t, /1'< '3L¡ b '-1- ì1-¿ 366'6 j;ãsfw¡~t"I,(J..... A/J¿lf AR ~6'¥·-.]~~.þP J J /J ¡'$o'l µ., ßrtJJ~f(AJhÞíÍ IJJlJl.slll~ ¡*/19f4çý 357,-12.17 \ 0 6~ ~ L¿~t:-~,~~\-lt.. ( Ä .L qq -Sl ") ~ w 4 o'S; ~ 3 ~dt¿é ~µ~ /(,Zbo ¡t!üb~ PI>;'Ii;,~C.,A K 1(41- /Va iV" A~ ¡Va No ,( "\ #1 STATE OF ALASKA ) NOTICE TO PUBLISHER ') ADVERTISING ORDER NO. ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02614009 F AOGCC R 333 W 7th Ave,Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT DA TE OF A.O. Jody Colombie PHONE September 1, 2005 PCN (907) 793 -1 ??1 DA TES ADVERTISEMENT REQUIRED: ¿ Anchorage Daily News PO Box 149001 Anchorage, AK 99514 September 6, 2005 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal D Display Advertisement to be published was e-mailed D Classified DOther (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TO AnchoraQ'e. AK 99S01 AMOUNT DATE TOTAL OF PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS REF TYPE NUMBER 1 VEN 2 ARD 02910 3 4 ~IN AMnllNT ~v r.r. C)f:M Ir. Ar.r.T ~v NMR DIST UQ 05 02140100 73451 2 3 R~QUISITIONEDBl) 1oDÛlMJ\----- ê DIVISION APPROVAL: ) ') Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Prudhoe Bay Field Polaris Oil Pool Application to amend Area Injection Order 25 Commission proposal to amend Conservation Order 484 By application dated August 23, 2005, BP Exploration (Alaska) Inc. as Unit Operator of the Prudhoe Bay Unit requested the Commission to amend Area Injection Order 25 ("AIO 25") to authorize underground injection of enriched gas into the Polaris Oil Pool. The Polaris Oil Pool of the Prudhoe Bay Field lies within T12N-R12E, T12N-R13E, T11N-R13E, T11N-R12E, Umiat Meridian. Also, the Commission on its own motion proposes to amend Conservation Order No. 484, Rule 7, to add enriched gas injection as an approved enhanced recovery operation; and Rule 9, to update reporting requirements to include results of enriched gas injection, and proposes to consolidate within Conservation Order No. 484 all related existing orders affecting the Polaris Oil Pool. The Commission has tentatively scheduled a public hearing on this application for October 13,2005 at 1:30 pm at the offices of the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on September 23, 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 September 27,2005. 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 ih Avenue, Suite 100, Anchorage, Alaska 99501. Protests and comments must be received no later than 4:30 pm on October 10, 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 October 13, 2005 hearing. If you are a person with a disab'1t}who may need special accommodations in order to comment or to attend the8:UbliC alrinr~se contact the Commission's Special Assistant Jody Colombie at 793-1221. , , Jor "K}:~' yc'· ~ . an J '-- ./ Published Date: 9//6/05 AO: 02614009 ) Anchorage Daily News Affidavit of Publication ') 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 592649 09/06/2005 02614009 STOF0330 $200.64 $200.64 $0.00 $0.00 $0.00 $0.00 $0.00 $200.64 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 Anchora~e, Alaska, and it is now and durin~ all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental 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. Notice of Public Hearing STATE OF ALÀSKA Alaska Oil aridGàsConseryationCommissiòn Re: Prudhoe. Bay Field . Polaris Oil Pool' APpliëâtiontoamend AredlniectionOrder 25 Commission proposal to amend Conservation Order 484 By application däted August 23,:2005, BP Explo: rati.o!) {Alaskallnc.as Unit Operator of the >PrUde hoe B.aY Unit requested the Commissiori to amend Area !:niection Order 25( II Alo.25'~J t'oaÙthorize under:ground. in ¡ection.Of ~ni"ichedgasinto the. Po- laris Oi I·PooI-The· Polaris Oil pool of the Prudhoe Bay.Héldlies Within T'12N-R12E¡ Tl2N,"R13Ei TllN-R13E, TlrN.'R12E, Umiat Meridian. Also, the CommTo;;o;;ion'on it,> ()wn m'()fiOI1 DrODo,>p.s<to'amend C(n,'';>rllOllor, Qra...r N.J J¡J RUlE-' 10 add en- r,cnea «;10, ,r"<,,cr,or, 0;, on oJpprO'Jed ...l1honc"'d·¡:.'" c':'Jer', üperOI,(r, or,CI Rule 9 10 LlPClole rE-t·c.rlirog r",au,r..m...nr:, ro inc luCl':- rf.'~ull::. 01 el1r,'=.hed gas In, II:'C lion, ar,a pr'JP.J;''''", 10 con,allCloTe ",,,Inln Con~t:r' ,ol,on Ora..r ~hJ J8J 011 r",lal..d ",~I~tin... ,)rdêrsaf- I".(t,ng Ihe- p"lor,¡, lJoI POOl STATE OF ALASKA THIRD JUDICIAL DISTRICT Teresita Peralta, being first duly sworn on oath deposes and says that she ìs an advertising representative of the Anchorage Daily News, a daily newspaper. TheCQl11rnissIon. has tentatively scheduled a pub- lichearing on this application for Dctober 13, 2005 at1.:30~rnat·the()ff¡ces of the Alaska Oil and Gas Conserv.ation cornmission,at 33~ vv~st7't~Avenµe, ,Suite 100, ~nchor'age/'Alask( 99501. 'Äp'ersOilmOy request th.at the tentatively s,cheduled hearing be heldb.y .filinga written requestwith.the Commis- sion no later than 4:30 p·m'on September 23, 2005. Subscribed and sworn to me before this date: () ¡ j ...:/5?1: t'1'Y'I Jc (ilL ()¡ I "Itì -- :7\.. ~. J{~ ) I:i' a 'rt:a'~}~s't ':'~'~~:'i:~' he~"~~~'n~'·i~~:" ~ot', 'f¡'n,'èì'Y"~f¡led'l "the ~~;::'I;~~~~na ~~~r~~;S'?o"'~,,~~~ il;st~~n¿~~~~~sr:~ 'Noll nold Ine PLlblic hE'or,ng pleo~,E-call 7'93-1221af~ If.or S"pl...mcer 21 ~005 In Oddit¡'Ori'abo?rson may submit a y..,ritten pro- l""sl or VIIr.rl.:-r, cornmell';; regarding this appliea.- I,on all( prOPo.ol 10 I he Alaska·Oil and Gas Con- ;.er/or,on COrTIm,,:, ¡,an at 333.West7'th'Ayenue, Su,r.. 100 Ancnc.r09ë . "'laska99501.Protests'and comments must be received no.J(ter than 4: 30 pm on October 10, 2005 except thanfthe .Commission decides.to hold a public hearing/protests or com- ments must be received no Idter than the conclu- sionoftheOctober 13, 2005 heàring. If YOU ore a person with a disability who may need speCial accommodations in order to com- ment or to attend the public hearing, please con- tact the Commission's Special Assistant Jody Co- lombie at 7'93-1221. John K.Norman Chairman Signed YtJ~)qJ Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska , J J MY COMMISSION EXPIRES: ()Cj/l.':f /.9J)(7(·,' 7(( , / I' \lU((((( IJI ",; I ' , ~, I \\\\ ERlY "I';'"r. I . ) J, i. IJ II G. .. ,\ ....t..9. . . · . :4. ..... ~ I " I ..........~"'ff'~....... . -,... ",. I ¡,' r I , .' ..1 1+ J "i . T. . .. .. ~ -:::. ;I''} 1.// /I}f< .7c.tt ~rj ./ I - /-7] 1..:i.C~ I ·fl.· \-\OT~.. .~-:. ./ t ./ //\...... ..... J.. ¿::. ./",./ ,I ~~. , ._ " ...X :.1 / ==~ . tC. - --"" -=~.. '1.... : ~ -.~ .. . ~ % ··.~Ot:ALJ.~·~~ ~....' Þ':-:.· w,.:A. <'-. ~....' ;.I.,) ~; ~", '.IlJ/JJ"'" AD: 02614009 Publish: 9/6/05 Ke: Public Notice ') ) Subject: Re: Public Notice From: "Ads, Legal" <legalads@adn.com> Date: Fri, 02 Sep 2005 11 :36:31 -0800 To: Jody Colombie <jody_colombie@admin.state.ak.us> Hello Jody: BE SURE TO CHECK OUT THE LEGAL NOTICES ON-LINE. WE RECENTLY CREATED NEW LEGAL SECTIONS ON-LINE ESPECIALLY FOR THE STATE OF ALASKA. WE ARE OFFERING A 90 DAY FREE TRIAL ON ALL LEGAL ADVERTISING AS OF MAY 9TH TO PROMOTE OUR NEW ON-LINE, USER FRIENDLY CATEGORY'S. PLEASE TAKE THIS TIME TO TRACK YOUR CUSTOMERS AND SEE IF ON-LINE ADVERTISING IS RIGHT FOR YOU. 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: 592649 Publication Date(s): September 6, 2005 Your Reference or PO#: 02614009 Cost of Legal Notice: $200.64 Additional Charges: . Web Link: E-Mail Link: Bolding: Total Cost To Place Legal Notice: $200.64 Your Legal Notice Will Appear On The Web: ~~~_.:.3_~.~..~._~gJ:0.._:_. 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: ~~g~l9ds@adn.cQæ Phone: (907) 257-4296 Fax: (907) 279-8170 On 9/2/05 7:18 AM, "Jody Colombie" <jody colombie@admin.state.ak.'J.s> wrote: Please publish on 9/6/05. I of 1 9/6/2005 8:34 AM 02-902 (Rev. 3/94) Publisher' ) lal Copies: Department Fiscal, Departmf" ) ~eiving AO.FRM STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO-02614009 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC 333 West ih Avenue. Suite 100 A nr.nnT:::top A K QQ",O 1 907-793-1221 AGENCY CONTACT DA TE OF A.O. R o M Jodv Colombie Sentember 1. ?005 PHONE PCN (907) 793 -1 ??1 DA TES ADVERTISEMENT REQUIRED: T o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 September 6, 2005 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 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 02-90 I (Rev. 3/94) AO.FRM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil I nformation Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 ) Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Schlumberger Drilling and Measurements 2525 Gam bell Street #400 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ) David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 'ubllC NotIces ::;wanson Klver tleld and Pl:SU Polaris ) ') Subject: Public Notices Swanson River Field and PBU Polaris From: Jody Colombie <jody_colombie@admin.state.akus> Date: Fri, 02 Sep 2005 07:20:38 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.akus>, Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.okus>, 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>, j briddle <jbriddle@marathonoil.com>, shaneg <shaneg@evergreengas.com>, j darlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <markdalton@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 1. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl 1. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gcLnet>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, bocastwf <bocastwf@bp.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hanl<.alford@exxonmobil.com>, Mark Kovac <yesnol@gcLnet>, 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>, 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.akus>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan _ hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.akus>, bpopp <bpopp@borough.kenai.akus>, 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 lof3 9/2/2005 7:51 AM Jublic Notices Swanson Kiver FIeld and PHU Polaris ') ) <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 <n1617@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>, 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 <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 1. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl 1. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, 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 N ady <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>, Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, loren_Ie man <loren_Ieman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan _ hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustria1.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 ~ of3 9/2/2005 7:51 AM fJublic Notices Swanson Kwer FIeld and PHU Polans ) ) <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unoca1.com>,jack newell <jack.newell@acsalaska.net>, James Scherr <james_scherr@yahoo.com>, david roby <David.Roby@mrns.gov>, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, Jerry Dethlefs <n1617@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@honeywel1.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Todd Kratz <T oddKratz@chevron.com>, Gary Rogers <gary _ rogers@revenue.state.ak.us>, Arthur Copoulos <A.rthur_Copoulos@dnr.state.ak.us>, Phillip Ayer <pmayers@unocal.com>, Ken <ken@secorp-inc.com> Content-Type: application/pdf Polaris Public Notice.pdf Content-Encoding: base64 Content-Type: application/pdf SwansonRiver Public Notice.pdf Content-Encoding: base64 30f3 9/2/2005 7:51 AM 'ub lIe N otlee ) ) Subject: Public Notice From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Fri, 02 Sep 2005 07:16:15 -0800 To: Legal Ads Anchorage Daily News <legalads@adn.com> Please publish on 9/6/05 I i Content-Type: application/msword lAd Order form.doc I Content-Encoding: base64 I i Content-Type: applicationlpdf SwansonRiver Public Notice.pdf C E . b 64 , ontent- ncodlng: ase i of 1 9/2/2005 7:51 AM