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Home My WebLink AboutCO 457 BCONSERVATION ORDER 457B Prudhoe Bay Field Aurora Oil Pool 1. March 25, 2004 BPXA’S application to expand Aurora Area Pool Rules (confidential exhibits held in secure storage) 2. April 2, 2004 Notice of Public Hearing, Affidavit of Publication, email distribution list, mailings 3. April 12, 2004 BPXA’s supplemental information 4. October 19, 2005 BPXA’s proposed Aurora EOR expansion 5. August 31, 2006 Prudhoe Bay – Annual Surveillance reporting requirements to AOGCC 6. May 23, 2007 Annual Surveillance Reporting Requirements (CO457B.002) 7. October 4, 2007 BPXA’s request for down-hole commingling of production from Aurora and Prudhoe Pools (oil tracers held confidential) (CO457B.003) 8. October 4, 2007 Notice of Public Hearing, Affidavit of publication, email distribution, mailing list 9. -------------------- Emails regarding request 10. April 29, 2009 BPXA’s letter and results of the collected surveillance data from the commingled production from Aurora Oil Pool and PBU (oil tracers held confidential) 11. September 30, 2013 BPXA’s letter regarding recently discovered lapse in reporting requirements 12. March 3, 2014 BPXA’s report regarding commingled production for well S-26 13. May 11, 2015 BPXA’s request for spacing exception to rule 1 (Exhibit 3 held confidential) (CO457B.004 corrected) 14. November 2, 2015 Request for admin approval for waiver of monthly reporting of daily production allocation data (CO 457B.005) 15. October 23, 2018 Request for admin approval for conforming PBU Satellite Pool Rules for Consistency (CO 457B.006) 16. February 24, 2020 BPXA Request to amend CO 492 rule 3(a) and 6(a) (co457B.007) 17. May 21, 2020 Notice of Hearing and mailing 18. ----------------- Emails 19. December 17, 2021 Request for admin approval to amend CO 457 Rule 1 (CO 457.008) ) ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Conservation Order No. 457B EXPLORATION (ALASKA) INC. ) for an order expanding the affected ) Prudhoe Bay Field area of the Aurora Oil Pool, ) Aurora Oil Pool Prudhoe Bay Field, North Slope, ) Alaska ) June 25, 2004 ) Corrected August 9, 2004 IT APPEARING THAT: 1. BP Exploration (Alaska), Inc. ("BPXA") by application dated March 26, 2004, applied for expansion of the affected area for the Aurora Oil Pool ("AOP") rules as defined in Conservation Order ("CO") No. 457 A; 2. BPXA provided supplemental information at the Commission's request on April 12, 2004; 3. Notice of a public hearing, tentatively scheduled for May 6, 2004, was duly published in the Anchorage Daily News on April 2, 2004; and 4. No requests for hearing or objections concerning the application were received. FINDINGS: 1. CO 457 A defines the AOP and sets out rules governIng its development and operation within a specified area. 2. BPXA proposes to expand the operation and development of the pool beyond the area specified in CO 457 A. 3. Subsurface wireline log data, pressure measurements, and newly reprocessed seismic data all indicate that the AOP extends beyond the area specified in CO 457 A to encompass the additional area proposed for development. 4. No reason appears why the rules set out in CO 457 A should not also apply to operation and development of the AOP in the additional area proposed for development. 5. CO 492 establishes requirements for managing annular pressures for all pools within the Prudhoe Bay Field, including the AOP. No reason appears why the requirements established in CO 492 should not be integrated into a single conservation order governing the AOP. ) Conservation Order 457.8 August 9, 2004 ') Page 2 6. Administrative Approval ("AA") 457 A.O 1 was issued to clarify requirements for maximum allowable annular pressure. No reason appears why the provisions of this Administrative Approval should not be integrated into a single conservation order governing the AOP. 7. AA 457A.02 permanently approved the use of the Prudhoe Bay Unit Western Satellite Production Metering Plan for production allocation and set out reporting requirements under this plan. No reason appears why the provisions of this Administrative Approval should not be integrated into a single conservation order governing the AOP. CONCLUSIONS: 1. The area subject to pool rules governing the development and operation of the AOP should be expanded to encompass the additional area proposed for development and indicated by subsurface well data, newly reprocessed seismic data, and reservoir pressure data acquired to date as being within the AOP. 2. All rules and approvals issued by the Commission for AOP operation and development should be consolidated into a single conservation order. 3. The record for this order includes the hearing records and administrative files related to Conservation Orders 457, 457 A and 492 including administrative approvals issued under those orders. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes and replaces CO 457 dated September 7, 2001, CO 457 A dated May 15, 2003, and - as to the Aurora Oil Pool only - CO 492 dated June 26, 2003. The findings, conclusions and administrative record for Conservation Orders 457, 457 A and 492 are adopted by reference and incorporated in this decision. The following rules, in addition to statewide requirements under 20 AAC 25, to the extent not superseded by these rules, apply to the Aurora Oil Pool within the following affected area: Umiat Meridian Township Range~ UM TI1N-RI2E Sections TI2N-RI2E Sec 2: Wl/2 Sec 3: All Sec 4: El/2, NW 1/4, E1/2SWI/4 Sec 5: El/2NEl/4 Sec. 9: NEl/4, Nl/2SE1/4 Sec 10: NWl/4SW1/4, Wl/2NWl/4 Sec 15: Sl/2SE1/4, SW1/4 ') Conservation Order 457B August 9, 2004 ) Page 3 Sec 16: NW1/4, S1/2 Sec 17: S1/2, NE1/4 Sec 18: SE1/4 Sec 19: N1/2 NE1/4 Sec 20: E1/2, N1/2NW1/4 Sec 21: All Sec 22: All Sec 23: S1/2, S1/2NW1/4,S1/2NE1/4 Sec 25; S1/2, S1/2NW1/4 Sec 26; All Sec 27: All Sec 28: All Sec 29: E1/2NE1/4, SE1/4 Sec 32: E1/2 Sec 33: All Sec 34: All Sec 35: All Sec 36: All Rule 1. Well Spacine (C0457" 9/7/01) Spacing units within the pool shall be a minimum of 40 acres. 20 AAC 25.055(a)(1) and (2) shall not apply to property lines within the external boundaries of the Aurora Participating Area. Rule 2. Casine and Cementine Practices (C0457" 9/7/01) a. In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75 feet below the surface. b. In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500 feet tvdss below the permafrost. Rule 3. Automatic Shut-in Equipment (C0457" 9/7/01) a. All wells must be equipped with a fail-safe automatic surface safety valve system capable of detecting and 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 to control subsurface flow. The Commission may require such installation by administrative action. ") Conservation Order 457B August 9, 2004 ) Page 4 c. Safety valve systems must be maintained in good working order at all times and must be tested a minimum of once each six months or according to such other schedule as is prescribed by the Commission. 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 shall be applied to adjust total AOP production. c. All wells must be tested a minimum of once per month. All new AOP 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. d. Technical process review meetings with the Commission shall be held at least annuall y. e. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for the Commission's review and evaluation. Rule 5. Reservoir Pressure Monitorine (C0457" 9/7/01) a. Prior to regular production or injection, an initial pressure survey shall be performed in each well. b. The minimum number of bottom-hole pressure surveys performed each year shall equal the number of governmental sections within the AOP that contain active wells. A minimum of four such surveys shall be conducted each year in representative areas of the AOP. Bottom-hole surveys conducted pursuant to paragraph "a" of this Rule may be used to fulfill the minimum requirement. c. The reservoir pressure datum will be 6,700 feet 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, and open-hole formation tests. ) Conservation Order 4)lB August 9, 2004 ) Page 5 e. Data and results from all reservoir pressure monitoring tests on surveys must be reported to the Commission 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. f. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph "e" of this Rule. Rule 6. Gas-Oil Ratio Exemption (C0457" 9/7/01) Wells producing from the AOP are exempt from the gas-oil-ratio limits of 20 AAC 25.240 (a) so long as the requirements of20 AAC 25.240 (b) are met. Rule 7. Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations (C0457 A" 5/15/03) Water and enriched hydrocarbon gas injection are authorized to enhance oil recovery within the AOP . Average reservoir pressure must be maintained above minimum miscibility pressure. Expansion of miscible gas injection outside of the North of Crest and West Blocks must be administratively approved by the Commission prior to long- term injection. Commission approval is required prior to implementing major changes in reservoir depletion strategy. Rule 8. Reservoir Surveillance Report and Depletion Plan Update (C0457A" 5/15/03) An annual reservoir surveillance report for the prior calendar year shall be filed with the Commission after one year of regular production and annually thereafter. The report shall include, but is not limited to, the following: a. Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation techniques; b. V oidage balance by month of produced fluids and injected fluids and cumulative status by major fault blocks; c. Summary and analysis of reservoir pressure surveys within the pool; d. Results, and where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; ) Conservation Order 457B August 9, 2004 ') Page 6 e. Review of pool production allocation factors and issues over the prior year; and f. Review of the Annual Plan of Operations and Development including discussion of the reservoir depletion plan and the current status of reservoir repressurization activity. Rule 9. Production Anomalies (C0457" 9/7/01) In the event of oil production capacity proration at or from the Prudhoe Bay Unit facilities, all commingled reservoirs produced through the Prudhoe Bay Unit facilities shall be prorated by an equivalent percentage of oil production, unless it is determined by the Commission that this will result in surface or subsurface equipment damage. Rule 10. Administrative Action (C0457" 9/7/01) Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this Order as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles. Rule 11. Well Mechanical Inteerity and Annulus Pressures (C0492" 5/26/03 and AA457.01" 7/29/03) a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement 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, unless prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2000 psig or (ii) sustained outer annulus pressure that exceeds 1000 psig. ) Conservation Order 457B August 9, 2004 ) Page 7 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 c. 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 immediately notify the Commission 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 the Commission to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph "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 that (i) the inner annulus pressure at operating temperature will be below 2000 psig, and (ii) the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph "c", but not paragraph "e", of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph "c", unless the AOGCC prescribes a different limit. Rule 12. Definitions For purposes of these rules; a. "inner annulus" means the space in a well between tubing and production casing; ') Conservation Order 457B August 9, 2004 ') Page 8 b. "outer annulus" means the space in a well between production casing and surface casing; c. "sustained pressure" means pressure that (i) is measurable at the casing head of an annulus, (ii) is not caused solely by temperature fluctuations, and (iii) is not pressure that has been applied intentionally. Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., lOth day after the application for rehearing was filed). ;' (, il) ¡::r~' \",", ~ òJ) ~ -,:;,..¡' t::=--J r:.::] HIÞ '~.~ L~ ') rmrç L, ~ fK~ ! '~1 L! L ¡~ (~l'J, fl/7, iI\ ü' i" Iln II In\ ~ ~~ in1 ,) I / / ,/ FRANK H. MURKOWSK/, GOVERNOR AlASKA. OIL AND GAS CONSERVATION COMMISSION 333 W. ¡rH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 August 9, 2004 To: AOGCC notice distribution list Re: Correction to Conservation Order No. 457B Not infrequently, the Commission amends a conservation order that prescribes pool rules for a specific pool. F or ease of reference and to minimize confusion, it has been the Commission's recent practice to incorporate such amendments from time to time in a comprehensively revised version of the underlying conservation order that supersedes and replaces the previous version of the order. This ensures that all applicable pool rules are set out in a single document and avoids the necessity of reviewing multiple orders relating to a single pool. On June 25, 2004, the Commission issued such a comprehensively revised order prescribing pool rules for the Aurora Oil Pool, in the form of Conservation Order No. 457B. One of the sources of amendments to the previous version of this order was Conservation Order No. 492, which established rules governing sustained annulus pressures for all pools within the Prudhoe Bay Field, including the Aurora Oil Pool. Conservation Order No. 457B stated that it "supersedes and replaces CO 457 dated September 7, 2001, CO 457A dated May 15, 2003, and CO 492 dated June 26, 2003." Since CO 492 affects other pools in the Prudhoe Bay field in addition to the Aurora Oil Pool, this statement is not correct. Conservation Order No. 457B supersedes and replaces CO 492 only insofar as CO 492 concerns the Aurora Oil Pool. Conservation Order No. 457B has no effect on CO 492 as to any other pools. Conservation Order No. 457B has been corrected accordingly. A copy of the corrected version is attached. / SCANNED AUG 2 4 2004 CO's ') ) lof2 8/10/20042:15 PM CO's ) ) ". ."...........,..,..,."...... ...,..............'..,..".........,..."..., ".."".""...........,."""."...",.",..."..",..,,,'.'., "..",.""""".....".".,...",..""""".",..,"",.."."...."...........". ,: ,i Content-T)'pe: application/ms\vord ,! ! C0528.doci ¡I i i Content-Encoding: base64 ,[ ~.::.~'::,':,~':::::::::::.~':::::::~::::~':::::::::.~::::::::::::::..,'::::::::::::..::.~::::::::::::::::::::.':.::::::::::::::::::.~:':::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::,':::::::::::::::.~'::::::::::::::::::::::::,~::::::::::::::.~'::::,':::::::,'::::::::::::::::::.. r:::::':,:,:::::,~',:::::::,:::,:::::::::::':,:::::,::':::,~'::':,::::'::::',:',:::',::~'::::::, '_'~'~"'~'_"_""""""'''~'''''_4''~'''''.__''''''''.''...,..,....._......,...... 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Content-Type: application/msword corrected.doc Content-Encoding: base64 " ,: Content-Type: application/msword i C0527.doci 'I j l Content-Encoding: base64 i ~,:::::::::::.',.:.':::.':::,'::::::::::::..:;:.','::.'::::::::::::::::,'.:..,'::::::::::::,':::,'::.':: ::.',':::..:::::::::::..::::.':::::.~.,.:::::::::::::::.'::,'::::,'::::::.':,'::;:.':::::::.',',':::::::::.'.'::.',',.::::,':::::..:::::::,':::::,':::,':::..... :::.'.·.'::,·::.',·:::.·::.:..t co 457 correction cover Content-Type: applicationlmsword Content-Encoding: base64 20f2 8/10/20042:15 PM ) ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Conservation Order No. 457B EXPLORATION (ALASKA) INC. ) for an order expanding the affected ) Prudhoe Bay Field area of the Aurora Oil Pool, ) Aurora Oil Pool Prudhoe Bay Field, North Slope, ) Alaska ) June 25, 2004 IT APPEARING THAT: 1. BP Exploration (Alaska), Inc. ("BPXA") by application dated March 26, 2004, applied for expansion of the affected area for the Aurora Oil Pool ("AOP") rules as defined in Conservation Order ("CO") No. 457 A; 2. BPXA provided supplemental information at the Commission's request on April 12, 2004; 3. Notice of a public hearing, tentatively scheduled for May 6,2004, was duly published in the Anchorage Daily News on April 2, 2004; and 4. No requests for hearing or objections concerning the application were received." FINDINGS: 1. CO 457 A defines the AOP and sets out rules governIng its development and operation within a specified area. 2. BPXA proposes to expand the operation and development of the pool beyond the area specified in CO 457 A. 3. Subsurface wire line log data, pressure measurements, and newly reprocessed seismic data all indicate that the AOP extends beyond the area specified in CO 457 A to encompass the additional area proposed for development. 4. No reason appears why the rules set out in CO 457 A should not also apply to operation and development of the AOP in the additional area proposed for development. 5. CO 492 establishes requirements for managing annular pressures for all pools within the Prudhoe Bay Field, including the AOP. No reason appears why the requirements established in CO 492 should not be integrated into a single conservation order governing the AOP. 8C!~NNEC JUN 2, 92004 ),' Conservation Order 457 "- June 25, 2004 ') Page 2 6. Administrative Approval ("AA") 457A.Ol was issued to clarify requirements for maximum allowable annular pressure. No reason appears why the provisions of this Administrative Approval should not be integrated into a single conservation order governing the AOP. 7. AA 457A.02 permanently approved the use of the Prudhoe Bay Unit Western Satellite Production Metering Plan for production allocation and set out reporting requirements under this plan. No reason appears why the provisions of this Administrative Approval should not be integrated into a single conservation order governing the AOP. CONCLUSIONS: 1. The area subject to pool rules governing the development and operation of the AOP should be expanded to encompass the additional area proposed for development and indicated by subsurface well data, newly reprocessed seismic data, and reservoir pressure data acquired to date as being within the AOP. 2. All rules and approvals issued by the Commission for AOP operation and development should be consolidated into a single conservation order. 3. The record for this order includes the hearing records and administrative files related to Conservation Orders 457, 457 A and 492 including administrative approvals issued under those orders. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes and replaces CO 457 dated September 7, 2001, CO 457 A dated May 15, 2003 and CO 492 dated June 26, 2003. The findings, conclusions and administrative record for Conservation Orders 457, 457 A and 492 are adopted by reference and incorporated in this decision. The following rules, in addition to statewide requirements under 20 AAC 25, to the extent not superseded by these rules, apply to the Aurora Oil Pool within the following affected area Umiat Meridian Township Range~ UM TIIN-RI2E Sections TI2N-RI2E Sec 2: W1/2 Sec 3: All Sec 4: E1/2, NW 1/4, E1/2SW1/4 Sec 5: E1/2NE1/4 Sec. 9: NEl/4, N1/2SE1/4 Sec 10: NW1/4SW1/4, Wl/2NW1/4 Sec 15: S1/2SE1/4, SW1/4 Sec 16: NW1/4, S 1/2 I:,!¥\'?:"J""" "IU' fl.! 2 "", 2nn ",' 'j ~ v ~jI uu4 Conservation Order 457.L. ) June 25, 2004 ) Page 3 Sec 17: S1/2, NE1/4 Sec 18: SE1/4 Sec 19: N1/2 NE1/4 Sec 20: E1/2, N1/2NW1/4 Sec 21: All Sec 22: All Sec 23: S1/2, S1/2NW1/4,S1/2NE1/4 Sec 25; S1/2, S1/2NWl/4 Sec 26; All Sec 27: All Sec 28: All Sec 29: E1/2NE1/4, SE1/4 Sec 32: E1/2 Sec 33: All Sec 34: All Sec 35: All Sec 36: All Rule 1. Well Spacine (C0457" 9/7/01) Spacing units within the pool shall be a minimum of 40 acres. 20 AAC 25.055(a)(I) and (2) shall not apply to property lines within the external boundaries of the Aurora Participating Area. Rule 2. Casine: and Cementine Practices (C0457" 9/7/01) a. In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75 feet below the surface. b. In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500 feet tvdss below the permafrost. Rule 3. Automatic Shut-in Equipment (C0457" 9/7/01) a. All wells must be equipped with a fail-safe automatic surface safety valve system capable of detecting and 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 to control subsurface flow. The Commission may require such installation by administrative action. c. Safety Valve Systems must be maintained in go04 working order at all times and must be tested a minimum of once each six months or according to such other schedule as is prescribed by the Commission. 5C!-\N~\!ED ,JUN 2· 9 2004 Conservation Order 457 L ) June 25, 2004 ) Page 4 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 shall be applied to adjust total Aurora Oil Pool production. c. 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. d. Technical process review meetings with the Commission shall be held at least annually. e. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for the Commission's review and evaluation. Rule 5. Reservoir Pressure Monitorine (C0457" 9/7/01) a. Prior to regular production or injection, an initial pressure survey shall be performed in each well. b. The minimum number of bottom-hole pressure surveys performed each year shall equal the number of governmental sections within the Aurora Oil Pool that contain active wells. A minimum of four such surveys shall be conducted each year in representative areas of the Aurora Oil Pool. Bottom-hole surveys conducted pursuant to paragraph "a" of this Rule may be used to fulfill the minimum requirement. c. The reservoir pressure datum will be 6,700 feet 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, and open-hole formation tests. e. Data and results from all relevant reservoir pressure surveys must be reported 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. JUN 2 9 2D04 Conservation Order 457L ) June 25, 2004 ) Page 6 Rule 9. Production Anomalies (C0457" 9/7/01) In the event of oil production capacity proration at or from the Prudhoe Bay Unit facilities, all commingled reservoirs produced through the Prudhoe Bay Unit facilities shall be prorated by an equivalent percentage of oil production, unless it is determined by the Commission that this will result in surface or subsurface equipment damage. Rule 10. Administrative Action (C0457" 9/7/01) Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this Order as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles. Rule 11. Well Mechanical Inteerity and Annulus Pressures (C0492" 5/26/03 and AA457.01" 7/29/03) a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement 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, unless prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2000 psig for all other development wells, or (ii) sustained outer annulus pressure that exceeds 1000 psig. SCÞJNNEr,ì JUN 2 9 2004 ",) Conservation Order 457 L- June 25, 2004 ) Page 5 f. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph d of this Rule. Rule 6. Gas-Oil Ratio Exemption (C0457" 9/7/01) Wells producing from the AOP are exempt from the gas-oil-ratio limits of 20 AAC 25.240 (a) so long as the requirements of20 AAC 25.240 (b) are met. Rule 7. Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations (C0457 A" 5/15/03) Water and enriched hydrocarbon gas injection are authorized to enhance oil recovery within the Aurora Oil Pool. Average reservoir pressure must be maintained above minimum miscibility pressure. Expansion of miscible gas injection outside of the North of Crest and West Blocks must be administratively approved prior to long-term injection. Commission approval is required prior to implementing major changes in reservoir depletion strategy. Rule 8. Reservoir Surveillance Report and Depletion Plan Update (C0457A" 5/15/03) An annual reservoir surveillance report for the prior calendar year shall be filed with the Commission after one year of regular production and annually thereafter. The report shall include, but is not limited to, the following: a. Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation techniques; b. V oidage balance by month of produced fluids and injected fluids and cumulative status by major fault blocks; c. Summary and analysis of reservoir pressure surveys within the pool; d. Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; e. Review of pool production allocation factors and issues over the prior year; and f. Review of the Annual Plan of Operations and Development including discussion of the reservoir depletion plan and the current status of reservoir repressurization activity. SC¡:~NNEG JUN 2 9 2004. Conservation Order 457.... ) June 25, 2004 ) Page 7 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 c. 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 immediately notify the Commission 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 the Commission to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph 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 (i) that the inner annulus pressure at operating temperature will be below 2000 psig for all other development wells, and (ii) the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph "c", but not paragraph "e", of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph "c", unless the AOGCC prescribes a different limit. Rule 12. Defmitions For purposes of these rules; a. "inner annulus" means the space in a well between tubing and production casing; <' ~, ~ :1'""",..... I U N; 2 n '1oe ~1 ·.::··\I~~<\l!t:"ì.) J ¡ ,ì} L "-Vi Conservation Order 457.L ) June 25, 2004 ) Page 8 b. "outer annulus" means the space in a well between production casing and surface casing; c. "sustained pressure" means pressure that (i) is measurable at the casing head of an annulus, (ii) is not caused solely by temperature fluctuations, and (iii) is not pressure that has been applied intentionally. ~ :..,.~, " ~ y Daniel T. Seamount, .J(, Commissioner Alaska Oil and Gas Conservation Commission d AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., lOth day after the application tòr rehearing was filed). SC/\N~'~EC JUN 2 5' 200Ll. 6/25/2004 4:00 PM 1 of 1 ··.:"J¡~EJJ JUN 2 g 2004 C0457B.doc' Content-Type: applicationlmsword Content-Encoding: base64 "",...................".."...........,..,...".........".....".......,......."........".....".."..,..............,..........."..........,.......,..,..,......",..,.......,..,'.."",.",.."."...."....".,....,...,.,...,.....",...,.,.,........".....".,.""",.".",' ....._-_..._--_........._..._..._........._...._.~.--...._......--.....................------............--..........--.----.....--....-..---....-........-.....--....--.-...........---................- Oops. I didn't mean to send you 22C again. Its CO 457B Subject:C0457B From: Jody Date: Fti,25Jun 2004 15:59:53 -0800 ') ) C0457B CO 457B ) ) lof2 ~;~~J\~H",EL\ . ¡UN 2 9 LOOt} 6/25/2004 4:00 PM CO 457B ) ) Content-Type: applicationlmsword C0457B.doc Content-Encoding: base64 ...................................., '~('j··¡\.\~"E·-1 \ ¡lJN 2· ~ 20Dl~ ~~_~b'i~~I'\j .""..... t..... ' ,!'J.:I 2of2 6/25/2004 4:00 PM ) ') Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, W A 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 ¡f}mkd j' (p 1~'3 /cf~ 5CAN~\!Er:" .j!"JN 'l q ?on/l • • 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 Aiip Daniel T. Se. r' ou , r., Commissioner, Chair j it . • ss Conservation Commission "A ULL, , i`i L i ` s' ��iman, Co der \IF • . . a Conserva ion Commission a il lit aOil 2 1 4 /l . 1 A. m► 41. 1 - . `4 cob 1W ii 7 a1 A. Cat y P. oerst r, Commissioner Alaska • 11 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 rants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of g g P Y Y PP the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, January 11, 2011 4:08 PM To: Ballantine, Tab A (LAW); '(foms2 @mtaonline.net)'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; 'caunderwood'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'daps'; '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 Moriarty'; 'Julie Houle'; 'Kari Moria , Y 'Ka nell 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 (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjr1; '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.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk @alaska.gov); Pasqual, 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 Sa4'uxintha' f± A to(47ca OW a Ca-nwvc to-►vC (90 7)793 -1223 (907)276-7542 (f c ) 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 President 408 18 Street 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 h 7 E P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. 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 <1;7) 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 "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.2659(b); 2 "I njec ti on wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(1); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Kuparuk 596 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit Raven 570 5 yes sign on wellhead 25. m wA deactivated SVS was replaced with requirement to maintain a deactivated SVS; si 9 ( ) tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.26r .> "Injection (exc di injectors) must be equipped with(i) a double check valve (a); 25 25 on we Check valve requirements for injectors are not covered by Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); 'Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection 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; 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) 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 permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; Milne Point Unit Schrader Bluff 477 5 yes injection well require SSSV or injection valve below permafrost; test 25.265(h)(5) N/A replaces SSSV nipple requirement for all wells every 6 months Prudhoe Ba Unit Borealis 471 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells 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); a ) ; 25.265 ( b ) ; 25.265 ( d )( 1 ) " The minimum setting depth for a 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 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double arrangement or (t) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include p check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Midnight Sun 452 6 yes flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells - fail -safe auto SSV and SCSSV; SSSV may be installed above or below 25.265(a); 25.265(b); 25.265(d)(1); The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip 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 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 (i) 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 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 m 25.265(a); 25.265(b); 25.265(h)(5); deactivated SVS was replaced with requirement to maintain a Kuparuk River Unit; to on well when not manned; administrative approval CO 2526.5 Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP 25.265(m) N/A 9 pP Milne Point Unit may be defeated on W. Sak injectors w /surface pressure <500psi w/ ( ) 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 <500psi) Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Revised Rule - "Well safety valve systems" (2) Comment Unit/Field POol Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reqts from Order fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Milne Point - Sag fail -safe auto SSV; injection wells require double check valve; test Check valve requirements for injectors are not covered by Milne Point Unit 423 7 no 25.265(a); 25.265(b); 25.265(h)(5) "Injection wells must be equipped with a double check valve arrangement." readopted regulation every 6 months River , fail -safe auto SSV; gas /MI injectors require SSV and single check Check valve requirements for injectors are not covered by valve and SSSV landing nipple; water injection wells require (i) double "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve readopted regulation; readopted 25.265(d)(5) does not include 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 SSSV requirement for MI injectors; administrative approval CO Kuparuk River Unit Kuparuk - West Sak 406B 6 no 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 defeated on West Sak water injectors with surface injection pressure less than 500psi." 4068.001 remains effective [re:defeating the LPS when surface injectors w /surface pressure <500psi w/ notice when defeated and injection pressure for West Sak water injector is <500psi] placed back in service fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A Badami Badami 402B 6 yes submit test results electronically within 14days; SVS defeated /removed 25.265(m) only if well SI or pad continuously manned fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission 25.265(m) tag on well when not manned fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must be maintained and tested as part of SVS; sign on well if SVS 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; N/A Prudhoe Bay Unit Prudhoe 341E 5 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells prescribed by Commission fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; N/A Prudhoe Bay Unit Niakuk 329A 5 yes deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be rermoved as part of 25.265(a); 25.265(b); 25.265(d); Readopted 25,265(d) dictates which wells require SSSV; N/A Prudhoe Bay Unit Pt. McIntyre 317B 8 yes routine well ops w/o notice 25.265(1); 25.265(m) replaces SSSV nipple requirement for all wells fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit West Beach 311B 6 yes w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork West Fork (Sterling 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A A &B) Requirement to maintain a wellhead sign and list of wells with fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); N/A deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Lisburne 207A 7 yes w /deactivated SVS; test as prescribed by Commission 25.265(m) tag on well when not manned suitable automatic safety valve installed below base of permafrost to 25.265(d) N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 yes prevent uncontrolled flow replaces SSSV nipple requirement for all wells AOGCC Policy - SVS Failures; issued by order of the Commission policy dictating SVS performance testing 25.265(h); h ) ; 25.265(n); n ) ; 25.265 ( o ) N/A Commission 3/30/1994 (signed by Commission Chairman Statewide N/A N/A N/A yes requirements Dave Johnson) Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded Page 2 of 2 • • Public Hearing Record And Backup Information available in Other 66 ~:fÆ~E:'F !Æ~!Æ~~«!Æ AlASIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NUMBERS C0457B.OOl and AI022C.OOl Mr. Oil Beuhler OPB Waterflood Resource Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Beuhler: By letter dated October 19, 2005, BP Exploration (Alaska), Inc. ("BPXA") requested authorization to extend current pilot miscible injection (MI) operations in the Aurora Oil Pool ("AOP") to the full area of the AOP. Rule 9(c) of AIO 22C and Rule 7 of CO 457B require that administrative approval be obtained prior to long term injection of MI in wells outside of the North of Crest and West Blocks of the AOP. On May 11, 2004 the Commission approved pilot MI injection into wells S-112, S-110, and S-116, which lie outside of the North of Crest and West Blocks. On December 22, 2004, the Commission extended these pilot operations to September 30, 2005. MI slugs have been injected into six wells in the AOP. Offset producers to all these injectors have shown some beneficial response. In addition, MI injection has a beneficial effect upon injectivity of water, and reservoir pressures are increasing as a result. The Commission approves injection of MI throughout the AOP area subject to the conditions of AIO 22C and CO 457B and statewide regulations under 20 AAC 25 (to the extent not otherwise superseded by AIO 22C and Conservation Order 457B. AIO 22B Rule 9 (c) and CO 457B Rule 7) are amended to eliminate the restriction of MI injection to only the North of Crest and West Blocks. As provided in AS 31.05.080(a), 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 orwe~kend. A person may not appeal a Co mission decision to Superior Court unless. reheari~~~~~..Q.~.:~. requested ß~~d. r\ t,;).l'..¡ ..-.:1 ,"':~:., . #?:.. ~.~~. \~:.~. ." ,;. \o\J..~..'~.......,.~-; ,..... .,~ /;,. þ ... ~N (? or e, Alaska and..dated Nove ber I 2005. /~~~~"5';\ \: /> ....j /~ Ánrj / l . Ø'/':/ ¡ 1.. ",,1 ~I JA /' ..7/ '. {'~~<"~',.. ~ . .. / ~ .~ ...." ¡ t. " I .. ;".,. ;I' J orman Daniel T. SeamóÚnt, Jr. Cathy p' :~, {?f~~f:~: '.' .,::// Chairman Commissioner Commiss '~~"~~lf~:'~>:;"::'/ ,:;c;:..,:.:,,,.,.:f;d;it ~lJ!;Efs~i~i~Í" ..... :04578.001 and AI022C.00l PBU Aurora Oil Pool Subject:C0457B.OOl andAI022C.00l PBUAuroraOÜPool From: Jody Col011lçie <jody _colombie@admin.state.ak.us> Date: Thu, 10 No\!, 2005 15:36:11-0900 " ":," "',I",', "'l'i"1 '1'"'''11''' " " "I',',~', ',','" ,,""'1'1"1 " ""',"',',',,',"" ,,""'111'1"'" "', ", ;"'11,,1" '," ).", ""'11',(," 1;0 :,I( "",,' ',' ,"'ø~ðseâ4~~'" "I,': ¡em,II!,!'!IIII::::', ,'""" :"""",1"':'1"1"""'11'''11''''''''1,'J:;""""'~!I","""''''I''''''''II', '1",1,1,1,",'. ""'~"""1I""'I'II"'"''I''''' "'11"','11' ',,"I' B'~, ,;:::',:1: ,11.,,1.' I I'., """\:B!¡:': ': ,:', II, 'IrI!J i,,:,:'I'''I.I'''I'''!:I',I'' " "I"II,"'III:'I"'i," '~I"" ~rôbè,' ,Ii ,,'" ".'" 'lå' ":" I',':"', """"""":""",,"'1.,,, , ",:,,':'II""III'I'¡',II';'I"',' ' <::1.." 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"':""I..'.'I,;~",,:;I~I:'I ".'1:1, ,I, ."'['1.,.1........,,, : ' <gary~ sçhu~~@4fu'~stªt~~ak.l1:~>,:W~me. ~~çi~~S~CJþR@p~p'0-cai}a4Alç~~ßin:,I\1~Jlÿ(,' <Bil1_Miller@}{~ofilas~~.cQm>, .'~r~dön.(}~grt(}h.f~,gågnqn@b~eIlalaw.cPrn~;'~.ª#I"WmsJ()w··., .. <pmwinslow@f()~~~~?~l.c0l!l> ~Ga1TYG~tron<c~~'01?-gr@bp.com>, Shanp.~~~ q~P~!~9: ,.... . <c?pela~y@~p~90~> ~,~i~tigPfrk~~kri,s!~n~ClJ~lc~@,~.~tat~:*.u~~ ,ISay:nep. ?;~m,~,:):';;",.l::·\,'::,"l""'..'." <kJzemaµ@marath0no~1.C9II1>, John T ()\\l~'Sq~'}()~r®~~a.doe;g()v>, Bill F()~I~ '. . e" <Btll ~r8~1~~($atl~d~tçq.ÇqM?',....y~1l~ .,~.~~.. .tt~~~~;,~~~~!99~m~,9P~~;I:.,,~P9n~:~~~wck <scottcranswick@mms,gov>, Brad McKiro<mçkitnbs@BP.cpm>, Steve LatJ1be' 'i ,. , <larnþes@µt1.pçal,pom~,j.~~~..·..~~,W~11··.<j~c~·~~~~U@~2~~~~~.~~~~,' J~~~i .~,~þ~~"':":':"""::"'.";':":'::'.·..··'i:··' <james 'sçherr@yahoo.çQµt>~david roby <Pªvi4J~,obY@J11.nis.gov>, Tim Lawlor':'\,,:':;~:':':" :',,' <Til11_ [~t\v!or'@~];ltn~'goy;,' .·L~aà"Kåhi1"<L~~à:Rähp@'fWs'~gôv>:·JêiTYj?~tliI~fs,i':i·;:":',""'.'..".' <Jeqy.ç.I),¥@~f!$,@ÇPnQçºpmllipª..9q~~,J ~ITY,;P~®~fs <11.1 Q 1'1 @con9qºPÞ.iJlj¡?~~çQm~,!:"':::·:."',: ' 1 of2 11/10/2005 3:39 PM 11/10/2005 3 :39 PM 20f2 C0457B.00 1 and AI022C.00 1 PBU Aurora Oil Pool Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,lD 83702 Kay Munger Munger Oil I nformation Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedm an Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 . ~~~~Œ (ffi~ ~~~~[K\~ . AIfASIiA. OIL Alftþ GAS CONSERVATION COMMISSION 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 457B.002 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 8 Reservoir Surveillance and Depletion Plan Update of Conservation Order 457B - Prudhoe Bay Field, Aurora 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 8 Reservoir Surveillance and Depletion Plan Update is amended to read as follows (additions are in bold and [deletions are bracketed]): Rule 8. Reservoir Surveillance Report and Depletion Plan Update An annual reservoir surveillance report for the reporting period agreed upon by the Commission and the operator[prior calendar year] shall be filed with the Commission on a schedule agreed upon by the Commission and the operator[ after one year of regular production and annually thereafter]. The report shall include, but is not limited to, the following: a. Progress of enhanced recovery project implementation and reserVOlf management summary including results of reservoir simulation techniques; b. V oidage balance by month of produced fluids and injected fluids and cumulative status by major fault blocks; c. Summary and analysis of reservoir pressure surveys within the pool; d. Results, and where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; CO 457B.002 May 23,2007 Page 2 of2 . . e. Review of pool production allocation factors and issues over the prior year; and f. Review of the Annual Plan of Operations and Development including discussion of the reservoir depletion plan and the current status of reservoir repressurization activity. As provided in AS 31.05.080, within 20 days after written notice ofthis 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. 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 200706:39:39 -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>, trmjr 1 <trmjr l@aol.com>, jdarlington <jdarlington@forestoil.com>, nelson < on@petroleumnews.com>, k Dalton <mark.dalton@hdrinc.com>, Shannon D y <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Ski '<SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <Rossbe BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon P il <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP. , Mikel Schultz <Mikel. ultz@BP m>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl leppin" <KleppiDE@B m>, "Jan . 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>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesno l@gci.net>, gspfoff <gspfoff@aurorapoweLcom>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred. steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, j ej ones <j ej ones@aurorapoweLcom>, 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 Katz <jwkatz@alaskadc.org>, t rk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, Jim 'te <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@aurorapoweLcom>, 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 <rogeLbelman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Karl Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>" Gary Rogers <gary _rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <klyons@otsintl.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@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@kbbLorg>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <cammy_taylor@dnr.state.ak.us>, Thomas E Maunder <tom _ maunder@admin.state.ak.us>, Stephen F Davies <steve _ davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoil.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg 10f3 5/24/2007 6:40 AM Various Administrative Approvals for North S, . <jim_regg@admin.state.ak.us therine P Foerster <cathy_foerster dmin.state.ak.us>, gregory micallef <micallef@clearwire. Silliphant <laura _ silliphan nr.state.ak.us>, David Steingreaber <david.e.steingreaber nm' .com>, akpratts@ac a.net, . Campbell <Robert.Campbell@reuters.com>, Steve Moot <steve_moothart@dnr.state.ak. 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 <WF eatherly@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 <jimwine arner@brooksrangepetro.com>, Matt Rader <mattJader@dnr.state.ak.us>, carol smyth <caroLs shell.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoil.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@international.gc.ca>, Cary Carrigan <cary@kfqd.com>, Sonja Frankllin <sfranklin6@bloomberg.net>, Mike Bill <Michael.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, "Alan Birnbaum <\"\"Alan J Birnbaum \">" <alan_birnbaum\"@law.state.ak.us>, Randall Kanady <Randall.B.Kanady@conocophillips.com>, MJ Loveland <N1878@conocophillips.com>, Dave Roby <daveJoby@admin.state.ak.us>, James B Regg <jim _regg@admin.state.ak.us> Jody Colombie <iody colombie(â?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: application/pdf C0311B-002.pdf Content-Encoding: base64 Content-Type: application/pdf C0570-002.pdf . Content-Encodmg: base64 Content-Type: application/pdf C0471-006.pdf . Content-Encodmg: base64 Content-Type: application/pdf C0484A-001.pdf Content-Encoding: base64 20f3 5/24/2007 6:40 AM Various Administrative Approvals for North. . 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 ~a\ \~~J 101 • • SARAH PALIN, GOVERNOR Q taL[~-7~ OIIJ ~ ~ 333 W. 7th AVENUE, SUITE 100 C01~5FRQATI011T CO1~II~II55I021T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. CO 457B.003 ADMINISTRATIVE APPROVAL NO. CO 341E.005 Mr. Frank Paskvan BPXA Resource Manager, PBU West Satellites BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Mr. Scott Digert BPXA Resource Manager, PBU Waterflood BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: BPXA request to commingle production from the Aurora Oil Pool and Prudhoe Oil Pool in Well 5-26 Dear Mr. Paskvan and Mr. Digert: By letter dated October 4, 2007, BP Exploration (Alaska) Inc. ("BPXA") requested that the Alaska Oil and Gas Conservation Commission ("Commission") authorize commingled production from the Aurora Oil Pool and Prudhoe Oil Pool in Well 5-26. The Commission published a notice of opportunity for public hearing on November 15, 2007 at 9:00 am in the Anchorage Daily News. No requests for a hearing or objections to BPXA's application were received. 20 AAC 25.215(b) 20 AAC 25.215(b) states: "Commingling of production within the same wellbore from two or more pools is not permitted unless, after request, notice, and opportunity for public hearing in conformance with 20 AAC 25.540, the Commission (1) finds that waste will not occur, and that production from separate pools can be properly allocated; and (2) issues an order providing for commingling for wells completed from these pools within the field." Proposal Well 5-26 produces 200 barrels of oil per day ("BOPD") to 250 BOPD from the Prudhoe Oil Pool at an approximately 75% watercut and frequently experiences downtime because of paraffin • • CO 457B.003 CO 341E.005 November 27, 2007 Page 2 of 3 and hydrate deposition. On November 14, 2007, BPXA submitted a sundry to workover the well to enable combined Prudhoe and Aurora Oil Pool production. To estimate the production contribution of each pool, BPXA proposes to use geochemical sampling and production log results along with regular well testing. Geochemical analyses performed by Oil Tracers L.L.C, on mixtures of oil from Well 5-26 (Prudhoe Oil Pool) and Well 5-109 (Aurora Oil Pool) showed that the Prudhoe and Aurora Oil Pool oils are sufficiently different in composition to allow for use of geochemical fingerprinting as an allocation tool. The testing of the oil mixtures showed that allocation accuracy within 94-96% certainty is possible. Geochemical analysis has been successfully used to allocate production from the Raven and Niakuk Oil Pools in Well NK-43 (C0329B.003). Benefits Compared to the current Well 5-26 Prudhoe Oil Pool production, commingling the production of the Prudhoe and Aurora Oil Pools should add approximately 490 stock-tank barrels per day and lower gas lift requirements by 2 million standard cubic feet per day. The higher rates should result in warmer flowing temperatures and less downtime caused by paraffin and hydrate deposition. Crossflow is anticipated to be minimal during production, and given the completion design, zonal isolation will prevent crossflow during long shut-ins. Findings and Conclusions Commingling production from the Aurora and Prudhoe Oil Pools in Well 5-26 will not result in waste; in fact, the proposed project will likely increase overall recovery from the two pools. Based on pilot testing in Well NK-43 and the geochemical reports provided with BPXA's application, the Commission finds that the use of geochemical sampling and production log results, along with regular well testing, should result in the proper allocation of production from the Aurora and Prudhoe Oil Pools. The interests of the Prudhoe Bay Unit working interest owners are integrated. The royalty owner is the State of Alaska, and the royalty rate is uniform for the Aurora and Prudhoe Oil Pools. Hence, commingling production from these pools raises no correlative rights issues. Order CO 457B and CO 341D are hereby amended to add the following rule: Rule 13 (in CO 457B) and Rule 18 (in CO 341 D) Commin ling of Production in the Same Wellbore Commingling production from the Aurora and Prudhoe Oil Pools in Well S-26 is approved on the condition that BPXA allocates production to the separate pools using the geochemical test, production log, and regular well test results outlined below: a. Prior to commingling production in Well 5-26, a bottom-hole static reservoir pressure and production test must be obtained and geochemical sampling and analysis must be performed on oil from the Aurora Oil Pool (in isolation from the Prudhoe Oil Pool). • CO 457B.003 CO 341 E.005 November 27, 2007 Page 3 of 3 r~ b. For the first six months after commingled production starts, geochemical sampling and analyses must occur monthly at the time stabilized production tests are performed. Thereafter, geochemical sampling and analysis must occur at least twice per year and not less frequently than once every seven months. c. Production logs must be obtained and compared to the geochemical and regular well test results within the first two months and again six months after commingled production starts. Thereafter, production logs or isolated well tests of each pool must be obtained when major changes in production characteristics occur which could result in less accuracy in allocation of gas or water to the separate pools. d. In addition to the other requirements of Rule 4 of CO 457B, the monthly reports required by Rule 4(e) of CO 457B must identify the Well 5-26 production allocated to the Aurora Oil Pool and Prudhoe Oil Pool. e. The volumes reported on Form 10-405-i. e., in accordance with 20 AAC 25.230(b)- must identify the Well 5-26 production allocated to the Aurora Oil Pool and Prudhoe Oil Pool. £ A summary report documenting the results and effectiveness of the commingled production allocation must be provided to the Commission within 9 months after the start of commingled production and shall include the results of the production allocated to the Aurora and Prudhoe Oil Pools, along with the analyses of the geochemical tests, production logs, and regular well tests. g. Unless a public notice and hearing are required, the Commission may administratively waive or amend the requirements of any .rule as long as doing so would 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. All other Rules in CO 457B and CO 341D remain in effect. As provided in AS 31.05.080, within 20 days after written notice of this order, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. To be timely, the application must be received by 4:30 p.m. on the 23`d day following the date of this order, or on the next working day if the 23`d day falls on a state holiday or weekend. This decision may not be appealed to the Superior Court unless the Commission has received a timely, properly filed application for reconsideration. DONE at Anchorage, Alaska and dated November 27, 2007. e a it and Gas Conservation Commission ~ + ~y L'~ . J n Daniel T. Seamount, Jr. Cathy . Foerster m ~~ Commissioner Commissioner Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, November 28, 2007 1:43 PM Subject: co 4576.003 and co341 e.005 PBU Attachments: co457b-003.pdf; co341e-005.pdf BCC:McIver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff; Arion, Teri A (DNR); 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'carol Smyth'; 'Cary Carrigan'; 'Catherine P Foerster'; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil ; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; keelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant ; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay';'Wayne Rancier' Attachments: co457b-003.pdf;co341 e-OOS.pdf; 11/28/2007 • Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503. Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department ~ PO Box 129 Barrow, AK 99723 ~1 I ~~ J ~~ ~I STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska) Inc. for an administrative waiver of the spacing requirements of Rule 1, Conservation Order No. 45713-Corrected to drill, complete, and produce development oil well Prudhoe Bay Unit No. S-44A at spacing of less than 40 acres within the Aurora Oil Pool. IT APPEARING THAT: Docket Number: CO-15-002 Conservation Order No. 457B (Corrected)-004 Prudhoe Bay Unit No. S-44A Development Oil Well Aurora Oil Pool Prudhoe Bay Unit North Slope Borough, Alaska June 2, 2015 1. BP Exploration (Alaska) Inc. (BP), by letter received May 14, 2015, requested an administrative waiver of the spacing requirements of Rule 1 of Conservation Order No. 45713-Corrected (CO 45713-Corrected) to drill, complete, and produce development oil well Prudhoe Bay Unit No. S-44A (PBU S-44A) at spacing of less than 40 acres within the Aurora Oil Pool. 2. Pursuant to Rule 10 of CO 45713-Corrected, the Alaska Oil and Gas Conservation Commission (AOGCC) may administratively waive the requirements of any rule or administratively amend any rule in CO 45713-Corrected as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles. 3. Owners, landowners, and operators of properties within 1,000 feet of the proposed well are BP, Chevron U.S.A. Inc., ConocoPhillips Alaska, Inc., ExxonMobil Alaska Production, Inc., and the State of Alaska. Pursuant to 20 AAC 25.055, BP sent notice of the application to these parties by certified mail on May 14, 2015. BP provided evidence of certified mailing (i.e., Domestic Return Receipts) on May 19, 2015. 4. No protests to the application, comments, objections or request for hearing were received. 5. Because BP provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. FINDINGS: 1. BP owns and operates the Aurora Oil Pool within the Prudhoe Bay Field and the PBU S- 44A development oil well, which are located in the North Slope Borough, Alaska. 2. PBU S-44A will be an onshore development oil well with a surface location 4,502' from the east line and 4,242' from the south line of Section 35, T12N, R12E, Umiat Meridian (U.M.). The top of the productive interval is expected to lie 4,345' from the east line and 847' from the south line of Section 27, T12N, R12E, U.M. The bottom -hole is projected to be 4,176' from the east line 2,828' from the south line and of Section 27, T12N, R12E, U.M. Conservation Order 457B Corr; -004 June 2, 2015 Page 2 of 2 The surface location of PBU S-44A will be located within State of Alaska lease ADL- 028257. The top of the productive interval and total depth of the well lie within State of Alaska lease ADL-028258. 4. PBU S-44A will be drilled to a structurally advantageous location to access an unswept portion of the Aurora Oil Pool reservoir that cannot be efficiently produced from existing wells. CONCLUSIONS: 1. An administrative waiver of the well spacing provisions of Rule 1 of Conservation Order No. 45713-Corrected is necessary to allow drilling, completion, and production of the PBU S-44A development oil well within the Aurora Oil Pool at a location that will maximize resource recovery. 2. PBU S-44A will recover reserves in the Aurora Oil Pool that are not accessible to other existing wells. NOW THEREFORE IT IS ORDERED: BP'S application for an order granting an administrative waiver of the well spacing provisions of Rule 1 of CO 45713-Corrected to allow drilling, completion, and production of BP'S PBU S-44A development oil well within the Aurora Oil Pool is hereby approved provided BP complies with the terms of all lease agreements, Alaska law, and all other legal requiremgAu.., DONE at Anchorage, Alaska and dated June 2, 2015. Cathy . F erster 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. Radrer, 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: Colombie, Jody J (DOA) Sent: Wednesday, June 03, 2015 9:11 AM To: DOA AOGCC Prudhoe Bay; Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Guh►, Meredith D (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWeIIIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); 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; ddonke►@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock, ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Hume, Rebecca E (DNR); Jacki Rose; Jdarlington (jar►ington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; 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 Landt, Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petro►eumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffieid@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; 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; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; 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; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke Subject: co457b corrected.004 Attachments: co457b corrected.004.pdf Prudhoe Bay Unit No. S-44A James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Carl Lundgren Richard Wagner Darwin Waldsmith West Satellites Subsurface Team Leader P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99519-6612 Sc� AA 3 , '.ZC� '�:Z, Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil a,,-iid Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.505B.001 CONSERVATION ORDER NO.457B.005 CONSERVATION ORDER NO.341F.001 CONSERVATION ORDER NO. 471.008 CONSERVATION ORDER NO.452.003 CONSERVATION ORDER NO.484A.003 CONSERVATION ORDER NO.559.011 CONSERVATION ORDER NO. 570.009 CONSERVATION ORDER NO.329B.004 Ms. Diane Richmond Performance and Data Management Lead, Alaska Reservoir Development BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 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 341F; - Rule 4(g) of CO 471; - Rule 7(d) of CO 452; CO 505B.001, CO 457B.005, CO 341F.001, CO 471.008, CO 452.003, CO 484A.003, CO 559.011, CO 570.009, CO 329B.004 January 7, 2016 Page 2 of 3 - Rule 4(d) of CO 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 341 F, Rule 10 of CO 471, Rule 13 of CO 452, Rule 13 of CO 484A, Rule 11 of CO 559, Rule 14 of CO 570, and Rule 5 of CO 329B.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 457B, the monthly reports required by Rule 4(e) of CO 457B must identify the Well S-26 production allocated to the Aurora Oil Pool and Prudhoe Oil Pool. Rule 4(f) of CO 50513, Rule 4(e) of CO 45713, Rule 4(g) of CO 471, Rule 7(d) of CO 452, Rule 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 341F, part(d) of Rule 7 of CO 452, part (e) of Rule 4 of CO 457B, part (g) of Rule 4 of CO 471, part (d) of Rule 4 of CO 484A, Part (f) of Rule 4 of CO 505B, part (f) of Rule 4 of CO 559, and part (d) of Rule 6 of CO 570are revised as follows: The operator shall submit a review of pool production allocation factors and issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Rule 4 of CO 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. 5� OIL �o Cathy . Foerster Daniel T. Se ount, Jr. Chair, Commissioner Commissioners TION 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 run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Ms. Diane Richmond Richard Wagner Darwin Waldsmith Performance and Data Management Lead, P.O. Box 60868 P.O. Box 39309 Alaska Reservoir Development BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99519-6612 ztnv@c-(I 'Id) 20\lam 011�scs-� 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.wallace@alaska.gov); AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; Becky Bohrer; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jennifer Williams; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; John Easton; Jon Goltz; Juanita Lovett; Judy Stanek, Julie Houle; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laney Vazquez; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer (meg.kremer@alaska.gov); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; Mike Mason; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Steve Moothart (steve.moothart@alaska.gov); Suzanne Gibson; Tamera Sheffield; Tania Ramos; Ted Kramer, Temple Davidson; Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr; Graham Smith; Greg Mattson; Hak Dickenson; Heusser, Heather A (DNR); Holly To: Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen 1 (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Marie Steele; Matt Armstrong; Mike Franger; Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Susan Pollard; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: CO 505B.001, CO 457B.00S, 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-00I.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 r 4C 0Itst4"ti } tt7f' i)Zit llhrii,71 CONFIDENTIALLTY NOTICE.,. This e-mail message, including any, attachments, contains info.nnatitm from the Alaska Oil. and Gas Conservation Conunission (AOGCQ, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The miauthorized. review, use or disclosrere of such information .may violate: state: or federal law. if you are an unintended recipient of this e-mail, please: dEiieti: it, without first saving or fortivarding it, and, so that the AOGCC is aware of the .mistake in sending it to you, contact Sainan:tlia Carlisle at (�X17) "; R3-1223 or Samanth Carhsle@,ilaska.Zov. 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 Wes} Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. a o g c c. a l a s k a. g ov 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 of 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 Commingling (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 AIO 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 AIO 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 Monitorin (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 lin 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, 1A, 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. . %( I..L DONE at Anchorage, Alaska and dated May 29, 2019. , rs: Daniel T. Seamount, Jr. J ie L. Chmielowski Commissionermmissioner 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 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. T 11[ S] ATI ,,ALASKA _ _ SKA G c'�VERIJOR NII, HA61. I DUNI.LiIT 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. 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 www.aogcc.olcskc.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 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 Commingling (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 AIO 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 Monitorin 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 Commin line 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 AIO 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 ComminLpline 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, 1A, 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. �4�'0 §J. t //signature on file// //signature on file// Daniel T. Seamount, Jr. Jessie L. Chmielowski"+hpNu Commissioner Commissioner 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 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. 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 THE STNIT 01 ILIL 1SK GOVERNOR MIKE UUNLEAV'Y Mr. Oliver Sternicki Alaska Oil 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.aogcc.olo5ka.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, LLCI (HNS) applied to modify Conservation Order No. 492 (CO 492) to raise the inner annulus (IA) 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)2. CO 492 was issued on June 26, 2003 and applied to all pools in the r 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 IB.004, 317B.003, 329A.002, 341I.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 psig to 2,100 psig 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 207D Lisburne 457B Aurora 484A Polaris 505B Schrader Bluff 559A Put River 570 Raven Rules being replaced 15 11 and 123 11 11 10 12 3 In the current CO 457B, the pool rules for the Aurora Oil Pool, Rule 11 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 311B West Beach 14 317B Pt McIntyre and Stump Island 17 329A Niakuk 13 3411 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-OIA 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.002,31113.004,317B.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 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 prig, 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. 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 DleiftaY lgnfd by pte Date: z.20l ora M. Price Ias9s0 ae'oo Jeremy M. Price Chair, Commissioner Daniel T. Diybilly`,-dby tamer seamwm.n. Seamount, Jr'°aeaolatem 1100%6 -0BVO' Daniel T. Seamount, Jr. Commissioner RECONSIDERATION AND Digitally signed by J1s512 L. Jessie L. Chmielowski Chmielowski Date: 2020. 10.01 12:22:07 -08'00 Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. lite AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days atter it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOOCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 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. 457B.008 December 21, 2021 Ms. Kyndall Carey, Land Representative Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: CO-21-026 Request for Administrative Approval to Amend Well Spacing for the Aurora 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. 457B 1 (CO 457B) to remove the 40-acre well spacing requirement and allow for unrestricted interwell spacing for the Aurora Oil Pool. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp’s request. CO 457B was issued on August 9, 2004. It superseded CO 457, which was issued on September 7, 2001, and CO 457A, which was issued on May 15, 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 AOP. 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 457B 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 AOP development to be optimized and correlative rights to be protected. 1 The letter referenced Conservation Order No. 457 but that order has been superseded by Conservation Order No. 457B. CO 457B.008 December 21, 2021 Page 2 of 2 Now therefore it is ordered that Rule 1 of CO 457B is repealed and replaced by the following: Rule 1. Well Spacing There shall be no well spacing restrictions within the Aurora 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 13:48:13 -09'00' Dan Seamount Digitally signed by Dan Seamount Date: 2021.12.21 14:29:14 -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 19 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. 457 (Prudhoe Bay Field Aurora 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. 457 (September 7, 2001) 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 Aurora 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. 457 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 Sean Wagner at 907/564-5283. 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. 457, Rule 10. By Samantha Carlisle at 9:34 am, Dec 17, 2021 'LJLWDOO\VLJQHGE\.\QGDOO&DUH\ '1FQ .\QGDOO&DUH\ RX 8VHUV 'DWH .\QGDOO&DUH\ 18 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 ornatural 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 oft he 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 (Me lvin.Rixse(alalaska gov). cc. Jody Colombie From: Colombie, Jody J (CED) Sent: Wednesday, June 10, 2020 8:59 AM To: Chmielowski, Jessie L C (CED) <jessie.chmielowski(7a alaska aov> Cc: Rixse, Melvin G (CED) <melvin.rixsePalaska.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) <jessie.chmielowski analaska gov> Sent: Wednesday, June 10, 2020 8:57 AM To: Colombie, Jody J (CED) <jody.colombiePalaska eov> Cc: Rixse, Melvin G (CED) <melvin.rixse9alaska gov> 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? Co, ambie, Jody J (CED) From: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Sent: Tuesday, lune 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 Sternicki wo Sr. Well Integrity Engineer BP Exploration Alaska Cell: 1 (907) 350 0759 oliver. stern ickiabo.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 1 (CED) <jody.colombie@alaska.eov> Sent: Friday, May 15, 2020 3:16 PM To: AOGCC_Public_Notices <AOGCC Public NoticesPlist state ak us> Subject: [AOGCC_Public_Notices] CO -20-008 Docket Number: CO -20-008 Prudhoe Bay Field, All Pools .Jody J. Colonihie Special Assistant Alctska Oil and Gas Conservation Counnission 333 West 76 Avenue Anchorage, AK 99501 (907) 793-1221 Direct (907) 276-7512 Fax List Name: AOGCC Public Notices@list state ak us You subscribed as: ryan.daniel(abP.com Unsubscribe at: htto://list.state.ak.us/mailman/options/ao¢cc Public notices/rvan daniel%40bo com 17 STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMITINVOICE SHOWING ADVERTISINGORDER NO, CERTIFIED AFFIDAVITOPPUBLAD RTISMENTATTAG7EDCOPVOF ADVERTISING ORDER NUMBER 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 5/15/2020 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 Anchora a Alaska 99514-0174 TYPE OF ADVERTISEMENT: r LEGAL 1` DISPLAY .r CLASSIFIED r OTHER (Specify below) DESCRIPTION PRICE CO-20-008 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMITINVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAV770F PUBLICATION WITHATTACFH:DCOPY OF ADVERnsmervT To: AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pae 1 of 1 Total of All Pages $ REF Type Number Amount Date Comments I PVN IVCO21795 2 AG AO-08-20-024 3 4 FIN AMOUNT SY Act. Tem late PGM LGR Obert FY DIST LIQ 1 20 AOGCC 3046 20 2 3 4 Parris n u if Title: Purchasing Authority's Signature Telephone Number .O. # and receiving agency name must appear on all invoices and documents reusing lothis purchase. 2yThe state is registered for tax free transactions under Chapter32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and of 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 psig. 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 am. at 333 West 76 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 am., 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 70, 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 Jlmy AOGCCSpecial Assistant, Jody Colombie, at (907) 793-1221, no later than June 20, 2020. M. Price Chair, Commissioner Benue Karl K&K, Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 16 a BP Exploration (Alaska) Inc.4 Attn: Well Integrity Coordinator, PRB-20 'V Post Office Box 196612t0A Anchorage, Alaska 99519-6612 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 bo�rd 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 Lamm =nvmli snWmss arras s/zarols unv=ms v5nD15 Lxa'm:5 mLa Figure 2- WbA Pad Gas Litt Header Pressure WOA Gas Lift Pressure =a5nm 5nvm15 5nnms bnam=s arras 9nN3015 lu:lrmli u5n 015 Dale v:vmla —m01 —DSm —Dso• —Dsos � i —os ez i —Dsm —Ds u —mlz —mll —D51• —Ds 1. —Mn —APN —arae —DPa --x PN —1 P.e —LIN —Mp" —xPN PPM P P., —SPN W v ne w PN .PN I ne =P.a 15 0 October 23, 2018 Via USPS and Electronic Delivery Hollis French Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7h Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska)Inc 900 -a51 Benson Bowevam P O Box 196612 Ancho'age. Alaska 99519-6612 (907) 561-5111 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 Application for Administrative Approval Amendment of COs 457 A/B, 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 areal 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 AB, 471, 50513, 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 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 [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 (Map]), 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 iniection 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 imection. Other quantitative methods may be administratively approved by the AOGCC. 3 Application for Administrative Approval Amendment of COs 457 A/B, 471, 5056, 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 subiect 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 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. [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. Eli Application for Administrative Approval Amendment of COs 457 A/B, 471, 505B, 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 be 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 iniection. 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 subiect 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 \ Tenn Well -C reservoir compartments, and one reservoir Application for Administrative Approval Amendment of COs 457 A/B, 471, 505B, 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 un 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 approved by the AOGCC. fmay 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.] Midnight 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 injection 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. A 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 Wiliiam.bredar@bp.com (907) 564-5348. Sincerely, �f Katrina Garner West Area Manager Alaska Reservoir Development Attachments: Maps 1 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 1•I Q Paul CO FW troCNrr1 Cunmt mMnurn I of MW IIU Oy^p' tfrY/mmIkMMMlmdrtln hepeW mMfmMrl 11pe 110 Wrt(r 11rr41b(IrrylrC h �MWnwm lel lalydnlbMl lrWUwC YriwmlM 9d0eYe OM IMe C Pofk app dtlK)� Ul ffrb(Mmllr Yex CeCMrn Mdl hOuvl IIW 11a Gyyl PW Iu(Nrye • 1 _ •w/•. _ _.. _;ayuatl l9 dunlal \rtt l pn repepltx xeJ LIf rrYnr lu PfM. pe t kulKKnp &1P ie rtuie purlafy .�uur.r' A•r/C}IH nJ +.,ruarr qU IxIH wINr 4irK Il YfJ 11u1<ml Kllw Iron rlxrbfJhdn KW p!\wle\wNry -wt-D1 _ _Wtll4ftYIJ1[[ repdtnl _ al ' '�I }n CIMNNm 10 PM •. Ufrrryr!\fMJlm•arrJ Pnrrul cNfulxavrp &Nr x.r+arr 4/1 Mnhn ISI Lur� 4Wt e�+inuni+t+ Sa rlurrurxe •NIa In rlalrfnlalMxN\ INItIn Xlm Itmr\rwlKl Mlhfurr sny 1j � � iII CPrldm 1U P(IP. ' i. tiler regrxnlxne Kea Pffu'M fJkWa1xm 18r1P r)rml ... Yl}X <a el nrrnJte :l yn drafiurlyd Brrnri nu•nIJ IMIarrN Klrv! hdofWzebU hwU Kry - _ • _ '�J flunmate 5G �te[rrdi I-.. wft� \rcHmwalN my[IOn '. ' NpIH }/M NwWrMpltmlyuwYnl" Stl lCMdmt04pP. :I.Onlrl l!\uuryNiprrN grMWlgn. P^u\rl4kuYrµnppNP rtlfen) WPatlllfrm Wllll It per repeeunlXM xea rtUm wlXf tlxa rtmrvry wanr\' 9rwa as rHnrer�+tr ah � �rew\fx rmtyxmrmn\. t:61 in IbIrpNKM XUM wehm w•all+mnl.m '4ufwaflWf Se mJt[ uarler Ir 1 uJl }J alunvyl! M exlfr myarlmenl xeli\) 560000 570000 580.000 590.000 600,000 610000 620,000 630000 BPXA requests this map be kept confidential under AS 38.05.035(a)(8), 11 AAC 82.810 and other applicable law. N o Represenative Areas by o Aurora Borealis ve Kuparuk LEGEND r t, I r Kuparuk Represenative Areas (Approximate) r----------') ' ' S 11 Aurora (West of Crest, North of Crest, South ED .,.__—_____-_____.-- 3 • of Crest, Crest Area, South of Crest) S 119 I • f- Q Borealis (NL -Pad, SWL-Pad, EV -Pad, NV -Pad, enT - 2L J % \ I •� • 07 .115 2 North SV -Pad, Z -Pad) I 1 S Pools West of Crest S_1 •of Crest • I Q Aurora �. _—_—_�� _Y.�, •S-121 S -1o0 -104 • \� Borealis • L-123 4 \ I • .A : -105 —�.� Participating 1. `5 ,, • �� 118 S� S-10 North L -Pad •L- 19\, S42 - • • -110B 122� ` S- 1 S- AURORA 11 I L-1 1 1.3BL1 01• '115 5-11�L S-109 • t..- BOREALIS -11 L-11 • •L 120 .rest Area S 112' e j Prudhoe Bay Unit N _1 4A L-103 : 1 2 h 1 7 '11 •` 25-123 N- — • Perf Midpoint p Sou l L 1 1 • L. V-103 _. ,. �- _ South • • _;; of,Crest S-125 �„• Eas of . r -loo iSW Pools L-1 V- \East V -Pad ,1 128 •� 6A (Crest - " I tl Q Aurora L- P L-'�07 _1 -, I S O6, ' 1 os 1 9 , •• V-102, : L-110 S-135 Q Borealis ' • North V -Pad • _ TKUD Faults ` � •10 •4-108 0V • -1059V-1 1 I V-122 + I TKUD Depth (feet TVDss) ,o ! -`_ • •- •V-100 • High: -6200 12 x'10 •V -115L - Low. -7700 t 1 South V -Pad V' •115 i 11 _1 -1 7 .,..----.. _101 1 •Z'I 3 3 Z-11 2 Z -Pad •Z-100ve _ _ < l Z 02 Z-103 \ E r Z__ I o 0 Coorennate system: o \ o NAD 1927 slatPlane Alaska 4 rips 5004 m I o Prolectio n: Transverse Mercator Datum'. North American 1927 a\I Data Sources: Well, Units, Coastline maintained by BPXA Cartography. 0 1 Miles rEAM. evxn 6P Exploration Alaska mcarlou.RuS%n 900 E fienson BIW Anchorage. AK MAP 1 nEv 0 560000 570000 580000 590000 600000 610000 620000 630000 cis s. EEO alts a.1 REVIEW p. MPMJ pn 25, 20P 560000 570.000 580.000 590000 600000 610000 620000 630000 Represenative Areas by N Aurora Borealis 0 Kuparuk LEGEND k r------ — I — — Kuparuk Represenative Areas (Approximate) p----------� i I---------------------------------- Aurora (West of Crest, North of Crest, South 0 i '111 East of Crest, Crest Area, South of Crest) o -� L_-_---..� i 119 o O Borealis (NL-Pad, SWL-Pad, EV-Pad, NV-Pad, �; j A__ S-1 m SV-Pad, Z-Pad) a 1 •S-102L • •S-107 5-102 North S 2 Pools L t S'1 2•of Crest • { ----------------- --- West of Cres• •S-121 0 Aurora L----------I S-114A S-103 j • S-100 S• S-104 Q Borealis L-1 2331A • • _31A S -105 Participating Areas t. • o L-118 S-4 A S-108 • j North L-Pad •L-119 &42 •S-1106 z AURORA L-1 22 -122 S-113 S- 20 S L-117 • • S-115 -11 1-1 S-109 5 010 -- BOREALIS �, --� -- L_ • L-101 •L-120 1 3BL1• Crest Area • • 5-112 o +--� I Prudhoe Bay Unit a -110L-115• L-114A t • •L-103 L-1 2 • i _1 7 -118• -123 --—� 1 • • L- • V-103 South South N • Perf Midpoint •L-1 1 • - '?120 of Crest* 5-13 • East of Pools 1 t ` L-100 L-10 • • • L-108 V-12 East V-Pad S-125 • S- 6A Crest S-128 • Q Aurora ti--,---------, SW L-Pad L_ • 107 I • V 0®V-106A •V-102 V-1 1 •5-129 Q Borealis j L-110 • LS-135 •North V-Pad101 0 OV-104 • , j -121A • V-105.V-1 11 V -122 o OV-1 •V- ' o 108 •V-100 _....-......._ 1 V-112 •V-115L N :-109 • N 1 V- South V-Pad • V- • Z-115 I � -117 101 Z-114 i V-11 •Z-113 • —' a -112 Z-Pad � 1 x---------- --- --- --.„1 •Z-100 r Z-102 Z-103 I f IJ f Z-108 i3 1 _. L-----t _ 1 rJ Coordinate System: 7 o NAD 1927 StatePlane Alaska 4 Firs 5004 m o Projection: Transverse Mercator N an Datum: North American 1927 1 Data Sources: a Well, Units, Coastline maintained by 8PXA Cadography. 1 a kPXR MilesrEPM BP Exploration Alaska K—AT susxa 900 E Benson BIW Anchorage, AK MAP 1 sru.0 560000 570000 580000 590000 600000 610000 620000 630000 cis x. sommeR Dens m+e ti-e- PMPWJ W25AP 560.000 570.000 580.000 590000 600,000 610,000 620000 630000 Represenative Areas by N BPXA requests this map be kept confidential under AS 38.05.035(a)(8), 11 AAC 82.810 and other applicable law. Orion / Polaris 0 ao co Schrader Bluff Jo co co LEGEND 11 Schrader Bluff Represenative Areas I ----------- (Approximate) 1 j Orion (1, 1A, 2, 2A, 2AS. 3A, 3S, 3N, 4, 5N, --,----t i I— 5S, 6N, 6S, 8, 9) i —------- — --- — — — -- o O Polaris (SPaCIN, SPadS, WPadN, WPadS) co i �s i—----------; j S Pool I i I N Q Polaris 1-4 ----_ ,. �� X203 •L-223 _ J_----------------I 1! Q Orion 1 -200 212 4 — ,t L. 1L-� -216 • : -215 -- � 1 SC\0 • Participating Areas ' L-218 L-2S� • - ORION ` L-202 •L-219 • S Pad N POLARIS o co 2 ^ _� i \ L 2 \ co Co so L • I , Prudhoe Bay Unit ` -210\� N — 1 '213 L- 4 21 • Perf Midpoint p •V- • \ t S -2'\- OA Faults ----------- t j •' 0• L- -221 ` V-20 • 0 ,. -21x• i S-217'-�--� ' OA Depth (ft TVDss) j i • • 0 • V-A9 V-216 213 24 I 111. •S-218 Pa S�dS. High :-3100 co - V-0040 222 • 21 �� I I c' r V V-217 • 1 - W-221 . o o 22 ••\� IV-223 191 y -220 N r F'1 i t 2 • •V-215 t . W-218 W-202 C2 ------ �---^----J s 223 W 0 • V1V*W-217 • 1 `' J { W Pad N/ �-- '{ -216t' t w-201 j_ t W-2140 W- t�-----t 0 13 19 • W-205 --�-- o m L------------------i 00 • -212 co _ ^L-------i • W 20 m j 211• -210 W-203 ! 7 1 0 1 \' • Miles W Pad S Coordinate System: NAD 1927 StatePlane Alaska 4 FIPS 5004 x Projection: Transverse Mercator t Datum'. North American 1927 o o Data Sources: m Well, Units, Coastline maintained by BPXA Cartography. f N )t BP Exploration Alaska N BP mcnnox FuSxF 560000 . 900 EBenson SW AnchorageAK MAP. 2 600000 610000 570000 580000 590000 620000 630000 cts x. soteuEa onm,mn REVIEW B. BREOFR Otl ]5, 10V 560.000 570000 580.000 590000 600,000 610000 620000 630000 by Represenative Areas N Orion /Polaris 0 0 0 0 0 0 Schrader Bluff 8 LEGEND ---------- T Schrader Bluff Represenative Areas J (Approximate) J --------- Orion (1, 1A, 2, 2A, 2AS; 3A, 3S, 3N, 4,5N, —"----�-`t i 5S, 6N, 6S, 8, 9) I tI O Polaris (SPadN, SPadS, WPadN, WPadS) 0 o ----- o o an Pool ..., .. Q Polaris L ----------t _. X203 • L-223 _. Jam.,\ -------- — ----i ,., - Q Orion L-200 L-212 L- 1 L -?1=@L-216 -201 e Participating Areas L-215 >..,.,., L-A L-218 • ORION • L-202 • L-219 _ • 5 Pad N POLARIS m '" j L 222 L-2.1 L 1-210 o f ;Prudhoe Bay Unit • -211A t _ • Perf Midpoint L-213 L-204 •V-221 • • V-1203 • V-210 x'22 • 5-213A • ------ --- • • V-220 • ` iL-205,19-221 { V-202 • OV -20-11t V-214•• S-217 , -. V �t l- L-220 * V-216Vi 113 •11 •224 • •S•218 S Pad S ....... __. . =211 V-�Q4• ` R •V-212 ; 0 1 V22 o o I V-217 •V-21 --.. _......._.. _,. W-221 ' I •' o.,4 N 1 ,2250 • V-223 V-219 ' • W-220 ,�^, � l � V-205 • • - ..__ :' I r � —, •V-215 ..._. W 018 W-202 j • -V?223 __.___.,.�....... ----------J ... J . W i • • W Pad N W-217 { --` 2169 W-201 :I W-214 • •W- t j 13 • W-•219 • W-205 o . --------------------- 00 • • W-212 t'-------' : -20 j ... .,.. j 211 • •-- -210 s 7 1 W-203 0 1 d 1 ® Miles W Pad S Coordinate System: NAD 1927 StalePlane Alaska d FIPS 5004 ProjectionTransverse Mercator J i Datum: North American 1927 J o Data Sources: J o Well, Units, Coastline maintained by BP%A Cartography. N J1i 1 M Bp qusNA eP)0E Naska,ocnnou REv.] 560000 900E.Bervson BlW liens Anchorage, AK MAP 2 570000 580000 590D00 600000 610000 620000 630000 cts ssoeu oam,ton REVIEW B. BREpW py y., p,) 14 b RECEIVED NOV 0 4 2015 BP Exploration (Alaska) Inc. AOGCP.O. East Benson Boulevard Box 612 Anchorage, Alaska 99519-6612 (907) 561-5111 November 2, 2015 Cathy Foerster Commission Chair Alaska Oil & Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 Re: Request for Administrative Waiver of Monthly Reporting of Daily Production Allocation Data Dear Chair Foerster, BP Exploration (Alaska) Inc., as the Operator of the Prudhoe Bay Unit, respectfully requests that the Commission administratively waive the requirement in the following Conservation Orders (CO) Pool Rules, for monthly reports and files containing daily production allocation data: Schrader Bluff Oil Pool - CO 505B Rule 4f Aurora Oil Pool - CO 457B Rule 4e Prudhoe Oil Pool — CO 341 F Rule 18d Borealis Oil Pool - CO 471 Rule 4g Midnight Sun Oil Pool - CO 452 Rule 7d Polaris Oil Pool - CO 484 Rule 4d Put River Oil Pool - CO 559 Rule 4f Raven Oil Pool - CO 570 Rule 6d Niakuk Oil Pool -43 — CO 32913.003 Rule 4b BP will continue to collect the daily production allocation data and will provide the data to the Commission at any time upon request. BP will also continue to submit required monthly production data to the Commission through the 10-405 forms. We simply seek relief from the cost and burden of preparing the reports on a monthly basis. We have attempted to include in this request all Prudhoe Bay Unit oil pool Conservation Orders that contain a requirement for monthly reporting of daily Request for AOGCC Administrative Waiver November 2, 2015 Page 2 allocation data. If the Commission is aware of additional Conservation Orders containing this requirement, BP respectfully requests the opportunity to add them to this request. Please direct any questions you may have to the undersigned or to Caroline Bajsarowicz at 907-564-4314, Caroline.Bajsarowicz@bp.com. Sincerely, 4 -, A L ," Diane Richmond Performance and Data Management Lead Alaska Reservoir Development, BPXA 564-4136 Carlisle, Samantha J (DOA) From: Roby, David S (DOA) Sent: Wednesday, December 30, 2015 2:53 PM To: Carlisle, Samantha J (DOA) Subject: FW: Monthly Reporting of Daily Production Allocation Data Sorry I forgot to forward this sooner. Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.roby@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 C03296. 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.robyC&alaska.gov] Sent: Tuesday, December 15, 2015 6:11 PM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline 3 Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane and/or Caroline, 1 I'm putting the finishing touches on the admin approval for this request and I have a question for you. In the request you asking us to waive Rule 4b in CO 329B.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 C0329B.003 Rule 4. Please confirm this or let me know if it is just a portion of that rule that you want waive and if so which portion. Below are links to the orders. http://doa.alaska.gov/ogc/orders/co/co300 399/co329b-3.pdf http://doa.alaska.gov/ogc/orders/co/co300 399/co329b.pdf Regards, Dave Roby (907)793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.roby@alaska.aov. From: Richmond, Diane M [mailto:Diane. Richmond@bp.com] Sent: Thursday, December 03, 2015 10:20 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Thanks Dave. We will go ahead and complete the report. From: Roby, David S (DOA) [mailto:dave.roby@alaska.gov] Sent: Thursday, December 03, 2015 10:15 AM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane, Working on your request was actually on my to do list for today. That said, we won't have a quorum of commissioners until the week of the 131h, so it's unlikely an official action will be taken until that time. While I don't expect there to be any issues with approving your request I cannot guarantee what the commissioners might say/decide, so to be safe you should probably go ahead and complete the report. Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.roby@alaska.gov. N From: Richmond, Diane M [ma iIto: Diane. Richmond @bp.com] Sent: Thursday, December 03, 2015 8:55 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: Monthly Reporting of Daily Production Allocation Data Dave, We are getting ready to prepare the Monthly State Satellites production report. Before completing this report, I wanted to understand the status of our Request for Administrative Waiver of Monthly Reporting of Daily Production Allocation Data sent to the AOGCC on Nov 2, 2015. Should we complete this report for the month of November to stay in compliance? Thanks for all of your help as we look to streamline, but also stay compliant with AOGCC orders. Diane Diane M. Richmond BP AK Reservoir Development Compliance SPA 907-564-4136 907-440-0835 (Cell) 13 Mom MAY 14 2015 May 11", 2015 Steve Davies Alaska Oil & Gas Conservation Commission 333 W. 7`h Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Spacing Exception— Aurora S-44A Aurora Pool Rules (CO 45713-Corrected) Affidavit of Compliance Dear Mr. Davies: AXow A BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 D(907)561-5111 BP Exploration (Alaska) Inc., (`BP") as operator of the Prudhoe Bay Unit, requests an exception to Rule 1 of the Aurora Pool Rules requiring a 40-acre minimum spacing to enable the drilling of Aurora well S-44A (the "Well"). Pursuant to Rule 10 of the Aurora Pool Rules (under which the Commission may administratively waive Aurora Pool Rules requirements), BP requests that the Commission grant this application and waive the 40-acre spacing requirement for the Well. The Prudhoe Bay Working Interest Owners have chosen to drill the Well for oil to access unswept oil resources not previously extracted by the producer S-100. The position of the Well will have perforations approximately 1100ft. from the heel of S-100. The owners, landowners, and operators of all properties within 1000ft. of the proposed bottomhole location of the Well are BP Exploration (Alaska) Inc., Chevron U.S.A. Inc., ConocoPhillips Alaska, Inc. and ExxonMobil Alaska Production, Inc. A notice of this application has been sent to these parties by certified mail pursuant to 20 AAC 25.055. A plat depicting the Well's trajectory on a quarter -quarter -quarter basis is attached as Exhibit 1. An Affidavit verifying the facts is attached as Exhibit 2. Exhibit 3 explains the rationale for the location of the planned producer S-44A (Exhibit 3.1). The Well will have perforations approximately 1100ft. from the heel of the producer S-100. It is expected that the drilling of S-44A will allow the maximum recovery of oil resources for the field. Exhibit 3 attached to this Application contains engineering, geologic and commercial information voluntarily submitted to the Commission, which BP requests that the Commission keep confidential pursuant to 20 AAC 25.537(b) and other applicable law. BP has chosen to drill the specified location for the following reasons: • Field level reservoir simulator history matching highlights an area of unswept oil to the east of 5-100 and parallel to the north -south fault (Exhibit 3.2). • Interactions analysis indicates that S-101 and 5-107 injectors provide good injection support to the producer 5-100; however, the injection streamlines go directly towards the 5-100 well, leaving an area of bypassed oil to the east of 5-100 and along the north -south fault. This north -south fault has significant throw (-150ft.) and no across -fault communication to the east is expected (e.g. 5-03 producer, 5-120 injector; Exhibit 3.2). • Reservoir simulated studies tested two well concepts to maximize total field recovery: a vertical well and a horizontal well parallel to the major north -south trending fault (Exhibit 3.3). • These concepts were simulated and the field incremental oil recovery shows an increase in oil recovery (Exhibit 3.4) in the horizontal concept compared with the vertical well concept. Conclusions An exception to the Aurora Pool Rules requiring a 40-acre minimum spacing requirement (Rule 1 of CO 45713-Corrected) is necessary to avoid waste and allow the maximum recovery of oil resources. Shortening the length of the well to comply with the minimum spacing requirements as outlined in the Aurora Pool Rules would result in increased risk of stranding oil resources. A spacing exception to allow drilling of a 2000ft. horizontal S-44A well concept is consistent with sound engineering and geoscience principles and will not result in waste or jeopardize correlative rights of adjoining or nearby owners. If you have any questions or require any additional information, please contact the undersigned at: Sincerely, �arl Lundgren West Satel ' ubsurface Team Leader BP Exploration (Alaska) Inc. HIBIT 1 - PRUDHOE BAY l r S-44A WELL SPACING EXCEPTION 5-119 21NW S-107 21NE saozu 22NW 22NE 5-111 PB2 5-111 PB1 S-102L1PB1 23NW 23NE ' 24NW I 24NE s-1B2 S-121 1 22SE 215W 21 SE 22SW S. 2 5-122PB3 S-122PB2 S-122PS1 23SW 235E S-124 24SW 245E AD L028258 5-121PB1 s-,o3 53 A ADL028257 28NW 26NE s-1Bo 5-102 27 S Bt 27NE 26NW 26NE 25NW 25NE S-44A BH 6-104 S-100 s-1o5 10202' MD 28SW 5-113A 28SE S- PB1 27 S-10e SE S-110 26S 25SW s-11 oB 255E 5-1138 TKC4 5-101 5-120 S-11BA S 09 S-10IF BI S=44A 3-112 33NW 33NE 34NW 5-109PB1 35NE' 36NW 36NE S-1 ]C S-11B 6-,2 Native Allotment S-134 ' #017451 Alfred Leavitt 5-125P81 -I 3.1 1 33SW 5-125 33SE 34SW S 34SE SA-116 35S✓ 35SE 35SW 38SE T1N-R12E . 5-129P 5-116APB1 S-116APB2 T11N-R12E .. i 4NW SW 4NE S-12B S-135PB2 3NW S E 29OF 2NW 2NE iNW iNE 4SW S-135 4SE 3SW 3SE 2SW 2SE iSW ISE 11NW 11NE 12NW 12NE WELL PLAN 5 TKC4 to TD by E) PBU S PAD AURORA FIELD WELL OIL & GAS LEASE BOUNDARY (Owned by PBU WIOs) - SECTION BOUNDARY `Ali other land within map extent owned by State of Alaska 11SW i1SE 12SW 12SE 0 0.25 0.5 0.75 1 Miles Im 16587a. mxd EXHIBIT 2 AFFIDAVIT VERIFICATION OF APPLICATION FOR SPACING EXCEPTION S-44 WELL I, Carl Lundgren, West Satellites Subsurface Team Leader for BP Exploration (Alaska), Inc., ("BP"), the operator of the Prudhoe Bay Unit and Aurora Pool, does hereby verify the following: I am acquainted with the Application of BP to the Alaska Oil & Gas Conservation Commission, dated May 1 lth, 2015, for a spacing exception for the S-44 Well. 2. I have reviewed the Application and all statements in the Application are true. 3. I have reviewed the plat attached as Exhibit "1" to the Application and it is accurate and correctly portrays the location of the S-44 Well and the location of all other completed and drilling wells on the property and all adjoining properties. Dated at Anchorage, Alaska this 11 day of May 2015. Carl Lundgr n West Satellite ace Team Leader STATE OF ALASKA THIRD JUDICIAL DISTRICT Subscribed and sworn to or affirmed before me at Anchorage, Alaska, on the 11 day of May, 2015. '- � --f3 � I S . &� � of Public, State of Alaska Exhibit 3: Aurora Field S — 44A Spacing Exception held confidential in secure storage #12 U Katrina Garner, P.E. Base Management Manager March 31, 2014 R I APR 0 2 2014 BP Exploration (Alaska) Inc. P.O. Box 196612 900 E Benson Boulevard Anchorage AK 99519-6612 UNITED STATES OF AMERICA Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Phone: +1-907.230-4212 Anchorage, AK 99501-3539 Re: Conservations Order CO 457113.003 and CO 341 D.005 for well S-26 (commingled production) Dear Commissioners, In a letter dated September 30, 2013 (copy enclosed) BP Exploration (Alaska) Inc. (BPXA) reporteda lapse in our special reporting requirements under the above -referenced Conservation Orders on well S-26, with a recommended action plan to address the allocation issues. We have completed a review of the situation and report the following. All collected samples have been analysed and we have back -calculated the impact of misallocation between the zones. The total discrepancy of 15,857 bbl was allocated to the Kuparuk that should have been allocated to the Ivishak. A plot of daily average daily production for the Aurora field is shown below with both the previously -reported splits (red) and the new correct splits (blue). Avg Daily Aurora Production 350 300 250 200 150 100 --N Daily Avg on 47% Aur Split Page 2 50 0 t+ N A Q� V tD ►+ N N A U V 00 a+ r r W v+ O� 00 f.+ �-+ F+ w N \ \ N \ W N r+ '\ r 0 tD \ \ W \ N \ \ \ r v M CO \ \ \ N \ \ \ N \ N O N N O N µ O O µ O N N\ N O N N N\ O O N O O O O N N N N O O O O OR 0 0 0 N p r µ N w To prevent future misallocations, we have established an automated reminder system to ensure the samples are collected in a timely manner and properly allocated between the oil pools. Please contact the Base Management Team Leader for the West End Area, Werner Schinagl, or myself with any questions regarding this matter. Respectfully, 7�w1, , OXII-Ow,.., Katrina Garner, P.E. Base Management Manager Attachments: Letter dated September 30, 2013 #11 0 E Katrina Garner, P.E. Base Management Manager September 30, 2013 RECEIVED OCT 02 2013 AOGCC rl BP Exploration (Alaska) Inc. P.O. Box 196612 900 East Benson Boulevard Anchorage, Alaska AK 99519-6612 UNITED STATES OF AMERICA Alaska Oil and Gas Conservation Commission Phone: +1.907-230-4212 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Re: Conservation Order CO 457B.003 and C0341D.005 for well S-26 (commingled production) Dear Commissioners, BPXA recently discovered a lapse in our special reporting requirements under CO 457B.003 and CO 34D.005 on well S-26. This well is a commingled producer completed in the Prudhoe Oil Pool and the Aurora Oil Pool. Your letter dated November 27, 2007 requires geochemical sampling every 6 months and not less frequently than every 7 months. Our last update of the allocation factors is dated May 3, 2010. Samples have been taken since then as follows: • February 21, 2011 • January 2, 2012 • June 22, 2012 • January 2, 2013 • June 26, 2013 (two samples) The delay from May 3, 2010 to February 21, 2011 resulted from the well being shut in between October 5, 2010 and February 16, 2011. Unfortunately, we did not take a sample between February 2011 and January 2012. The analysis of the samples taken is being performed now. I have asked the team responsible for the West End Area to implement the following plan: • Analyze all samples • Ensure samples are taken at the required intervals • Back -calculate any amount of impact due to potential misallocation between the zones • Update the allocation on a point -forward basis • C: Page 2 I will keep you informed about any impact of misallocation between the different oil pools as well as on progress of the plan outlined above. Please contact the Base Management Team Leader for the West End Area, Werner Schinagl, or myself with any questions regarding this matter. Respectfully, Katrina Garner, P. E. Base Management Manager io by • • 0 RECEIVED / �r' 2 �, 2009 t;►aska Oil & Gas Cons. Commission John Norman a Anahgrapo Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 RE: Conservation Order 457B (Rule 13) and Conservation Order 341D (Rule 18) - Commingled production from the Aurora Oil Pool and Prudhoe Oil Pool in Well S -26 Dear Chairman Norman, As set forth in Alaska Oil and Gas Conservation Commission's Conservation Orders 457B and 341D (as amended), BP Exploration (Alaska) Inc. has complied with the commingled production of the Aurora Oil Pool (AOP) and the Prudhoe Oil Pool (POP) within well S -26 to determine a reliable and acceptable production allocation method. Over the course of the six month commingled test period (August 20, 2008 through February 20, 2008) BP has fulfilled the Commission's requirements in obtaining Production Profiles, Static Bottom Hole Pressure Surveys, Geochemical Samples and Well Tests. The results of the collected surveillance data are included in this letter. Please call either of us or Danielle Ohms 564 -5759 (POP) or Pat Collins at 564 -4363 (AOP) if you have any questions or wish to discuss further. Sincerely, rank Paskv n -"Scott gert Resource Manager, GPB West Resource Manager, GPB Waterflood Attachment 1: OilTracers Report No. 09 -826 (CONFIDENTIAL) Attachment 2: Schlumberger PL Advisor for S -26 10 -10 -08 PPROF Attachment 3: Schlumberger PL Advisor for S -26 2 -16 -09 PPROF 1 • • History of S -26 S -26 was originally drilled and completed as a Prudhoe producer in 1990. Zone 4 Stimulations, including both frac and acid treatments, were performed in 1991 and 1992 to maximize production. By late 2007, S -26 was producing 200 to 250 bopd at approximately 75% watercut and 6000 GOR from the Prudhoe Oil Pool. Well S -26 penetrates the AOP and POP in areas where well rates from both Pools are low. A stand alone Aurora producer in this area could not be justified due to the expected low rates and associated problems with paraffin and hydrate deposition. A RWO to commingle production from the two pools within the S -26 well -bore was planned to maximize oil production from the two oil pools. Prudhoe production was isolated on 12- 15 -07. A RWO to recomplete and enable Aurora production was completed in January 2008. Aurora perfs were added and an initial Aurora only SBHP was obtained on 4 -3 -08. The Aurora reservoir pressure at this time was 3615 psi. The well was put on production on 4 -4 -08 though total fluid rates were low and the well was SI on 4 -7 -08. An Aurora only frac placed approximately 188,000# proppant in the formation on 5/12/08. S -26 was put on production again on 5 -16 -08 with significantly increased production rates post frac from the Aurora only. Plugs were drilled out to re -open the Prudhoe on 8- 17 -08. Commingled production began on 8- 20 -08; it has remained commingled since. The commingling of the Prudhoe and Aurora pools has shown to have a positive impact on oil production from S -26. The Aurora oil production to date from S -26 is 183,500 bbls. The total incremental commingled oil rate from S -26 (over 2007 Ivishak only production) is approximately 600 bopd. Results Obtained from Commingled Test During the course of the commingled testing period, two production profiles using Schlumberger's DEFT and GHOST tool, 7 geochemical samples, and 19 welltests were gathered to assess performance of the Prudhoe and Aurora. PL Advisors interpreting the oil/ water and gas splits between the pools were performed by Schlumberger, and were completely independent from the oil Geochemical analysis performed by Oil Tracers L.L.C. Neither were privy to the other's analysis or results. Both the PL Advisors and the Oil Geochemical Report reference the Ivishak layer of the Prudhoe Oil Pool, so please note that reference to the Ivishak and Prudhoe are meant to represent the same oil. The PL Advisor reports from Schlumberger are included in the Appendix. A summary of the Production Profile logging of the Aurora and Prudhoe Oil Pools in S -26 is shown in Table 1. Oil % Water % Gas % Aurora 10/10/2008 51 16 35 2/1612009 55 34 26 Prudhoe 10/10/2008 49 84 65 2/1612009 451 66 -- 17 Table 1. S -26 Aurora/Prudhoe PPROF Results Monthly geochemical samples were collected over the commingled test period and results are shown in Table 2. Separate end member samples of the Prudhoe oil (9/3/07 sample) and the 2 • • Aurora oil (5 /19/08 and 5/20/08 samples), all from 5 -26, were used to determine commingled oil splits. The Geochemical report from Oil Tracers L.L.C. is included in the Appendix. Geochem % Geochem Prudhoe % Aurora Date Oil Oil 8/30/08 26.83 73.17 9/18/08 51.61 48.39 10/10/08 37.09 62.91 11/14/08 46.10 53.90 12/21/08 43.81 56.18 1/5/091 59.20 40.79 2/11/091 47.011 52.99 Table 2. 5 -26 Aurora/Prudhoe Geochemical Analysis Results Reservoir pressures were obtained from the separate pools during the last period they were produced in isolation. While the Prudhoe reservoir pressure is higher than the Aurora at face value, if converted to the Aurora datum of 6700' TVDss assuming a water gradient of 0.44 the pressures are very similar. Table 3 below lists the results. Reservoir Oil Pool Date TVDss Pressure Prudhoe 9/23/2007 8800' 3223 psi Aurora 1 4/3/2008 1 6700' 3615 psi Table 3. Aurora and Prudhoe Reservoir Pressures Welltests were conducted over twice a month during the commingled test period, and at least once per month for the periods of individual Aurora and Prudhoe production. Prior to obtaining PPROF data, initial commingled spilts were assessed and applied to allocated pool production based on separate zone tests. Using the 11/27/07 welltest as representative of Prudhoe only production and the 8/1/08 welltest as representative of Aurora only, initial splits were calculated and shown in Table 4. A summary of all welltests since 2007 is shown in Table 5. Oil % Water % Gas % Prudhoe split 38 94 63 Aurora split 62 6 37 Table 4. Initial Splits based on Separate Zone Tests 3 Y CL H m « a rc C x x V J J J Well Date 06 c U. O 3 c7 0 U U. LL 3 0 0 ► S-26 3/22/2009 4 6 1358 602 756 1797 2986 94.8 222 104 55.7 3010 1305 3540 S -26 33/2009 4 6 1349 617 732 2197 3559 94.8 219 102 54.3 3080 1412 3912 S -26 2/18/2009 4 6 1668, 792 876 6110 7712 94.9 257 98 52.5 3680 1800 5W9 S -26 2/11/2009 4 6 14081 660 748 2092 3171 94.4 222 102 53.1 3060 1367 3659 S -26 2/7 {2009 4 6 1408 652 756 20% 3215 94.4 219 102 53.7 3040 1 1357 1 3648 26 1/21t2009 4 8 1427 691 736 2055 2973 94.4 220 101 51.6 3070 1 1372 1 3501 S -2 1/51200 4 8 16 9' 906 783 2482 1 2740 55.5 495 08 46.4 3580 1614 1 3589 S -26 12/2212008 4 6 1447 811 636 2361 2910 93.6 231 101 43.9 3510 1555 4057 S -26 12119t2008 4 151* 866 648 2334 2L96 93,6 230 103 42.8 3440 1525 3814 S -26 12/17/2008 4 6 1502 870 632 2385 2741 9.3.6 231 1 102 42.1 3480 1553 39G5 S -26 11/2512008 4 6 15061 870 636 2425 2788 93.7 234 103 42.2 3460 1520 39.08 S -26 11/14/2008 4 6 111584, 932 1 652 7 2761 94.0 2M 102 41.2 20 1560 3847 S -26 10/31/2008 4 6 11497 901 596 2710 3009 Q.7 228 103 39.8 3510 1548 4155 S -26 10/1812008 4 6 1509 885 624 2750 3107 91.6 212 101 41.4 $420 1522 4089 S -26 10/4/2008 4 6 1713 937 776 2577 12751 91.7 197 107 45.3 1910 1008 2619 S -26 10/1/2008 4 6 26MI 1378 1268 2569 1865 91.7 204 119 47.9 1630 975 1 7 S -26 9/20/2008 4 6 1545 813 732 1815 2233 90.6 208 110 47.4 1510 883 2152 S -26 9/9/2008 4 8 1743 942 801 2208 2345 90.6 209 112 46.0 1530 921 2145 S -26 8/23/2008 4 6 2219 895 1324 32 3599 91.2 240 119 59.7 2140 1198 2416 S -26 8/1/2008 4 6 799 719 80 1552 2157 90.6 219 74 10.0 2000 1033 4446 S -26 7/20/2008 4 6 697 653 44 1425 2182 90.6 217 72 6.3 2030 1009 4957 S -26 6/24/2008 4 6 790 722 68 1588 2200 89.3 210 80 8.6 1940 938 4466 S -26 6/6/2008 4 6 1085 989 96 1874 1896 92.4 214 82 8.9 2000 882 3571 S -26 5/21/2008 7 4 1 1630 1461 169 2320 1588 92.0 340 89 10.4 1400 1900 2282 S -26 5/21/2008 4 4 1 3145 1369 1776 2147 1569 44.8 205 74 56.5 1570 963 1182 S -26 4/5/2008 4 6 81 61 20 602 9938 94.8 189 72 24.8 1990 1338 32000 S -26 12/8/2007 4 6 898 194 704 1197 6183 94.7 211 106 78.4 1980 1456 3538 S -26 11/27/2007 4 6 909 197 712 1172 5943 94.7 218 103 78.3 1970 1225 3457 S -26 11/19/2007 4 6 916 220 696 1395 6335 94.7 208 104 76.0 2030 1226 3739 S -26 11/11/2007 4 6 941 217 724 1406 6496 94.7 205 103 77.0 2030 1239 3651 S -26 11/3/2007 4 6 978 198 780 1422 7200 94.7 197 105 79.8 2030 1244 3530 S -26 10/21/2007 4 6 961 205 756 1490 7270 59.7 288 105 78.7 2040 1307 3673 S -26 9/4/2007 4 6 1186 406 780 1425 3509 94.8 226 112 65.8 3270 1574 3959 S -26 8/12/2007 4 6 1224 288 936 1394 4841 95.0 219 116 76.5 2070 1296 2830 S -26 7/30/2007 4 6 929 201 728 1189 5928 95.0 229 112 78.4 2030 1172 3465 S -26 7/15/2007 4 6 866 242 624 1068 14415 95.0 237 107 72.1 2070 1241 3624 S -26 6/25/2007 4 6 940 212 728 1005 4748 95.0 242 105 77.5 2040 1243 3239 S -26 6/8/2007 4 6 848 216 632 976 4525 95.0 231 103 74.6 2060 1229 3580 S -26 6/1/2007 4 6 935 227 708 1155 5096 95.0 242 104 75.8 2060 1218 3439 S -26 5/9/2007 4 6 939 239 700 1104 4627 95.0 228 104 74.6 2020 1199 3327 S -26 4/21/2007 4 3 844 197 647 969 4931 95.0 236 104 76.7 2020 1103 3541 S -26 3/3/2007 4 4 909 213 696 1570 7379 94.9 245 99 76.6 2480 1263 4455 S -26 2/8/2007 4 4 802 244 558 1 1578 6475 94.9 244 94 69.6 2550 1267 5147 S -26 1/19/2007 4 4 804 222 i 582 1 1641 17404 94.9 224 100 72.4 2420 1237 5051 =Prudhoe only Welltests Aurora only Welltests =Commingled Prudhoe and Aurora Welltests Table 5. S -26 Welltest Data The average oil rate over the 7 months of commingled tests shown in the welltest data table is 843 bopd. The initial commingled welltest watercut of 59.7 % is higher than average and is attributed to the Prudhoe production cleaning up after an extend shut in period. Aside from that initial welltest, watercuts have been on a gradual increase which is expected as both pools are being waterflooded. A Welltest plot annotated with the periods of individual pool production and commingled tests is shown in Figure 1. 4 0 . S -26 3 10,000 w d x w 1000 • • • r • • • • • a c 100 4 0 co a w 10 V Jan -07 Apr -07 Jul -07 Oct -07 Jan -08 Apr -08 Jul -08 Oct -08 Jan -09 Apr-09 Prudhoe only welltests Aurora only Commingled welltests -Gross Fluid -Oil -GOR ♦ Gas Lift Pressure • Manifold Pressure Manfold Temperature -+-TGLR 100.0 0 0 4 0 0 100.0 80.0 80.0 a m 60.0 60.0 m m 40.0 40.0 m CL ° 20.0 20.0 ° 0.0 0.0 Jan -07 Apr -07 Jul -07 Oct -07 Jan -08 Apr -08 Jul -08 Oct -08 Jan -09 Apr -09 -Q-- Water Cut + Choke Figure 1. S -26 Welltest Plot Conclusions A summary of the allocated production reported for both the Aurora and Ivishak pools to date is shown in Table 6. The high Aurora oil split in August is due to S -26 being produced Aurora only until 8/20/08 when production between the 2 pools was commingled. Engineered splits were applied in September and October until the 10/10/08 preliminary PPROF results were applied starting in November. Final PPROF analysis results were applied starting in January 2009. The 2/16/09 PPROF results were applied to allocated production starting in March 2009. Oil Prod Water Prod Water Gas Prod Gas Prod Oil Prod Rate Rate Aurora Prudhoe Rate Prod Rate Aurora Prudhoe Rate Rate Aurora Prudhoe STB /DAY S- STB /DAY S- Oil split Oil Split STB /DAY S STB /DAY Water Water MSCF /DAY MSCF /DAY Gas split Gas Date 26 AURA 26_PBU % % 26 AURA S -26 PBU split % Split % S -26 AURA S- 26_PBU % Split % 8/31/2008 526 121 81.3% 18.7% 53 317 14.2% 85.8% 918 446 67.3% 32.7% 9130/2008 400 245 62.0% 38.0% 42 661 6.0% 94.0% 531 904 37.0% 63.0% 10/31/2008 560 343 62.0% 38.0% 45 713 6.0% 94.0% 1012 1723 37.0% 63.0% 11/30/2008 413 372 52.6% 47.4% 95 499 16.0% 84.0% 701 1707 29.1% 70.9% 12/31/2008 355 320 52.6% 47.4% 88 463 16.0% 84.0% 631 1538 29.1% 70.9% 1/31/2009 409 393 51.0% 49.0% 100 528 16.0% 84.0% 736 1368 35.0% 65.0% 2/28/2009 313 301 51.0% 49.0% 104 548 16.0% 84.0% 1248 2317 35.0% 65.0% 3/31/20091 299 245 55.0% 45.0% 224 435 34.0% 66.0% 679 1933 26.0% 74.0% Table 6. S -26 Monthly Allocated Production Based on the allocated production splits, the Prudhoe formation GOR increased in February and March to approximately 7800 scf /stbo. This corresponds with MI injection into Prudhoe injector S -20A in November through December of 2008 and interaction time with S -26 is typically 3 months. MI interactions between S -26 and offset Prudhoe injectors S -20A and S -06 are fairly 5 • • well established and are expected to be recognizable when they occur. These wells are not on MI often as the area is becoming mature for MI in the Prudhoe oil pool. A comparison of the commingled oil splits from both the production profiles (data from Table 1) and Oil Geochemical fingerprinting (data from table 2) is presented in Figure 2. Oil production splits were obtained from the commingled geochemical samples and are in close approximation with the Production profile logging results. The geochemical sample obtained on 10/10/08 and the PPROF started on 10/10/08 were over 10 hours apart. Flucuations in gas lift rates and well head pressures can have an impact on oil production splits from the 2 zones, thus the slight variation in the more frequent Geochemical analysis. S -26 Aurora vs. Ivishak Oil Splits 100.00 80.00 1 60.00 I 40.00 20.00 0.00 8/1/08 8/31 /08 9/30/08 10/30/08 11/29/08 12/29/08 1/28/09 2/27/09 -+- Geochem % Aurora Oil Geochem % Prudhoe Oil 10/10/08 PPROF Aurora Oil % x 10/10/08 PPROF Ivishak Oil % 2/16/09 PPROF Aurora Oil % n) 2/16/09 PPROF Ivishak Oil % Figure 2. S -26 Comparison of Oil Geochem and PPROF Splits Oil production splits were obtained from the commingled geochemical samples and are in close approximation with the Production profile logging results. The geochemical sample obtained on 10/10/08 and the PPROF started on 10/10/08 were over 10 hours apart. Flucuations in gas lift rates and well head pressures can have an impact on oil production splits from the 2 zones, thus the slight variation in the more frequent Geochemical analysis. The average Aurora oil split over the commingled test period from the 2 PPROF's was 53 %. This is very closely matched by the average of the geochemical analysis Aurora oil split of 55% (for all 7 samples) or 53% (excluding initial sample when Prudhoe just reopened and cleaning up). Obtaining more frequent Oil Geochemical samples is preferred over the more intrusive PPROF logging. Geochemical analysis provides quicker insight to production changes between the pools that may occur in the future. It also reduces risk by minimizing running into the well with tool strings. Occasional PPROFs or separate zone tests may be needed to determine water and 6 0 • gas splits between the 2 zones that are not readily explained by injection changes in interacting offset injectors. Based on the good agreement between the methods of measuring Aurora and Prudhoe oil splits, BP believes that geochemical analysis has been demonstrated to provide an accurate and appropriate method of allocating oil between the two pools. Therefore, BP proposes that from May 1, 2009 forward, geochemical fingerprinting be utilized for oil allocation purposes. The geochemical sampling frequency will be twice per year and not less frequently than every 7 months. When major changes in production characteristics occur, which cannot be readily explained by changes in offset injectors for either Pool, a production log will be obtained to more accurately allocate the water and gas production. Sincerely, Frank Paskvan / Scott Digert BPXA GPB Subsurface Resource Managers, WEST / WF BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 7 • • CONFIDENTIAL MATERIALS HELD IN CONFIDENTIAL ROOM 0 by schlumber PL Advisor' Production Log Interpretation With GHOST and DEFT Company BP Exploration (Alaska), Inc. Field Prudhoe Bay Well S -26 Date Logged 16- Feb -2009 Date Processed 12- Mar -2009 Reference Number AYTU -00014 API Number 50- 029 - 22047 -00 Log Analyst Erika Bowen Alaska Data and Consulting Services 2525 Gambell Street, Suite 400 Anchorage, Alaska 99503 (907) 273 -1700 II interpretations are opinions based on inferences from electrical or other measurements and we cannot, and do not guarantee the accuracy or correctness of any interpretations and e shall not, except in the case of gross or willful negligence on our part, be liable or responsible for any loss, cost, damages or expenses incurred or sustained by anyone resulting rom any interpretation made by arty of our officers, agents or employees. These interpretations are also subject to clause 4 of our general terms and conditions as set out in our current rice schedule. BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prud Bay 1. Production Logging Objectives: The objective of this logging suite was to evaluate production splits between the Aurora and Ivishak pools. Three phase production interpretation was performed to determine oil, gas, and water splits. 2. Main Results: Table 1: Interpreted Downhole Rates from multiphase solver. Tot.DH Oil Gas Water Pool Perforation prod. % Rate % rate % rate % From, ft To, ft B/D B/D B/D B/D Aurora 6870 6894 1695.8 31.30% 404.4 55.00% 1034.2 26.30% 257.2 34.10% Ivishak 8951 9053 3726.8 68.70% 331.4 45.00% 2899.1 73.70% 496.3 65.90% 8951 8960 2594.0 47.8% 189.5 25.8% 2404.5 61.1% 0.0 0.0% 8965 8990 539.6 10.0% 123.4 16.8% 395.1 10.0% 21.1 2.8% 8995 9012 593.5 10.9% 18.6 2.5% 99.8 2.5% 475.1 63.1% Below 9012 Trace Trace Trace Trace Total: 5422.6 735.8 3933.3 753.5 Table 2: Interpreted Surface Rates converted from downhole rates. Gas Water Pool Perforation Oil Rate rate rate To, From , ft ft STB /D % Mscf /D % STB /D % Aurora 6870 6894 359.8 55.40% 385.2 26.70% 250 34.30% Ivishak 8951 9053 289.7 44.60% 1059.1 73.30% 479 65.70% 8951 8960 167.2 25.7% 854.4 59.2% 0.0 0.0% 8965 8990 104.1 16.0% 218.2 15.1% 20.3 2.8% 8995 9012 15.7 2.4% 56.7 3.9% 456.3 62.6% Below 9012 Trace Trace Trace Total: 649.5 1444.3 729 "Splits within the Ivishak are as requested. Zonation within a flowing interval has higher uncertainty due to instability in the flow regime. Surface rates on the day the product log was acquired were: 792 bpd oil; 876 bpd water; 1610 mscf gas 2 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 3. Production Log Interpretation: BP Exploration (Alaska), Inc. (BP) well S -26 is a producing well located in Prudhoe Bay field. This well is producing from two separate pools, the upper Aurora (Kuparuk) and lower Ivishak (Prudhoe Bay). The Ivishak is producing from a perforated 7.0" cemented liner with open perforations from 8951 -9053 MD. The upper Aurora pool is producing from a 9.625" cemented casing open from 6870 -6874. 4.0" tubing is run PP P p 9 9 P 9 between the two intervals and above the Aurora with gas lift mandrels (see well sketch at end of report). The S -26 well was logged with the PS Platform production logging tools consisting of gamma ray, CCL, 99 P 99 9 9 9 Y temperature, pressure, gradiomanometer, 2.5" continuous spinner, in -line spinner, X -Y caliper, GHOST and DEFT. Both the upper and lower intervals were logged with three sets of u /down asses at both PP 99 P P production intervals (no logged continuously between due to large distance between production zones). Station stops were recorded at 9020, 8992, 8963, 8900, 8593, 8570, 8000, and 6650 at both gas lift rates. The well was shut in for 1 hour and two station stops were recorded at 8000 MD. The downhole temperature and pressure at 9010 ft. are 223.9 °F and 1507 psi. Data quality: Field data was depth matched to open hole gamma ray recorded May 24, 1990. Data quality is high, pressure and temperature is consistent within the logging passes indicating that well production was fairly stable. DEFT and GHOST holdup corrections were applied. Interpretation: Over -all downhole rates are lower than reported surface rates. Due to the changes in ID with this completion, inflow for perforated zones was computed in the 4.5" tubing for consistency. The increase to the 9.625" casing at the upper Aurora pool is causing apparent water recirculation. 3 BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 3.1. Interpretation Results: 16-Feb-2009 Survey The figure below shows cumulative production along with comparison between the reconstructed curves and stacked input curves for the full interval. Depth Van Skate Z Density match Gas holdup match Water holdup match Velocity match OZT 0 M (in) 0 91cc 1.2 0 1 0 1 -50 tVmin 350 -500 BID 6500 -500 BAD 6500 -7.8774 UWFD S5,11 YG 55,11 YW_DFT 55,11 VASPIN 55,11 UATCZ- 55,11 YGZ -> S5,11 'All _DFTZ 55,11 VASF'INZ -> 55,11 6700 680 1 6900 I 7000 1 7100 i 7200 i 7300 i 7400 7500 i 7600 I 7700 1 1 7800 i 7900 8000 8100 i 8200 I 8300 I 8400 i 8500 i 8600 8700 I i 8800 8900 i 1 9000 i i 1 9100 , 9200 — 4 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 16- Feb -2009: Cumulativ production and recons truct overlays for the u pper Aurora and lower Ivishak pools. Depth Veil Sketc Z Density match Gas holdi.p match Water holdup match Velocity match C1ZT O (ft) (in) 0 g/cc 1.2 0 1 0 1 -50 tVmin 350 -500 B/D 6500 -500 B/D 6500 - 7.9.74 UWFD 55,11 Y(I S5,11 iW F +T 55,11 V45F1f1 S5;' ;PV'FU 5.1I ;GZ-' '_`,11 DFTZ -x.1'1 'Vil " I I I 6700 I i I 6800 I' i I I 6900 i' i i i 7000 i i i . i 7100 I I I i 7200 Dept Veil Sketc Z Censlty match Gas holdtp hatch Water holdup matcl Vdocih maicr OZT G 1 (in) 0 cycc 12 0 1 C 1 -50 tUnin 550 -500 BrD 6500 -500 BAD 6500 - 7.ZM4 U P _;.ii _x,11 VN DFT 55,11 SPIM1I o`,I II "VV , F "TZ = 5511 .-TI'I 1 8703 I i I I ' 86303 i I i i I i a��u3 ! 1 9003 I i I I 1 I i I I I 1 I I 5 BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 16- Feb -2009: Correlation display for the up per Aurora and lower Ivishak pools.. ) ePt Well View* 1 II Sk Z GR TENS CCLD ID PFC1 PFC2 (tt) (ft - >Top) I (in) 0 GAPI 450 500 lb 1500 -8 8 -6. in 6. 8 in 0 0 in 8 � I I 70 1 I 8Q `� 1 s I j I I 90 I E 00 ; 10 ,i I 1► 1 I 20 )Rpit woI view 91 II Sk Z r_.R TENS CCLD ID PFC1 PFC2 (ft) (ft -> Top) (in) 0 GAPI 450,500 b 1500 -0 8 £. iI 6 J in 0 0 in 0 JU i E i � I , I 5. 1 0 0 sn UO I � I � i I e i i . i I I 10 i I ; I i i i 6 0 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Fi e l d: Prudhoe Bay 19- Feb -2009: PSP sensors up and down passes overla y display for the upper Aurora and lower Ivishak pools Depth ell Sket Z GR WPRE WTEP UVWFD SPIN SCVL (K) (in) 0 GAPI 450 900 psia 1120 182 T 210 0.2 g'cc 1 -10 rps 45 -120 1Vm 120 1�� 1 700 S 1 + - i 600 _ z i 1 I s00 S 1 I 2 I { l i 000 t` I I t! i 100 1 I +<y I I 200 Depth ell Sket W Z GR WPRE TEP UWFD SPIN SCVL (tt) (in) 0 GAP] 450 1380 psia 1520 214 T 226 0.2 rycc 1.2 -10 rps 18 -120 t min 120 I i 700 t [! I I I 800 1 I T �ym I s I S I 900 I I i 000 t` } I l I i 100 ' I I I I ii i 1 � _ i I 9200 i 7 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 19 -Feb -2009: GHOST down passes overlay plot. Note high water holdup due to recirculation in the 9.625 casing interval. Depth DFH1 DFH2 DFH3 DFH4 D1RB YW_DFT DEFT 32 D bib 32 (ft) 0 1 0 1 0 1 0 1 0 360 0 1 1 0 0 829.563 s „ t 70 OC z. 80 • -hub ... ; 00 1 ! I 1 �,•► �a 10 t •' _ qft .► 20 eP • UFH1 UFH2 OF H3 01-H4 U1Rd Y`N_UFI UtF t2 U bub 62 M 0 1 0 1 0 1 0 1 0 360 0 1 1 0 0 886.12L 1 070 .wr I �* I I i fi0 3900 � I O0Q 't 10 20 g 0 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 19- Feb -2009: GHOST down passes overlay plot Depth GHH5 GHH6 GHH7 GHH8 D1RB2 YG GHOST 32 G BUB 32 (ft) 0 1 0 1 0 1 0 1 0 360 0 1 0 0.75 0 1245.42 i T - 6700 - - r .— - -- - - - -- s , r 6800 A r If AL 7000 `� • 7100 7200 - I r j 1 1 7300 +.► Depth GHH5 GHH6 GHH7 GHH6 D1RB2 YG GHOST 52 G BUB 52 (ft) 0 1 0 1 0 1 0 1 0 360 0 1 0 0.75 0 582.751 8700 41� 14L 8800 8900 9000 9100 9 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 3.3. Spinner Calibration: ❑ 30 X 0 10 X X 270 10 -20 30 -40 rps versus ft /min Threshold ( +) 9.8 fUmin Threshold ( -) -9.8 fl/min Calib. Zone Slope ( +) Slope () Int ( +) Int () Int. Diff. ft ft/min ftlmin ft/min ❑ 6707.8- 6747.7 0.089 N/A - 261.01 N/A 0.00 0 6779.2 - 6839.5 0.089 N/A -50.22 N/A 0.00 + 6914.2- 7014.1 0.089 0.090 -50.14 -63.27 13.13 X 7065.8- 7221.8 0.089 N/A - 18434 N/A 0.00 A 8727.1- 8903.9 0.099 N/A -58.58 N/A 0.00 V 9001.2- 9011.6 0.100 0.090 -0.13 -19.98 19.85 Spinner Calibration plot. 10 i • 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 3.4. Summary Table Results: Summary table of inflow zones: Zones 1 Zones 2 Zones 3 Zones 4 Zones 5 From, ft 6870 8951 8965 8995 9022 To, ft 16 8960 8990 9012 9053.1 Water FVF 1.0287 1.0362 1.0403 1.0414 1.0418 Viscosity, cp 0.357 0.3102 0.2854 0.281 0.2793 Density /cc 1 0.99 0.98 0.98 0.98 0.97 Oil +Gas FVF 1.126 1.144 1.1861 1.1881 1.1892 Viscosity, cp 1.918 1.5363 1.1544 1.1319 1.1219 Density, cc 0.81 0.8 0.78 0.78 0.78 Gas FVF 0.0174 0.0161 0.0114 0.0114 0.0114 Viscosity, cp 0.0141 0.0146 0.0158 0.0159 0.0159 Density, cc 0.055 0.0593 0.0835 0.0837 0.084 Temperature, 1= 187.13 207.28 220.44 223.09 224.08 Pressure, psia 945.46 1056.2 1488.6 1500.2 1508.7 Diameter, in 3.958 3.958 6.275 6.275 6.275 Deviation, ° 20.1 17.7 4.93 4.88 4.81 Roughness 1.16E -04 2.53E -04 1.59E -04 1.59E -04 1.59E -04 Rs, cf /bbl 148 160 232 233 234 Rsw, cf /bbl 6 6.45 8.67 8.75 8.79 V mixture, ft/min 267 179 20.6 10.8 0 Visc. Mixture ' cp 0.54 0.39 0.31 0.28 0.28 V cf 0.89 0.89 0.84 0.83 0.5 dQ res., B/D 1695.79 2594.01 539.62 593.54 0 % Qt 31.27 47.83 9.95 10.95 0 dQw res., B/D 257.21 0 21.13 475.14 0 dQw s.c., STB /D 250.04 0 20.31 456.27 0 dQo res., B/D 404.39 189.48 123.44 18.6 0 dQo s.c., STB /D 359.78 167.22 104.07 15.65 0 dQg res., B/D 1034.18 2404.53 395.05 99.8 0 dQg s.c., Mscf /D 385.26 854.43 218.24 56.72 0 Yw 0.248 0.309 0.786 0.954 1 Yo 0.232 0.186 0.075 0.011 0 Yg 0.52 0.505 0.14 0.034 0 Vslip, ft/min 243.443 204.263 50.854 43.702 0 Vslip W-O, ft/min 2.553 3.776 19.855 19.952 Regime Froth /chum Slug liquid -gas Bubble Bubble No flow Corral. Aziz and Govier Aziz and Govier Aziz and Govier Aziz and Govier Aziz and Govier Stanford Drift Stanford Drift Stanford Drift Stanford Drift Stanford Drift Corral. W -O Flux LL Flux LL Flux LL Flux LL Flux LL 11 • 0 BP Exploration (Alaska), Inc. Well: S -26 J ob Number: AYTU -00014 Field: Prudhoe Bay 4. Table of abbreviations: Tool Mnemonic Channel Description Units: Description CVEL Cable veloci CCLD/ B/D Barrels per Day CCLC Casing Collar Locator Discriminated / Calibrated DFB1 /2/3/ scf /bbl Standard Cubic Feet per Barrel 4 DEFT bubble count per probe DFH1 /2/3/ cp Viscosity centipoises 4 DEFT water holdup per probe ft/m Feet per minute SCV1 I Depth corrected cablespeed to in -lines inner cc Grams per cubic centimeter SCVL Depth corrected cablespeed to spinner MMSCF /D Million Standard Cubic Feet per Day GHHM2 Field calculated combined gas holdu MSCF /D Thousand Standard Cubic Feet per Day DFHM Field calculated combined water holdu Res. To denote reservoir conditions downhole MWFD Field pressure derived densi s Revolutions per second GR Gamma Ra GHB1 /2/3/ S.C. To denote surface conditions u hole 4 GHOST gas bubble count per probe GHH1 /2/3/ SCF Standard Cubic Feet 4 GHOST gas holdup per probe STB/D Stock Tank Barrels per Day SPI1 In -lines inner WPRE Pressure PVT: Pressure Volume Temperature DPHZ Pressure derived density from Emeraude Bo Oil volume factor PFC1 / PFC2 PSP Caliper 1 and Caliper 2 Bw Water volume factor Q Rate Relative bearing for probe 1 of second tool Bg Gas volume factor D1 RB2 GHOST FVF Fluid volume factor D1 RB Relative bearing of probe 1 GOR Gas Oil Ratio SPIN Spinner fullbore or turbine Watercut Ratio of produced water to total fluids WTEP Temperature Holdup Fraction of fluid present in an interval of pipe TENS Tension Uncorrected Fluid Density (from UWFD radiomanometer Interpretation: WFDE Well fluid density from radiomanometer Correlation Model L -G: Liquid Gas W -H: Water Corral. Hydrocarbon; O -W Oil -Water ID Internal Diameter PSP Production Services Platform Q Cumulate Rate with continuous solution DEFT Di ftal First Entry Tool (Water holdu OZl Incremental rate per zone GHOST Gas Holdup Optical Sensor Tool Gas holdu QZT Cumulative Rate track with zonal contribution Regime Modeled Spinner Calibration: Slope of rps/ (ft/m). Defines conversion of YG Gas Holdup Sloe spinner to velocity. YO Oil Holdup Int Intercept of line of slope defines veloci Difference between up /down passes. This is the YW Water Holdup Threshold velocity required to initiate rotation of the spinner. YW DFT Water Holdup from DEFT Z Zone: Yellow - spinner calibration Red - Perforation White - Inflow Zones Gray: Calculation stable zone 12 BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Fi e l d: Prudhoe Bay 5. Tool Diagram: MH -22 48.9 MH•22 AH -SAG G 47.3 AH G L� EQF - 43 45.8 EOF -43 EOF-43 39.8 EOF-43 EQF 43 33.8 EOF-43 Detail MT TelStatus PSPT - AIB CTEM 1 — 27.9 27.8 PSC-A PSPT -A PSTC 676 PBMS -A 772 GR —24.1 10k Sepphire_Mano RTCY Thermometer GR Well Temp 21.0 CCL Manometer _ 20.9 PBMS CCL _ 20.3 PBMS PSTC 19.6 PGMC -A!B ACCE 19.6 PGMC -B 852 Gradioman — 18.1 Accelero PSOI Gradio PGMC 14.8 PILS - A 14.8 PILS -AS70 Spinner 13.2 GHOST -A2 12.3 Flowmeter Probes Relative Bearing Caliper GHOC -C 701 GHOH -C GHOST2 Pr 7.2 GHOST2 Ca 7.1 GHOST2 Ca 5.1 PFCS Spin PFCS Cali 1.9 PFCS - PFCS Prob 1 1.6 5.1 Holdup Probes GHOST2 We HV Spinner 2.5 GHOST2 Re Relative Bearing PFCS Wave ip PFCS Rela Cal PFCC -A 856 PFCS Cart PFCH -A 856 Tension 0 TOOLZERO MAXIMUM STRING DIAMETER 1.69 IN MEASUREMENTS RELATIVE TO TOOL ZERO ALL LENGTHS IN FEET 13 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 6. Well Schematic: TREE = 4' OW SAFETY NOTES: NOT B=Y GC OF ANY WELL All -LFEAD = E �1 //�� OFMCRATION THAT COULD INCRCASE ROW OR AOTUATOR= 0713 S=2 EROSION RATES TO 3 SIOD FLOWLNE(POTEN" IAL KB. ELEV= 65.09 V VV EROSIOPf ) ""CHRDMETBG"'€'i'iiOLELF- AKIN BE ELEV = 37.49 C,-:U c' 7ZUU - 34,:4""' KOP = 4400 Max Angle = 23' 5178 2029' 4 -10 FES X NP .13 3.813' Datum MC = a073 Datum TVD= MOO' G-- GAS L.F7 AaANDRES 20" CONDUCTCR.= 110' ST MD ND DEV TYFE VLV LATCH PORT DATE :j 4 3635 3635 0 M1.�G DOWE P1C 16 05714/09 13.3'8" CSG, 68#. L -30 BUTT, D - 12.4161 3 5304 5251 23 K%C EMY f>f( 0 04/18/08 2 6217 6094 22 MMu MY PK 0 05127108 4- 12 "SYMPHONYGUA3Ew 1!- NREIC= 3.94" 1 65376391 21 MArtG S`O F1IC 22 05/27/08 66 )Q' 4-111" Ht7 X NY, IU= 3.2113` Minimum ID = 3.80" @ 8613' 4 -112°' OTISXN NIP, MILLED OUT 6891 9- 518"X4- 1/2 "13KRS- 3PKR,:O =3875" 6715 4 -10I-ES X NR ID= 3.813" 4 -1i2" 783. 12,6*. 13CR VAM TOP, X 152 bpf.:D - 3.958" 6780' 4- 12 "W 5.958' FN HOLE LEAK N 9-5 ?8" G5G (BEHIND LOWER ISOLATION STRINGI 70$2+ &618" X4 -1)2° BKRS -3 PKR i7= 3875" 4 -112' TB3, 12 611, 13CR VAM TOP 7066' -f4 1 t2" ttS X NP. ID= 3.813 X 152 W. ID = 3.958" 14-112 TBG STILE (12126/07) $520' 8531' 9 s/s" x 4 v2° LRJlOUE ovf3zsHOT 8540' 9 5B" X 4 112" OT15 PKR iC - 3.86" TOPOF 7 LNR 8593' 4- 1f2 "PAFKERSWSI RD=3 -813' 8613' 4.1x1 "UIfSXNNP, MLLtdJ1U3.tlU "(12/2h1U1) 4- 112" TBG 126#, L -EO TDS, .0152 bpf, ;D = 3.958" $625 4 -1/L' W/LEG, ID= 3.958' 47# NTSC wr n = A 681 ° 8627' -E-MD LOGGED 081 Fb*(JKA I KN SLNM1A KY FEF LOG S'NS BRCS OK 05/24150 ANGLE AT TOP PERF: 19' @ 6877 Njlc. P.vf w :u N,dwtiw DE fu/ hiniui L=n1 j- f Jdtd 8(130' 7" Z0f1N_ iSO -ATION PKR, (07128197} S.IE Sit N URVAL UFNSgz L)A le 3.3 /5* 4 6870-6894 -- 0T 8 3 -3/3" 4 8951-8961 O 08/26/90 9139' FISH- BKR ECP. SCOO° GLIDES, 3.31R" 4 SG65 - 9053 C nfirMA0 RUNNING TOOL. AND OLD OP 3 3t3" 4 9085 0130 S 00/10/94 3.3/3' 4 9184-9186 S 09110'94 - 9178 7" MA W9R JC %W PBTD i TAG3M 01117,93) 7" LNR 26k L -BO U44, 0?83 bpf. D = E.276" 9434' DATE FE\, BY CCMENTS DN TE REV BY Cohwmrs PPSJCHOE BAY LMT 06/04/90 N1BE ORIGINAL COMPLETION 05114,08 KSBJTLH GLV GO WELL 5 -26 01102/08 014 RWO 05lt1,0A - AV?R r,1 V ri0 (5'27/08) PFW:T Vn r 1AM53n 04106/06 RRrJ SV PERFOPATIONS (04)03108) 07/02,08 DHO/PJC DRLG DRAFT CORRECTMS AR No 50- 029 - 22047 -OC 041C0 /08 DAV /PJC GLV C10 09135,00 AR/PJC MILL rAODRILL (00+17100) 3CC 35, T12N. R12C 1335' rNL S I IGC' rWL U4120,08 KSHfPJL ULV L?U 05/C9/08 ? /PJC DRLGDFAFTCOaFECT10N5 SP Exploration (Alaska) 14 by schlumber PL Advisor Production Log Interpretation With GHOST and DEFT' (Revised Format —April 2009) Company BP Exploration (Alaska), Inc. Field Prudhoe Bay Well S -26 Date Logged 10 -Oct -2008 Date Processed 30 -Oct -2008 Reference Number 12017505 API Number 50- 029 - 22047 -00 Log Analyst Erika Bowen Alaska Data and Consulting Services 2525 Gambell Street, Suite 400 Anchorage, Alaska 99503 (907) 273 -1700 II interpretations are opinions based on inferences from electrical or other measurements and we cannot, and do not guarantee the accuracy or correctness of any interpretations and e shall not, except in the case of gross or willful negligence on our part, he liable or responsible for any loss, cost, damages or expenses incurred or sustained by anyone resulting rom any interpretation made by any of our officers, agents or employees. These interpretations are also subject to clause 4 of our general terms and conditions as set out in our current rice schedule. • . BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 1. Production Logging Objectives: The objective of this logging suite was to evaluate production splits between the Aurora and Ivishak pools. Three phase production interpretation was performed to determine oil, gas, and water splits. 2. Main Results: Table 1: 3.5 MMSCF Gas Lift: Interpreted Downhole Rates from multiphase solver. Tot.DH Oil Gas Water Pool Perforation prod. % Rate % rate % rate % From, ft To, ft B/D B/D B/D B/D Aurora 6870 6894 1717.4 36.07% 297.9 51.40% 1367.9 35.39% 51.6 16.31% Ivishak 8951 9053 1 3043.4 63.93% 1 281.7 48.60% 12496.9 64.61% 264.8 83.69% 8951 8960 2588.2 54.4% 226.2 39.0% 2362.1 61.1% 0.0 0.0% 8965 8990 187.6 3.9% 52.7 9A% 134.9 3.5% 0.0 0.0% 8995 9012 267.6 5.6% 2.8 0.5% 0.0 0.0% 264.8 83.7 Below 9012 0.0 0.0% 0.0 0.0% trace trace Total: 4760.8 579.6 3864.8 316.4 Table 2:3.5 MMSCF Gas Lift:interpreted Surface Rates converted from downhole rates. Oil Gas Water Pool Perforation Rate rate rate To, From , ft ft STB /D % Mscf /D % STB /D % Aurora 6870 6894 263.4 52.60% 527.9 29.06% 50.3 16.51% Ivishak 8951 9053 237.4 47.40% 1288.7 70.94%1 254.3 83.49% 8951 8960 190.7 38.1% 1208.1 66.5% 0.0 0.0% 8965 8990 44.3 2.6% 77.8 4.3% 0.0 0.0% 8995 9012 2.4 0.1% 2.8 0.2% 264.8 86.9% Below 9012 0.0 0.0% 0.0 0.0% trace Total: 500.8 1816.6 304.6 I 2 I • 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Fi Prudhoe Bay Table 3:2.1 MMSCF Gas Lift: Interpreted Downhole Rates from multiphase solver. Tot.DH Oil Gas Water Pool Perforation prod. % Rate % rate % rate % From, ft To, ft B/D B/D B/D B/D Aurora 6870 6894 1742 35.79% 237.6 40.83% 1443 36.46% 61.5 18.77% Ivishak 8951 9053 3125.6 64.21% 1 344.3 59.17% 2515.1 63.54% 266.2 81.23% 8951 8960 2650.0 54.4% 276.2 47.5% 2373.8 60.0% 0.0 0.0% 8965 8990 206.3 4.2% 65.6 11.3% 140.7 3.6% 0.0 0.0% 8995 9012 269.2 5.5% 2.5 0.4% 0.6 0.0% 266.2 81.2% Below 9012 0.0 0.0% 0.0 0.0% trace trace Total: 4867.6 581.9 3958.1 327.7 Table 4:2.1 MMSCF Gas Lift:lnterpreted Surface Rates converted from downhole rates. Oil Gas Water Pool Perforation Rate rate rate To, From , ft ft STB /D % Mscf /D % STB /D % Aurora 6870 6894 210.4 41.97% 537.7 29.36% 59.8 18.95% Ivishak 8951 9053 1 290.9 58.03% 1 1293.6 70.64%1 255.7 81.05% 8951 8960 233.5 46.6% 1208.3 66.0% 0.0 0.0% 8965 8990 55.3 11.0% 82.3 4.5% 0.0 0.0% 8995 9012 2.1 0.1% 3.0 0.2% 255.7 81.0% Below 9012 0.0 0.0% trace trace Total: 501.3 1831.3 315.5 3. Production Log Interpretation: BP Exploration (Alaska), Inc. (BP) well S -26 is a producing well located in Prudhoe Bay field. This well is producing from two separate pools, the upper Aurora (Kuparuk) and lower Ivishak (Prudhoe Bay). The Ivishak is producing from a perforated 7.0" cemented liner with open perforations from 8951 -9053 MD. The upper Aurora pool is producing from a 9.625" cemented casing open from 6870 -6874. 4.0" tubing is run between the two intervals and above the Aurora with gas lift mandrels (see well sketch at end of report). The S -26 well was logged with the PS Platform production logging tools consisting of gamma ray, CCL, temperature, pressure, gradiomanometer, 2.5" continuous spinner, in -line spinner, X -Y caliper, GHOST and DEFT. Both the upper and lower intervals were logged with three sets of u down asses at two different PP 99 P/ P rates of gas lift, first at 3.5MMSCF gas lift, than allowed to stabilized for 3 hours and logged at 2.1 MMSCF gas lift. Station stops were recorded at 9020, 8900, 8593, 8570, 8000, and 6650 at both gas lift rates. The well was shut in for 1 hour and two station stops were recorded at 8000 MD. Surface rates were recorded as 2.4 MMSCF formation gas, 800 BOPD, and 560 BWPD at 3.5 MMSCF gas lift and 2.4 MSCF formation gas, 940 BOPD, and 550 BWPD at 2.1 MMSCF gas lift. The downhole temperature and pressure at 9010 ft. are 223.8 °F and 1519 psi at 3.5 MMSCF gas lift; 223.8'F and 1508 psi at 2.1 MMSCF gas lift. 3 0 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay Data quality: Field data was depth matched to open hole gamma ray recorded May 24, 1990. Data quality is high, pressure and temperature is consistent within the logging passes indicating that well production was fairly stable. Variation within the station stops was less than 5 psi pressure, and under 10 rps change on spinners. DEFT probe #3 was not working after the first set of up /down passes at the Aurora pool at 3.5 MMSCF gas lift. DEFT probe #3 was removed from the water holdup computation for the remaining passes. Additionally a few minor spikes in DEFT and GHOST holdups data were removed to aid in stacking passes. Interpretation: Data indicated mostly standing water column at base of well up to 8958 MD. Spinner, density, DEFT, and GHOST indicate close to sump (no -flow) conditions below 9000MD. Over -all downhole rates are lower than reported surface rates. For the Ivishak interval, it was requested to break down the inflow into sub - zones. Since there are no stable intervals the division of production is suspect to higher uncertainty. From data indicators the lowest entry at 8998MD is majority water and some oil. The entry at 8974MD is predominately oil, and the main gas contributor is the upper perforation at 8951 -8961 MD. Spinner response indicates fluid recirculation in the 7.0" casing interval below the 4.5" tubing. Due to the changes in ID with this completion, inflow for perforated zones was computed in the 4.5" tubing for consistency. The increase to the 9.625" casing at the upper Aurora pool is causing water to drop out and recirculate in this interval. This is shown with the high water holdups and spinner response. Since water is recirculating in this interval before lifting again in the 4.5" tubing the water attributed to this zone has a higher uncertainty. There is approximately only a 10 psi pressure change between 3.5MMSCF gas lift and 2.1 MMSCF gas lift. There is less than 2 rps difference in spinner response also. Apparent downhole rates between the two sets of surface gas lift rates are essentially the same. There was no enough downhole rate variation with change in surface gas lift rates for a SIP (selective inflow performance) plot to be generated. 4 0 , BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.1. Interpretation Results: 3.5 MMSCF Gas Lift 3.5 MMSCF Gas Lift: The figure below shows cumulative production along with comparison between the reconstructed curves and stacked input curves. De pt 11 Ske 2 Density match Gas holdup match Water holdup match Velocity match DZT Q (ft) (in) p cc 1.2 0 1 0 1 -50 ft/min 350 -500 B/D 6500 -1000 BJD 8000 > > UWFD 50 11 r G." (Y9 Df T - A I VASMN SG 11 sJ nj { YG S6 11 J YVIf OFT S5 11 11 1 - t y I � 1 I i I i i I I I I I I I _ I l I i 7 I t � I { I i 5 • 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 F Prudhoe Bay 3.5 MMSCF Gas Lift: Cumulative production and reconstruct overlays for the upper Aurora and lower Ivishak pools. Depth 1 Ske Z Density match Gas holdup match Water holdup match Velocity match OZT O (ft) (in) 0 g/cc 1 2 0 1 0 T-50 fflmin 350 -500 BID 6500 -1000 BID 8000 -7 7. UWFU 1 .. VA,- A S II ' .' VG Ctiit �-� r ".-T S;..I < °_r'a:' F.BIt i c i I I - 1 � z I i i 1 . i Depth ll Ske Z Density thatch Gas holdup match Water holdup thatch Velocity match QZT Q (ft) (in) 0 g/cc 1 2 0 / 0 1 .50 ft/min 350 -500 BID 6500 -500 BID 7000 -7 7 UWFD Wit OW OF 11 i, WkSPIN jA 11 +' r IG S5 It VW DFT S61t ','A "IN. ;'1 i 1 r i i I i 1 I i I , J i ' I 1 ; i i I I 1 ii 6 0 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.5 MMSCF Gas Lift: Correlation display for the upper Aurora and lower Ivishak pools.. ept Well View 111 Z Nell Sketc ID PFC1 PFC2 COLD GR (ft) (ft Top) (In) -6 in 6 2 in 8 2 in 6 -6 6 0 GAN 300 9500 5800 7 i i'. i i . 3 I. . LL i i I i , ept Well View #1 Z ell Sket I PFC1 PFC2 CCLD GR (ft) (ft Top) (inj -6 in S 2 In 8 2 In 8 -6. 6. 0 GAN 300 9500 5800 -7 7 I I I - r - L L' i i I - I 7 r • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.5 MMSCF Gas Lift: PSP sensors up and down passes overlay display for the upper Aurora and lower Ivishak pools Depth Z Well Sketch 10 WPRE WTEP UWFD SPIN (ft) (in) -6. in 6 960 psia 1110 178 'F 206 0 orcc 1 -5 rps 40 _j I I I I I I I I s I I \(} j- i i I ; r _ 1 i S iI I � I Depth Z Well Sketch 1D : ^JPRE WTEP UtNFD SPIN (ft) (in) 6 in 6 134D psis 1540 212 F 226 0 gr 1 2 •15 rps 30 N. I �i It j J t i i i i I f I I 8 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.5 MMSCF Gas Lift: GHOST down passes overlay plot. Note high water holdup due to recirculation in the 9.625 casing interval. eP0 Z GHH5 GHH6 GHH7 GHHB D1RB2 YG GHOST ON20 (fti 0.2 1 2 -0 .2 1.2 -0.2 12 -0.2 1.2 0 360 0 1 0® 1 f Depth Z GHH5 GHH6 GHH7 GHHB D1RB2 YG GHOST Dn12 (ft) -02 12 -0.2 1 2 -02 1.2 -0.2 1 2 0 360 0 1 0 1 1 i= 9 r 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Fi Prudhoe Bay 3.5 MMSCF Gas Lift: GHOST down passes overlay plot Z II Sk DFH1 DFH2 DFH3 DFH4 D1RB Yw_DFT DEFT Dn18 (in) -0 2 1 2 -0 2 1 2 -02 1 2 -0 2 1.2 0 360 0 1 0 1 1 - -"` } i � f Z I Sk DFH1 DFH2 DFH3 DFH4 DiRB Yw_DFT DEFT Dn34 (in) -0 2 1.2 -01 1 2 -0 2 1 2 -0.2 12 0 360 0 1 0© 1 � I I►Ii�l II I I L' I I I I I J R I 't I � I I I , I � t t 10 • 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.2. Interpretation Results: 2.1 MMSCF Gas Lift 2.1 MMSCF Gas Lift: The figure below shows cumulative production along with comparison between the reconstructed curves and stacked input curves. Depth ell Sket Z Density match Gas holdup match Water holdup match Velocity match QZT Q (5) (in) 0 g/cc 1 2 0 1 0 1 -20 ft/min 420 -500 BID 6500 -500 B/D 8000 7.874 y.., a r�l. _ _. ir;�l'ly �51i UVVFD S511 S II Y1 ^J Dr 5511 P.- 1 - - 1 I I I - 1 I I I I - I I I I - i - 1 - I , i I d — a I _ - S — 1 11 9 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 F i e ld: Prudhoe Bay 2.1 MMSCF Gas Lift: Cumulative production and reconstruct overlays for the upper Aurora and lower Ivishak pools. Depth ell Sket Z Density match Gas holdup match Water holdup match Velocity match QZT Q (ft) (in) 0 gkc 1 2 0 1 0 1 -20 I'Vnin 420 -SDO BID 8500 500 BID 8000 -7.874 I t 1 - � I l 1 Y 1 _ f i _ i 1 — � 1 – I I j 1 I i t r i r � � _ � 1 Depth all Sket Z Density match Gas holdup match Water holdup match VelocKy match QZT Q YU (in) 0 g!cc 12 0 1 0 1 -20 ftlmin 420 -500 BID 8500 . BID 8000 •7.874 ti ._ _. '1 �� l VASrIN S , 11 JWFD 5511 YG S51I YW DFT S511 � 1 1 = 1 � ' !4 _ y i r � i I ■ 11 . I 12 i 0 0 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Pr Bay 2.1 MMSCF Gas Lift: Correlation display for the upper Aurora and lower Ivishak pools Depth WeIlView #1 i Z ell Sketc ID PFCI PFC2 CCLD GR (ti) (ft -> Top) (in) -6 In 6 2 In 8 2 In 8 -6 8 0 GAPI 300 9350 7500 -7 874874 I f I ( i j - I - i j r i )x epth Well View #1 Z ell Ske ID PFC1 PFC2 CCLD GR Ott ft -> Top) (in) -6. n 6. 2 n 8 2 In 8 -6 8 0 GAM 300 7500 6000 7 874874 F11 A F r, I r I L` i i s' `9 I 1 1 I I � i I y ' I 1 I 1 I 1 .nn I 13 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 F Pr Bay 2.1 MMSCF Gas Lift: PSP sensors up and down passes overlay display for the upper Aurora and lower Ivishak pools )ePtt Z ell Sket ID WPRE WTEP UWFD SCA SPIN (h1 (in) 6 In 6 960 psia 1130 178 r 208 0 grit 1 -120 ft/min 140 -10 rps 45 o I I � I 1 I I I 1 1 i I I I L i Ll i I � � i I 1 ' i I I I I � I I I I 1 L i r i I I I i f I I :)eptt Z ellSket ID WPRE WTEP UWFD SCVL SPIN (n) (in) -6 in 6 1350 psia 1520 212 F 226 0 g /cc 1 2 -140 ft/min 140 -15 rps 30 I I 1 I t - I I I I 1 1 I I 1 1 I I } I I I 1 1 I 1 I I 1 I 1 I I 1 I I I 14 fee MI iiiiiiiArs �i lo Mtn 0 . BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Fie Prudhoe Bay 2.1 MMSCF Gas Lift: GHOST down passes overlay display for the upper Aurora and lower Ivishak pools. Note high water holdup due to recirculation in the 9.625 casing interval. Depth Z GHH5 GHHG GHH7 GHH8 D1RS2 YG GHOSTDnM ft) 0 1 0 1 0 1 0 1 0 360 0 1 0© 1 s a r Depth Z GHH5 GHH6 GHH7 GHH8 D1RB2 YG GHOST Dn108 In) 0 1 0 1 0 1 0 1 0 360 0 1 0© 1 T s 5. f i 16 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.3. Spinner Calibration: 13 20 > & 10 IWI ARM no -160 80 160 =io -20 -30 A0 rps versus tUrnin Threshold ( +) 11.5 ft/min Threshold ( -) -11.5 ft/min Calib. Zone Slope ( +) Slope ( -) Int ( +) Int {) Int. Diff. ft ft/min ft/min ft/min 11 6715.0- 6751.0 0.089 N/A - 285.98 N/A 0.00 u 6783.0- 6853.0 0.098 N/A -40.49 N/A 0.00 + 7059.0- 7179.0 0.089 N/A - 184.45 N/A 0.00 X 8585.0- 8642.0 0.089 0.089 - 124.17 - 146.25 22.08 A 8699.0 - 8903.0 0.089 NIA -35.35 N/A 0.00 V 8967.8- 8984.9 0.112 0.057 -17.12 -40.12 2100 E 9007.0- 9024.0 0.101 0.080 13.11 -9.89 23.00 3.5 MMSCF Gas Lift: Spinner Calibration plot. Default 0.089 spinner slope used in 4.5" tubing section for consistency between flowing rates. 17 r BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prud B ay 30 X 0 20 10 X -160 160 -10 -20 30 4D rps versus ft/min Threshold { +) 11.5 ft/min Threshold { -) -11.5 ft/min Calib. Zone Slope { +) Slope { -) Int (+) Int { -) Int. Diff. ft ft/min ft/min ft/min I] 6715.0- 6751.0 0.089 N/A - 302.94 N/A 0.00 6783.0- 6853.0 0.080 N/A -84.45 N/A 0.00 + 7059.0- 7179.0 0.089 N/A - 199.78 N/A 0.00 X 8585.0- 8642.0 0.089 NIA - 145.38 N/A 0.00 A 8699.0- 8903.0 0.089 N/A -44.94 NIA 0.00 V 8968.2- 8988.7 0.109 0.080 -10.69 -41.41 30.72 9007.0- 9024.0 0.091 0.092 5.71 -17.29 23.00 2.1 MMSCF Gas Lift: Spinner Calibration plot. Default 0.089 spinner slope used in 4.5" tubing section for consistency between flowing rates. 18 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.4. Summary Table Results: Summary table for 3.5 MMSCF Gas Lift. From, ft 6870 8951 8965 8995 9022 To, ft 6894 8960 8990 9012 9053.3 Water FVF 1.0268 1.0389 1.0397 1.0412 1.0418 Viscosity, cp 0.3698 0.291 0.2875 0.2816 0.2791 Density, g /cc 0.99 0.98 0.98 0.98 0.97 Oil +Gas FVF 1.1311 1.1861 1.1889 1.1911 1.1926 Viscosity, cp 1.9065 1.1738 1.149 1.1216 1.1081 Density, g /cc 0.81 0.79 0.78 0.78 0.78 Gas FVF 0.0159 0.0114 0.0113 0.0113 0.0112 Viscosity, cp 0.0141 0.0158 0.0159 0.0159 0.016 Density, g /cc 0.061 0.0849 0.086 0.0859 0.0862 Temp. F 182.42 217.27 219.25 222.73 224.21 Press psia 1012.9 1476.6 1500.3 1511.5 1521.4 Diameter 8.681 6.275 6.275 6.275 6.275 Devi. ° 19.51 4.9 4.93 4.88 4.81 Roughness 1.42E -04 1.59E -04 1.59E -04 1.59E -04 1.59E -04 Rs, cf /bbl 164 235 238 238 239 Rsw, cf /bbl 6.42 8.6 8.73 8.8 8.86 Q tot res., B/D 5726.62 3044.4 454.8 267.63 0 dQ res., B/D 1717.44 2588.2 187.56 267.63 0 % Qt 36.07 54.36 3.94 5.62 0 Qw tot res., B/D 312.76 264.22 264.42 264.79 0 Qw tot S.C., STB /D 304.61 254.32 254.32 254.32 0 dOw res., B/D 51.64 0 0 264.79 0 dQw S.C., STB /D 50.29 0 0 254.32 0 Qo tot res., B/D 569.94 281.58 55.53 2.83 0 Qo tot S.C., STB /D 503.87 237.41 46.71 2.37 0 dQo res., B/D 297.87 226.15 52.71 2.83 0 dQo S.C., STB /D 263.35 190.7 44.33 2.37 0 Qg tot res., B/D 4843.91 2498.59 134.85 1.00E -02 0 Qg tot S.C., Mscf /D 1799.84 1288.67 80.59 2.81 0 dQg res., B/D 1367.93 2362.05 134.85 1.00E -02 0 dQg S.C., Mscf /D 527.86 1208.08 77.79 2.81 0 Yw 0.304 0.497 0.912 0.997 1 Yo 0.393 0.122 0.039 0.002 0 Yg 0.303 0.38 0.049 0.001 0 Regime Elongated bubble Elongated bubble Bubble Bubble No flow Corral. Petalas and Aziz Petalas and Aziz Petalas and Aziz Petalas and Aziz Patellas and Aziz Stanford Drift Stanford Drift Stanford Drift Stanford Drift Stanford Drift Corral. W -O Flux LL Flux LL Flux LL Flux LL Flux LL 19 0 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Pr Bay Summary table for 2.1 MMSCF Gas Lift. ft 61170 8951 8965 To, ft I 6894 ( 8960 I 8990 I 901 0 2 I 9186 Water FVF 1.0272 1.039 1.0396 1.0412 1.0417 Viscosity, cp 0.367 0.2911 0.2881 0.2817 0.2797 Density, g /cc 0.99 0.98 0.98 0.98 0.97 Oil +Gas FVF 1.1295 1.183 1.1857 1.188 1.1892 Viscosity, cp 1.9106 1.1871 1.1638 1.1342 1.123 Density, g /cc 0.81 0.79 0.78 0.78 0.78 Gas FVF 0.0161 0.0115 0.0114 0.0114 0.0114 Viscosity, cp 0.0141 0.0158 0.0158 0.0159 0.0159 Density, g /cc 0.0594 0.0828 0.0839 0.0838 0.0841 Temp. F 183.43 217.26 218.94 222.65 223.86 Press psia 1005.4 1465.6 1489.9 1501.3 1509.1 Diameter 8.681 6.275 6.275 6.275 6.275 Devi. ° 19.51 4.9 4.93 4.88 4.81 Roughness 1.41E -04 1.59E -04 1.59E -04 1.59E-04 1.59E -04 Rs, cf /bbl 160 230 233 233 234 Rsw, cf /bbl 6.37 8.55 8.67 8.75 8.8 Q tot res., B/D 5845.62 3126.82 475.16 269.24 0 dQ res., B/D 1742.04 2649.99 206.32 269.24 0 % Qt 3519 54.44 4.24 5.53 0 Qw tot res., B/D 324.06 265.63 265.79 266.19 0 Qw tot S.C., STB /D 315.49 255.66 255.66 255.66 0 dQw res., B/D 61.45 0 0 266.19 0 dQw S.C., STB /D 59.83 0 0 255.66 0 Qo tot res., B/D 570.39 344.15 68.05 2.45 0 Qo tot S.C., STB /D 505 290.93 57.39 2.06 0 dOo res., B/D 237.59 276.22 65.6 2.45 0 dOo S.C., STB /D 210.38 233.54 55.33 2.06 0 Qg tot res., B/D 4951.17 2517.04 141.32 0.6 0 Qg tot S.C., Mscf /D 1811.29 1293.6 85.3 3.01 0 dQg res., B/D 1443 2373.77 140.72 0.6 0 dQg S.C., Mscf /D 537.65 1208.3 82.29 3.01 0 Yw 0.307 0.474 0.902 0.997 1 Yo 0.386 0.148 0.047 0.002 0 Yg 0.307 0.378 0.051 0.001 0 Regime Elongated bubble Elongated bubble Bubble Bubble No flow Corral. Patellas and Azfz Palates and Aziz Petalas and Aaz Petalas and Aziz Petalas and Aaz Stanford Drift Stanford Drift Stanford Drift Stanford Drift Stanford Drift Corral. W-O Flux LL Flux LL Flux LL Flux LL Flux LL 20 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 4. Table of abbreviations: Tool Mnemonic Channel Description Units: Description CVEL Cable veloci CCLD/ B/D Barrels per Day CCLC Casing Collar Locator Discriminated / Calibrated DFB1 /2/3/ scf /bbl Standard Cubic Feet per Barrel 4 DEFT bubble count per probe DFH1 /2/3/ cp Viscosity centi oises 4 DEFT water holdup per probe ft/m Feet per minute SCV1 Depth corrected cablespeed to in -lines inner /cc Grams per cubic centimeter SCVL Depth corrected cablespeed to spinner MMSCF /D Million Standard Cubic Feet per Day GHHM2 Field calculated combined gas holdu MSCF /D Thousand Standard Cubic Feet per Day DFHM Field calculated combined water holdu Res. To denote reservoir conditions downhole MWFD Field pressure derived densi s Revolutions per second GR Gamma Ra GHB1/2/3/ S.C. To denote surface conditions u hole 4 GHOST gas bubble count per probe GHH1 /2/3/ SCF Standard Cubic Feet 4 GHOST gas holdup per probe STB /D Stock Tank Barrels per Day SP11 In -lines inner WPRE Pressure PVT: Pressure Volume Temperature DPHZ Pressure derived density from Emeraude Bo Oil volume factor PFC1 / PFC2 PSP Caliper 1 and Caliper 2 Bw Water volume factor Q Rate Relative bearing for probe 1 of second tool Bg Gas volume factor D1 RB2 GHOST FVF Fluid volume factor D1 RB Relative bearing of probe 1 GOR Gas Oil Ratio SPIN Spinner fullbore or turbine Watercut Ratio of produced water to total fluids WTEP Temperature Holdup Fraction of fluid present in an interval of pipe TENS Tension Uncorrected Fluid Density (from UWFD radiomanometer Interpretation: WFDE Well fluid density from radiomanometer Correlation Model L -G: Liquid Gas W -H: Water Corral. Hydrocarbon; O -W Oil -Water ID Internal Diameter PSP Production Services Platform Q Cumulate Rate with continuous solution DEFT Digital First Entry Tool (Water holdu QZI Incremental rate per zone GHOST Gas Holdup Optical Sensor Tool Gas holdu QZT Cumulative Rate track with zonal contribution Regime Modeled Spinner Calibration: Slope of rps/ (ft/m). Defines conversion of YG Gas Holdup Sloe spinner to velocity. YO Oil Holdup Int Intercept of line of sloe defines veloci Difference between up /down passes. This is the YW Water Holdup Threshold velocity required to initiate rotation of the spinner. YW DFT Water Holdup from DEFT Z Zone: Yellow - spinner calibration Red - Perforation White - Inflow Zones Gray: Calculation stable zone 21 I � � BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 5. Tool Diagram: DOWNHOLE EQUIPMENT M H -22 48.9 MH SAH - G 47.3 SAH - G 1015 EQF - 43 45.8 EOF EQF - 43 39.8 EGF-43 EQF -43 33.8 EQF-43 Detail MT TelStatus PSPT -A/B CTEM 1 _ 27.8 27.8 PSC -A PSPT -B 876 PSTC 876 PBMS -B 876 GR _ 24.1 COG F Mano RTD'hermometer GR 876 Well Temp 21.1 CCL 876 COG Wanom / 20.7 PBMS 876 CCL = 20.3 PBMS PSTC 19.6 PGMC - AlB 19.6 PGMC -A 1839 Gradioman _ 18.1 PSOI Gradio 3726 PGMC 14.8 PILS - A 14.8 PILS - A 869 Spinner _ 13.2 GHOST -A2 12.3 Flowmeter Probes 733 Relative Bearing 733 GH pe C 33 GHOFI -C GHOST2 2 Pr / 7.1 GHOST2 Ca 5.1 PFCS Sppin !' PFCS Cai 1.9 PFCS -A PFCS Prob V10 1.5 5.1 HV Holdup Probes 762 GHOST2 Wa Spinner 2.5 762 GHOST2 Re Relative Bearing PFCS Wave Caliper 762 PFCS Rela PFCC -A 762 PFCS Cart PFCH -A 762 Tensio TOOLZERO MAXIMUM STRING DIAMETER 1.69 IN MEASUREMENTS RELATIVE TO TOOL ZERO ALL LENGTHS IN FEET 22 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 6. Well Schematic: TREE= 4 'C.W SAFETY NOTES: NOTIFY GC OF ANY WELL W,ELLI -EA D = F �1 !!''�� /'e OPEDQtATION TIIAT COULD INCRCP.SC FLOW OR ACTUATOR= 07Z S Q L /'► EROSION RATES TO3 - $KID FLOWLWE(POTEWIAL KB_ ELEV= 85.09 V V EROSION) CHROMETBG""PIWOLC LEAK iN9.318" BF. E"EV = S7.49 cac a 7zJO • a434'""" KOP= 4400 Max A r19fa = 23" 4 5178 2029 4 -12' HES X NF? ID= 3.813' Datum UT = 3073 Datum TVD C800'c GAS L!FT M19ANDRE_S 20- CONDUCiCR =' i 1 0' ST A4C TVD CEV TYPE VLV LATCH PORT DATE 4 3635 3635 0 WAG C10M£ R1C 16 1 05/14108 13 - &8" CSG. 08Vt, L -30 BUTT, D - 12.41;1 3 5304 5251 23 Mr, PK 0 04/18/08 2 6217 6094 22 1,4M DIAY W 0 05127!08 4- 112 "SYMPHONYGUA3Ew1I - 12/119 IC = 344" 1 &537 6391 21 MMG S`O IN 22 051171 6670' 4.1/1" Fkti X NY, N= 3.81 Minimum ID = 3.80" @ 8613' 4 -112" OTIS XN NIP, MILLED OUT 6691 9- 518 ° -1t2" BKRS.3 PKR. 0= 3875' b715' 4 -12" FIES X NF', ID= — 38 - 1T - 1 4- L2" T133,12.6*. 13CR YAM TOP C152 bpf, 0-3 968" 6780' 4.112 WILED. A= 3.958' PN HOLE LEAK 14 9. 518" CSG (BEHIND LOWER ISOLATION STRING) 7042' 9.58" X 4- 112° BKRS -3 RWR 1:) = 3 875' 4 - 10 TBG. 12 60,13CR VAM TOP H 7066 4 HE NN F', ID= 3.813 .052 bpf. 0=3.958" 4 _7 TBG ST(& (9212607) 8520' ' 8531' 0 618"X 4 112" U IGLIE OVERSHOT 8540' 0 "' X 4 112° OTIS TOPOF 7" LNR Jfar 8570 9•brtl" X 1' LP8( KiX( ;J ='V 8593' 4"12" PARHER SIN Mt', D73 8613' 4-11'1 "UIDXNNF', MLLtUiU3.tlU "(111fi1U,') 4 -1'2 "TBG. 126x, 1.40 T1�..0152 blrf.:D = 3.958° 8625' 4 .12" W1LEG, iD = 3 .958' S - 5.11" CSC,, 474, Kim: wrr. Il = p 6A i H 8�2r ELMD L 00! 15'90 H41d-UFtAI itAV SU1"J(Y1 KY FEF LOG SJVS BRCS ON 05/24/90 ANGLE AT TOP PEFF: 10" 687T NAb. Rata .v Rcdu:tbtr DE rut wbu Lai par f Jata 9030' 7" 20NA- iS0✓1T'ON SILL bNF N ERVAL UPNSq. (b1It 6870.6894 1 3 -313" 4 $961 -8961 O 08/26190 9139' FAH BKR MR SC00' GLIDE. 3.319" 4 9!48.5. (: 091711/90 RLMNC TOOL. AND OLD OP 3 319° 4 9085 9130 S 00 3 -313" 4 9184-9186 S 09/10x94 91 H"r MARKER JCANT PBTD (TAGGED 01117193) 7" LNR 2�! L -80 'J45, .0383 bpf, D = 9.276° 9434' Y I COMWNTS LATE I REV BY COWENTS PRA-HOE 3AY M,T 06/04/90 N1BE ORIGINAL COMPLETION 05114,08 KSBITLH GLV 00 WELL S-26 01!021011 014 RWO (IRA lOR - AV1TT) ('IV (H] (5 PF &:T 1 4 t r 19(DF9f) 04106106 FW- SV PERFORATIONS (04103108) 0710208 DHOVPJC DRLG DFAFT CORRECTIONS AP 4o. 50 -029- 22017 -0C 041C0 10B DAV /PJC GLV C/O 09 ?35100 - ArvpJC KILL fAwml. (00117100) SEC 35. T1 2N, 1112C 133 rTL A 110V r WL U4 /moii KStYr'J(; uLV UU 05iC9 /08 ?iPJC 0RLGDR4FTC0RFECT110NS OP Exploration (Alaska) 23 ~9 ICE: 526 Downhole Commi~pplication ~ Page 1 of 2 ,~ . . Colombie, Jody J (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, November 07, 2007 11:30 AM To: Williamson, Mary J (DOA); Saltmarsh, Arthur C (DOA) Cc: Colombie, Jody J (DOA) Subject: RE: S-26 Downhole Commingling application Jane, I support their plan. A workover will be necessary to gain access to the 7" casing across the Kuparuk. It may be appropriate to have a bond log run in the 9-5/8" casing as part of that work. I have examined the well file and it appears that the 9-5/8'° cement may have channeled since the 9-5/8" x 13-3l8" annulus became plugged and it was necessary to cut and pull the upper portion of the 9-5/8" casing. There isn't much information in the file regarding the cementing. Isolation may be likely based on work attempted on W-29 which had suspect isolation; however it was not possible to squeeze cement as planned. In the order or AA submitting a 403 to conduct the workover should be specified since pullinglreplacing tubing on development wells in Prudhoe Bay Field does not ordinarily require a sundry. Let me know if you need anything else. Tom From: Williamson, Mary J (DOA) Sent: Tuesday, November 06, 2007 4:41 PM To: Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA) Cc: Colombie, Jody J (DOA) Subject: FW: S-26 Downhole Commingling application Please review the commingle request and let me know if you have need for a hearing. I don't, do you? BP will still need to send in a 403, but I don't have a problem with the commingling. I'll start working on the order. From: Roby, David S (DOA) Sent: Thursday, October 04, 2007 12:51 PM To: Williamson, Mary J (DOA); Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA) Subject: FW: S-26 Downhole Commingling application A revised version of the application. Dave Roby Phone: 907-793-1232 email: dave.roby@alaska.gov From: Young, Jim [mailto:Jim.Young@bp.com] Sent: Thursday, October 04, 2007 11:55 AM To: Roby, David S (DOA); Colombie, Jody J (DOA) Cc: Lenig, David C; Paskvan, Frank A; Ohms, Danielle H; Robles, Marcelo Subject: RE: S-26 Downhole Commingling application Jody, Please strike « File: Aurora IPA Commingle Request BP_COP-EMfinal.doc » from your records & replace with attached for the official application. 11/7/2007 ~E: 5-26 Downhole Commipplication ~ Page 2 of 2 r " Dave - A couple minor changes we're made to clarify when monthly GC sampling would start & that we don't anticipate significant crossflow potential unless shut-ins exceed 2 months (point at which isolation plug would be used). Thanks Jim Young «Young, Jim.vcf» «Aurora IPA Commingle Request BP_COP-EMfinal.pdf» From: Young, Jim Sent: Wednesday, October 03, 2007 4:31 PM To: 'dave.roby@alaska.gov' Cc: Lenig, David C; Paskvan, Frank A; Ohms, Danielle H Subject: 5-26 Downhole Commingling application Hello Dave, This took a bit longer to get signed off than I'd hoped, but Frank signed this today. Tommorrow, you'll get ahard- copy with Scott's signature on it as well, but I wanted to get something to you right away so we can get the ball rolling on the public notice. Thanks Jim « File; Kuparuk Ivishak Allocation Feasibility 07-616.pdf (Compressed) » « File: Aurora IPA Commingle Request BP_COP-EMfinal.doc (Compressed) » 11 /7/2007 I;.E: ~-~6 T)ov~rn~ole ~o~Tirnin~pplicatior~ ~ Wage fl of 1 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Wednesday, November 07, 2007 11:48 AM To: Colombie, Jody J (DOA); Norman, John K (DOA); Seamount, Dan T (DOA); Foerster, Catherine P (DOA) Cc: Birnbaum, Alan J (LAW); Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA) Subject: Cancel hearing S-26 Downhole Commingling application - Commissioners, Senior staff recommend cancelling the Nov 15 hearing, assuming there have been no protests or requests for a hearing. Jody, if the Commissioners agree to cancel the hearing, can you a-mail Jim Young (jim.young@bp,com), David Lenig David.Leng@bp,com, Frank Paskvan Frank.paskvan@bp,com and Danielle Ohms Danielle,Ohms@bp.com Jane 11 /7/2007 Page 1 of 2 Colombie, Jody J (DOA) From: Williamson, Mary J (DOA) Sent: Monday, October 15, 2007 3:48 PM To: Colombie, Jody J (DOA) Subject: S-26 Jody, Please put this in the S-26 !Aurora commingle file. Jane From: Williamson, Mary J (DOA) Sent: Monday, October 15, 2007 3:47 PM To: 'Young, Jim' Subject: RE: hydraulics commingling S-26 comments No word yet. November 9 is due date on hearing request. Nov. 15 is potential hearing date. From: Young, Jim [mailto:Jim.Young@bp.com] Sent: Monday, October 15, 2007 3:41 PM To: Williamson, Mary J (DOA) Subject: RE: hydraulics commingling 5-26 comments I did the hydraulics in Prosper. Hagedorn & Brown is a good correlation if you want to do a check in SNAP. The key factor is the Ivishak FGOR, currently estimated ~4000scf/b it provides a lot of natural lift. All of your data gathering suggestions sound good (basically what I had planned), we can live with those specifics. I'll have to ask about the MI......I think they can still do it, no more MI planned for Prudhoe, but we may have some things to learn about effect on Aurora GC. Any comments from the public yet? Not needing a hearing would certainly make everyone more comfortable about getting this on the 2007 rig scedule. Jim From: Williamson, Mary J (DOA) [mailto:jane.williamson@alaska.gov] Sent: Monday, October 15, 2007 2:35 PM To: Young, Jim Subject: hydraulics commingling 5-26 comments Jim, Do you have a copy of the hydraulics report? If in SNAP, I can run here. In my first glance of the S-26 it looks good but a few suggestions for additional data gathering. A static BHP of Aurora alone before commingling. (you might want to get a static pressure of Prudhoe perfs near the same time). geochem of the Aurora perfs producing along with a zonal production test of Aurora. Geochems should be collected the same time or as close as possible to the well tests and production logs. I'd suggest 1 or 2 additional production logs during the year. Possibly at month 3 and 1 year 10/16/2007 Page 2 of 2 We'll want a full report by the end of one year on the effectiveness of the testing and preliminary findings (e-mail fine) every 3 months till then. You mention MI. When are you expecting the MI injection to start? Will the geochem be greatly effected with MI breakthrough? Seem's like the oil composition will change. Jane 10/16/2007 ~8 STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRE F AOGCC R 333 W 7th Ave, Ste 100 ° Anchorage, AK 99501 M 907-793-1238 AGENCY CONTACT DATE OF A.O. Jod Colombie October 4 PHONE PCN R o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 October 5, 2007 THE MATERIAL BETWEEN THE OOUBLE LINES MUST BE PRINTED ~N ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classified ^Other (Specify) SEE ATTACHED INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TO Anchora e AK 99501 REF TYPE NUMBER AMOUNT DATE 1 VEN s AR1~ 02910 FIN AMOUNT SY CC PGM 1 08 02140100 2 REQUISITIONED qW: PAGE 1 OF TOTAL OF 2 PAGES ALL PAGES$ COMMENTS LC ACCT FY NMR oisr 73451 DIVISION APPROVAL: NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO-02814017 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE 02-902 (Rev. 3/94) ~/ Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM • • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Prudhoe Bay Field Aurora Oil Pool and Prudhoe Oil Pool Application to allow commingling of production from the Aurora Oil Pool and Prudhoe Oil Pool within Well 5-26 By letter dated October 3, 2007, BP Exploration (Alaska) Inc. as Unit Operator of the Prudhoe Bay Unit requested the Commission to issue an order in conformance with 20 AAC 25.215(b) allowing commingling of production from the Aurora Oil Pool and Prudhoe Oil Pool within Well 5-26. The bottomhole location of the well is in Section 35, T12N-R12E, Umiat Meridian. The Commission has tentatively scheduled a public hearing on this application for November 15, 2007 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on October 25, 2007. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please ca11793-1221 after November 10, 2007. In addition, a person may submit a written protest or written comments regarding this application and proposal to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Protests and comments must be received no later than 4:30 pm on November 9, 2007 except that if the Commission decides to hold a public hearing, protests or comments must be received no later than the conclusion of the November 15, 2007 hearing. If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact the Commission's Special Assistant Jody Colombie at 793-1221. a Cathy . Foerster Commissioner • f~EIVED Anchorage Daily News 0 C ~ 1 6 2001 lois~2oo7 Affidavit of Publication f~ ~+ ]001 Northway Drive, Anchorage, AK 99508 ~1~8$k8 Ui~ & C]8S C~t1S. CiUf711111SSI4f1 AnChntage PRICE OTHER OTHER OTHER OTHER THER GRAND AD # DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 352262 10/05/2007 02814017 STOF0330 $192.56 $192.56 $0.00 $0.00 $0.00 $0.00 $0.00 $192.56 Notice of Public Heating. STATEOFALASRA-- Alaska Oil and Gas Conservation Commission Re: .Prudhoe Bay Field Aurora Oil Pool and Prudhoe Oil Pool Application to allow commingling of production STATE OF ALASKA from the Aurora Oil .Pool and Prudhoe oil Pool within well s-zs THIRD JUDICIAL DISTRICT By letter dated october 3, 2007, BP exploration (Alaska) Inc. as Unit Operator of the Prudhoe Bay Unit r in d Angelina Benjamin, being first duly sworn on oath deposes and t ti f th A h h h i d i i e requested the Commission to issue an or conformance with zo AAC zs.21 s(b) allowing comminSling of production from the Aurora Oil Pool The bottomhole ll 5-26 W i hi orage vert a ve o e nc at s e s ng represen says t s an a . n e t and Prudhoe oil Pool w location of the well is in Section 35, T72N-R12E, Umiat Dail News a dail news a er. Y ~ Y P P Meridian. That said newspaper has been approved by the Third Judicial The Commission has tentatively scheduled a public Court, Anchorage, Alaska, and it now and has been published in hearing on this application for November t5, 2007 at 9:00 am at the offices of the Alaska Oil and Gas the English language continually as a daily newspaper In Conservation Commission at 333 West 7th Avenue, a Anchors e Alaska and it is now and durln all Sald time was K ~ ~ g y Suite 100; Anchorage, Alaska 99501. Aperson m request that the tentatively scheduled heanng be held printed in an office maintained at the aforesaid place of by filing a written request with the commission no later than 4:3o pm on october zs, 2007. publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in If a request for a hearing is not timely filed, the Commisswn may consider the issuance of an order supplemental form) of said newspaper on the above dates and without a hearing. ro learn if the commission wilt hold the public hearing, please call 793-1221. after that Such news a er was re larl distributed to its Subscribers p p gu y November 10, zoo7. during all of said period. 'That the full amount of the fee charged . a person may submit a written protest Ih addition for the foregoing publication is not in excess of the rate charged , dr written comments regarding this application and proposal to the Alaska Oil and Gas Conservatioh rivate individuals. P Commission at 333 West 7th Avenue, Suite 100. Anchorage, Alaska 99501. Protests andCOmmentS must be received no later than 4:30 pm on November 9, 2007 except that if the Commission decides to hold a public hearing, protests or comments must be' received no later than the cdnclusion of the November ~ 15, 2007 hearing. Signed /~ tf you are a person with a disability who may need speaal accommodationsin order to comment or to attend the Qublic hearing, please contact the Commissions Special Assistant Jody Colombie at Stabscribed end sworn tom before this date: 793-1221. Cathy P: Foerster Commissioner Q // AO-02814017 Publish: October 05, 2007 Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY ~® ~~R~~ ~t S $ ~~ r~~i ~- _„ •, ,. .. _ ,~ „ !~ °°' ;~t1~1. .. v ~ ~ ~•o~ or.n "^c ~~. ~-.°; i • Colombie, Jody J (DOA) From: Ads, Legal [legalads@adn.com] Sent: Thursday, October 04, 2007 2:54 PM To: Colombie, Jody J (DOA) Subject: RE: Public Notice PBU Attachments: STOF0330 - Ad Preview.pdf; STOF0330 - Receipt.pdf Page 1 of 2 Following is the confirmation on your legal notice. Please fully review all attachments and let me know if there are any. changes., Please let me know if you. have any questions or need additional information. Account Number: Legal Ad Number Publication Date(s) Your Reference Number: Total Cost of Legal Notice: Thank you, Angelina Benjamin Legal Classifieds Representative Email: legalads@adn.corn P: (907) 257-4296 F: (907) 279-8170 Anchorage Daily News 1001 Northway Drive Anchorage, Alaska 99508 STOF0330 352262 October 05, 2007 02$14017 $192.56 Ask me how to get Uour ad online at www.legalnotice.org, linked through www.adn.com! Ask me how to advertise in the "Don't Drink £~ Drive" pa$e on Halloween, Thanksgiving, Christmas and New Years! -----Original Message----- From: Colombie, Jody J (DOA) [mailto:jody.colombie@alaska.gov) 10/4/2007 • ;1 w ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED H ATTACHED COPY OF AO-02814017 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WIT ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue. Suite 100 Anch~rage_ AK 9951 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News October 5, 2007 PO Box 149001 h r AK 99514 A THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ric o a e g ~ ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2007, and thereafter for consecutive days, the last publication appearing on the day of 2007, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This day of 2007, Notary public for state of My commission expires Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation /~ Land Department I~ ! / PO Box 129 ~ O /l Barrow, AK 99723 '{ 1~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, October 04, 2007 12:59 PM Subject: Public Hearing Notice PBU Attachments: Aurora and Prudhoe Commingling.pdf 10/4/2007 ~ 7 :' BP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 581 October 4, 2007 Alaska Oil and Gas Conservation Commission 333 West 7't' Avenue, Suite 100 Anchorage, AK 99501 ;.. "...~ )v 9 r ~~. RE: Application for Down-hole Commingling of Production from Aurora and Prudhoe Pools by In its capacity as Operator of the Aurora Oil Pool (AOP) and the Prudhoe Oil Pool (POP), BP Exploration (Alaska) Inc. ("BP") hereby requests approval to commingle production from the AOP and POP in the same wellbore. Because commingling of production from the AOP and POP will not cause waste, but rather should allow for recovery of a greater quantity of oil, and such production can be properly allocated, BP requests that the Commission issue an order authorizing the commingling of production from the AOP and the POP within the same well-bore. Plans are to commence commingling of production from AOP and POP in Well 5-26 by the end of 2007 if approval can be obtained in time. The following information is provided to support this application. Please call Jim Young 564-5754 or Danielle Ohms 564-5759 if you have any questions. Sincerely, ~,,.. .4 +,. p`, ~' ~. ;• Frafik t'a_fiJcvan~~t:t~it I~gcrl Subsurface Resource Managers, GPB WEST / WF Attachment 1: OilTracers Report No. 07-616 (CONFIDENTIAL) CC(electronic): Sherry Gould (BP commercial) Hank Bensmiller (ExxonMobil) Don Ince (CPAI) ~, Aurora Prudhoe Commingling 10/4/2007 Introduction Commingling of production within the same well-bore from two pools is permitted under 20 AAC 25.215(b) if the Commission, after notice and opportunity for public hearing, "(1) finds that waste will not occur, and that production from separate pools can be properly allocated; and (2) issues an order providing for commingling for wells completed from these pools within the field." Waste Will Not Occur 1. Production Considerations Well 5-26 penetrates the AOP and POP in areas where well rates from both Pools are very low. In low rate wells, frequent production problems (e.g., paraffin and hydrate deposition) are encountered due to low flowing temperatures associated with the North Slope permafrost. Intervention options such as hot-oiling, heat-trace, jet pumps, and continuous methanol injection can reduce down-time to as low as 10%. Although there is currently no AOP production from the 5-26 wellbore, the expected rate and remaining hydrocarbons do not justify drilling a standalone well. By commingling production from the two pools within the same well-bore, the fluid rate and velocity in the tubing can be increased, resulting in higher flowing wellhead temperatures and reduced production problems associated with wax and hydrate formation. Consequently, commingling of production from the AOP and POP within the same well-bore will not cause waste, but rather should allow for recovery of a greater quantity of oil. 2. Hydraulic Impacts on Production Well 5-26 was drilled in 1990 as a standalone producer from the POP, with a fracture stimulation. Production from Well 5-26 averages 800-950 stb/d liquid and 200-250 stb/d of oil, as shown in Table 1. This is considered a low rate for the existing 4-1/2" tubing, causing a large variability in test rates due to slugging. It is estimated that Well 5-26 has the Aurora Prudhoe Com gling • 10/4/2007 hydraulic capacity for an incrementa1500-900 stb/d of production without resulting in a significant change in flowing bottom hole pressure. Table 1 Well tests from 5-26, in standard oilfield units Well Bore Run Date Total Fluid Rate (bbls) Oil Rate (bbls) Water Rate (bbls) Form Gas Rate (mcfd) Gas Lift (mcfd) Gas Lift Press (psi) Form GOR (scf/ stbo) FTP (psi) WH Temp (f) WC Pct (%) 5-26 07/15/07 866 242 624 1,068 2,070 1,241 4,415 237 107 72 5-26 06/25/07 940 212 728 1,005 2,040 1,243 4,748 242 105 77 S-26 06/07/07 848 216 632 976 2,060 1,229 4,525 231 103 75 5-26 06/01/07 935 227 708 1,155 2,060 1,218 5,096 242 104 76 Using the expected S-pad AOP productivity of 500 stb/d, the relative and combined capacities are depicted in Table 2. An increase in AOP production is expected from commingling due to reduced down-time associated with wax issues mentioned earlier. Table 2. S-261iquid rate impact of commingling: Pool 2 wells Commingled delta (liquid) POP(75% wc) 900 stb/d 860 stb/d -40 stb/d AOP(0% wc) 450 stb/d 500 stb/d +50 stb/d Total 1350 stb/d 1360 stb/d +10 stb/d Fm. Gas Rate 1450 mcfd 1460 mcfd -8 mcfd AL Gas Rate 4000 mcfd 2000 mcfd -2000 mcfd Delta oil from wellbore = +490 stb/d Due to the low current POP production rate, no additional artificial lift (AL) gas would be required to handle additional liquid from the AOP. In a gas handling constrained environment, the reduced AL gas required for the commingled well (relative to two wells) results in an increase in oil production rate by utilizing the AL gas elsewhere. Since commingling requires a shallower gas-lift injection depth, a rate impact is expected to the POP later in life as water-cut increases. However, because the oil cut is lower at this point, the impact on oil rates to the POP is more than offset by additional production from the AOP by the reduced down-time and gas-handling benefits. This selective application of commingled production will result in an increase of overall recovery from both the Aurora and Prudhoe oil pools. • Aurora Prudhoe Commingling 10!4/2007 3. Cross flow Because both pools have similar in-situ fluid properties and share the same source of injection water, commingling should not result in formation damage. No fluid incompatibilities have been noted during ongoing surface commingling. Consequently, limits on cross flow are guided by reservoir management considerations. Pressure buildup behavior from both AOP and POP has been analyzed to assess cross flow potential and consequences. When a commingled well is shut-in, cross flow will be dictated by pressure buildup behavior within each pool. At initial shut-in, the pressure at each pool is equal to the wellbore pressure plus hydrostatic head caused by well bore fluid. The hydrostatic head between pools will be approximately 0.3 psi/ft and increases over time with producing water-cut. After a transient period after shut-in, the pressures within each pool will increase to a limit no greater than the average reservoir pressure. Direction of cross flow will be determined by which pool has the greater reservoir pressure at a given datum depth. A comparison of recent pressures in area wells is shown in table 3 to illustrate different cross flow scenarios. Table 3 Comparison of AOP & POP static pressure data near S-pad SW_ DATUM TEST_ PRES_ PRES_ PRESS_ DELTA PROJECT NAME DEPTH_SS DATE DAYS_SI DATUM 8800'SS PSI PRUDHOE S-26 8800' 9/11/05 6 3224 0.3PS1/FT ~S_26) AURORA S-108 6700' 6/14/07 14.92 2241. 2851 -373 AURORA S-108 6700' 3/29/06 300 2964 3574 370 At expected initial conditions of high AOP pressure in this area (>3000psi at 6700'ss datum), the differential pressure could exceed 300 psi. However, as confirmed by pressure-buildup analyses, low permeability in the AOP for this area results in an extremely long transient time before full reservoir pressure is seen in the well bore. Consequently, POP reservoir fluids may slowly cross-flow into the AOP until pressures equalize. Reservoir modeling suggests that this volume is expected to be small. Well 5-26 will be equipped with an X- nipple between the AOP and POP perforations, as shown in figure 1, to allow isolation of the pools by setting adown-hole plug for extended shut-ins (>2 months) or when separate zone pressure measurements are desired. Aurora Prudhoe Com~ lin g fi Figure 1. Proposed commingled completion • 10/4/2007 TRff = 4" OW WALHEAD = ACRYaTOR= OTIS KB. AEV = 65.09' BF. B.EV = 37.49' KOP= 4400' fv13z A le = 23 5366' Datum ND = 9073' Datum N D = 6600' SS OPHtATION VN~CR COILDINCF648E ROYV OR I 840.410N RATS TO 3' 310D ROYYLIFE (POTB(f WL Bi0.410tQ. S-26 R4 R4 Kupa-uk Ad-pens --6860-6900' MD FHKORATION sllaMRY R~ LOG: SWS BRCS ON 05/24190 ANGLE AT TOP PEf~: 4 ~ 8951' N01e: Rater t0 RoduCiian DB /or IJatorical data S2E SR= MHZVAL O4TE 33/8' a 8951 - 8961 O 0626190 33B' d 8%5 -9053 O 08/'28/90 33/8' 4 9085 - 9130 S 09/10/94 3-3/8' 4 9184 - 9186 S 09/1094 F -7000 I 862T anoTTLOGC,~oe/1y9o 987b' d-vr wn.EG DOTE ~V BV ODrMBJTS DOTE R2/ BV COf,T.8.R5 08/0490 OfiGINAL COMPLETION 04/26/03 ATD/TLH WAN62 SAFET' NOTE 09/OJ/01 HJ'TP ~CTK7f.G 0924/05 QL/TLH WANffi SFTY NOTE OB ETID 10/06/02 JM'KAK GLV GO 10/13/02 JAVKK WANER SAFTTTV NOTE 02/22/03 JhPMAK WANER SAFETY NOTE RE/ 03/09/03 JJ/TP GO GLVS Pid1D1i0E BAV lM WAL: 526 PSATf N0: 1800580 AR NO: Sb02322047-00 BP Brploratbn (Alaska) Appropriate Surveillance and Production Allocation Will Be Assured Appropriate surveillance and production allocation measures will be undertaken to meet reservoir management objectives and to provide an acceptable allocation methodology. 1. Production Allocation In addition to stand-alone tests prior to commingling, when commingling commences, monthly (30-producing days) geo chemical (GC) samples will be obtained and compared with production logs both initially and after 6-months of production. Fluid samples have Aurora Prudhoe Commingling 10/4/2007 been obtained from both pools to verify that GC analysis will allow for metering of pool oil, water and gas to within allocation quality accuracy. See attached report from Oil Tracers for more detailed information on this. After one year of commingled production, GC analysis will be completed semi-annually and production logs will be repeated as necessary to assess production anomalies based on well test results. 2. Reservoir Surveillance Long-term development plans for AOP and POP pools include water-flood and Enhanced Oil Recovery using Miscible Injectant (MI) from the Prudhoe Bay Miscible Gas Project. Reservoir pressure and hydraulic communication to offset injection support will be determined by comparing initial pressure and production from each pool with subsequent well tests.. If pressure maintenance is a concern, static pressures from each pool can be measured with the use of down-hole plugs and pressure gauges. If it is determined that a completion in one pool is adversely affecting production from the other pool, that completion can be isolated as necessary to ensure waste does not occur. To ensure the efficient allocation of MI, rate and pressure response to injection will be monitored in the production wells. Production fluid samples will be taken as needed to assess pattern efficiency based on the returned MI (RMI) ratio. Allocation of RMI from commingled production samples will be linked to gas production determined from production logging and GC analysis. Conclusion BP requests approval for well-bore commingling of production from AOP and POP, in Well 5-26. This activity will not create waste and produced liquids and gas from the separate pools can be properly allocated. During the first year of production, geochemical analyses of oil samples will be performed monthly to verify agreement with stand-alone tests and production logging results. Thereafter, it is proposed that geochemical analysis be performed semi-annually to properly manage and allocate long-term production. ·~6 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 Group 3 - Prudhoe Satellite Oil Pools ___ ___ .______ __________ .___n______.._____ ____ _______ Aurora C0457B Rule 8 6/25/2004 Boreallis C0471 Rule 4 5/29/2002 - __n ___ _.__ _ __ _____.__.__________. _ .______ Midnight Sun C0452 Rule 11 11/15/2000 _._.._--_._-_.._._._--------~ ---.--.---.--.---- -------- ---.---..---------.------ Orion C0505A Rule 9 4/28/2006 .__.._ ___. .___.______ ____ .._________.________ .__.__..__.________. _____.n_________ ____________________________________ Polaris C0484A Rule 9 11/3/2005 . <.!!(;)up_~ :..~~-ºiI~~ol~_ -- Prudhoe Oil Pool ---...-.----...--- ."-_._-----~ Put River Oil Pool . Group 2 - GPMA Oil Pools _______. ·_______._____n...__...._.__.__________ Lisburne 1- ----- ---- ___________n._.____n_..___ ____ Niakuk North Prudhoe Bay pt. Mcintyre _____ ._._. - __._._.n.________.__________ _._.. Raven Oil Pool West Beach Oil Pool _..--._.__._---~---- ---_._~- ~_.__._~-_._.__.__. _..._-_._.._---~._.__._---~--_. -- --~~-_...._--_.~- .-.- -- ._.__._--_._-_.__._------_..~---~._------ ___n___..___'.__ Amends Order/Rule Order Date Comment - _n_ C0341D Rule 11 ..-------.. C0559 Note C0341 E (modified Pool DefinitiOl1 to include a portion of Put River Sandstone) Corrected 2/14/2006 11/30/2001 11/22/2005 n C0207 207 A C0329A Rule 9 C0345 Rule 8 C0317B Rule 15 C0570 Rule 10 C0311B Rule 13 ---f---------. . -- No rule on Surveillance reports 6/4/1996 12/16/1994 4/19/2000 8/9/2006 8/1/2000 -- nn_________ .- __n_____ (corrected 8/9/2004) -- ~ 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 _u___ ... _________________n____~ ------------------ ----- ---------,_.._---_.,-_._-_._.-.-~-~---"_.__._---.--_.-~--- ~.._~-~.._---_.._-~,-~--._---. - -~ -~~-- -----~ Annual Overview Presentation 22-Mar 22-Jun 22-Sep ----- ----~-,_.,.._~---- -.---- -~ -..-. Production Period to be Covered Jan 1-Dec 31 Apr 1-Mar 31 Jul 1-Jun 30 Amends Order/Rule G_~oup__1 ~J~A_ºilu~.c?~I~___________ --_.._..._.._-~-_.~-,------_._-~ Prudhoe Oil Pool - - --PuIRTveroTI-Pool ,-- C0341D Rule 11 --------.-------',..-..--- C0559 Group 2 - ºPMA Oi'-~~ol~_____ _ -. LisbiJ"me -- "--C0207;207 Ä~-'-- --"--~---'-"'- - ~._..~._~ "~-'-'--'-~~---~-'--'----- -~- Niakuk i C0329A Rule 9 ._.._..._-----_._-'"..._---~- ___ _______~gi!~_¡::'!~dho~~ay C0345 Rule 8 ____n_________£>!=-~clr~tyr~_______ºQ~17B Rule 15 Raven Oil Pool C0570 Rule 10 ~._..__._,-----_.__.-._--,.~_._~---_._._-~_._---_._-~----'-~-~ West Beach Oil Pool C0311 BRule 13 G ~~lJ p3 ~ _ ~rudh~~_ S~!elli!~_ºi!~ool~___ __ ___________________ Aurora C0457B Rule 8 --_._~-_.._-_.._-_..~-_._----.._--,--~-.------- ------"---~,,--~-_.._-~--~~--- Boreallis C0471 Rule 4 -_._~-_.._--,._-_.~------~--~._----~ ------.._--...,.,._._--,_._.-~---_._.----_..- _~i_~f!ight..ª~!" ____ Ç045~_l3..ule 11___ Orion C0505A Rule 9 .. .-.-.--. ------,.._-- .-- "-~---~_.._"--- . --------._.._-----~-_..~..... Polaris C0484A Rule 9 . Order Date Comment ----l-~~---- I Note C0341 E (modified Pool Definition to 11/30/2001 include a portion of Put River Sandstone) ."----_._~_...-. ----,-~_. 11/22/2005 Corrected 2/14/2006 ~----J __+ No rule on Surveillance ree.~!!s ~m_ ---~=-- _m~n ---------r----------~-~-----~--------- I - ,.'._~'-~-~- 6/4/1996 12/16/1994 4/19/2000 8/9/2006 8/1/2000 . -._-'---' ~_....._~_...~.~._----_._".._-- _ 6/25/2004 ___.J.~!re~ed 819/2004) 5/29/2002 ! ___________~____J_____________u_____________ __________ ____ ------ ~~~~~000~ --+-----~-- --~-------- ------~1173/2005 -------t----- ------- -.- . lO ,,_. l' .. -. ---. -- . _..·_u__ .-...-.. -----1J . . Subject: [Fwd: [Fwd: Re: surveillance report dates]] From: Jane Williamson <jane _ 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 <dave_roby@admin.state.ak.us>, Cathy P Foerster <cathy _foerster@admin.state.ak.us>, Alan J Birnbaum <alan _ birnbaum@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 something I didn't get around to before I left and that was to administratively amend 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 CDs affected. I'm not sure how you want to handle. Jody. Please put this in the following CO files along with the attachment. Group 1 - IP A Oil Pools Prudhoe Oil Pool C0341 D Put River Oil Pool C0559 Group 2 - GPMA Oil Pools Lisburne C0207, 207 A Niakuk C0329A Rule 9 North Prudhoe Bay C0345 Pt. McIntyre C0317B Raven Oil Pool C0570 West Beach Oil Pool C0311B 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~admin.state.ak.us> Organization:State of Alaska To:Lenig, David C <David.Lenig(a!bp.com> References:<CBF4D8E92B5A 704 79F64416582F6A 17CB81AEO(a!bp lancexOOS.bp l.ad.bp.com> Oops Lenig, David C wrote: Hi Jane, 100 4/23/2007 9:50 AM l'" ........ l" ........ ..'---.....-... .~.-".-..........- -"'""'t"""'..... ~.......'""'......JJ . . J djdr(t get the attachrnent. David From: Jane Williamson 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 Jul1-Jun30 IPA GPMA March 15 June 15 September 15 March 22 June 22 September 22 March 30 June 30 September 30 Jan1-Dec31 Apr1-Mar31 Satellites Annual Surveillance Report Annual Overview Presentation -----Original Message----- From: Jane Williamson [mailto:jane williamson@admin.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 PBO 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 20f3 4/23/2007 9:50 AM l·o. Y'-' Lo. ........ .......-......-... .-.......-.....-- ~-t'........ ""'-"'-~JJ . . administrative action process. Thanks. , "..". ~~. .". (Zi;" - , J~nl=" \i\j11!1;::1!1TIS0,~""¡ U'r <1~~.A= ;"-¡,;~j19:r--;ç;r"'11"'" r¡lqrj~....,."'\~-:;...., r"'-,-n-:c-þ ~1( ~1C'> "},_;..11.,,-,,, 1l.-,-.l'~_11,¡ 'J~A:.., i. ~ ;-_::.1.1''-' ii' 1.11-':.c-i--<.J.lu\../_L1L !""-L-j::::::"_~_L_ll-"-.:.o\::n_Q:~_:,...-~C~c:. oG-LJ Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission Content-Type: application/vnd.ms-excel surveillance report. xis Content-Encoding: base64 30f3 4/23/2007 9:50 AM #4 .,' t' BP Exploration (Alaska), 1m. ) 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 581 ) bp October 19, 2005 RECEnl OCT 2 4 2005 Alaska Oil & Gas COliS. Anchorage Jane Williamson Robert P. Crandall Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Proposed Aurora EOR expansion As per CO 457B, rule 7, expansion of miscible gas injection outside of the North of Crest and West Blocks must be administratively approved by the Commission prior to long- term injection. Your approval is requested for long-term EOR expansion into the remaining depletion areas within the Aurora field. The following information is provided to supplement the application for an Area Injection Order for the AOP, dated June 15, 2001. Included are updated EOR results and observations from the pilot completed on injection wells S-110 and S-112. Please call Jim Young 564-5754 if you have any questions. Sincerely, ~~ Gil Beuhler GPB Satellites Manager Attachments CC: JeffFarr (ExxonMobil) Don Ince (CP AI) ') ) r '. 2005 Aurora MI Expansion Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507 Description of Operation Tertiary EOR Miscible Water Alternating Gas (MWAG) started in the North of Crest (NOC) and West blocks at Aurora in December 2003. Expansion of MWAG to remaining areas of the field based upon perfonnance of primary production and waterflood operations is proposed. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil and increases as the Miscible Injectant (MI) reduces residual oil saturation around the injection well. In order to increases injection rates and verify long-tenn feasibility, pilot injection ofMI into the southeastern portion of the field, has been completed on injection wells S-110i and S-112i. Long-tenn MW AG is proposed for these wells, water injection wells S-llli, S-116i, S-31Ai, S-120i, and future injection wells at Aurora. Geologic Information The Geology of the AOP is described in Section I of the Pool Rules application. Mechanical Integrity of Injection Wells Wells S-110i, S-112i, S-116i, S-llli, S-116i, S-31Ai, S-120i, have been completed in accordance with 20 AAC 25.412, thus satisfying mechanical integrity requirements. Refer to AIO for offset penetrations within ~ mile of well S-112i, 10-403 application for well S-110i, and drilling pennits for S-116i, S-llli, S-120i. S-31Ai will re-completed for injection into the Aurora pool in accordance with 20 AAC 25.412. No new wells have penetrated the proposed injection interval within ~ mile of these injectors since this infonnation was last provided. Injection Fluid Type/Source/CompatibilitylPressure/Confinement Refer to AIO 22A application. Maximum Injected Rate Maximum MI rates are estimated to be 30 MMCFD for higher injectivity wells such as S- ll1i, and 15 MMCFD for lower injectivity wells. Rates will be monitored & adjusted accordingly to maximize efficiency of the EOR process. Surveillance Plan Consistent with the AIO 22A application, injection rates, pressures and producer response will be closely monitored to assess level of improvement during and after each MI cycle. Refer to 2005 ASR for details on pressure surveys and analysis. 1 , ' EOR Results update to to as no 1 Map with overlay of cumulative MIIRMI sœooo 600000 G10000 G12!!00 614000 G16000 61??oo ß20000 SZ!!JOO 624000 626000 2 2 00 response , '. 2??oo 5000 20000 4000 f! 1 ??oo i fl3000 í1 ~ 2000 5000 1000 ??oo o 06!28/f)3 10/00103 01114/04 04/23/04 08101104 11/08104 02/17105 OS/28/05 08105105 block, productivity connectivity rates IS 4000 4000 3500 3000 1000 1000 000 o 06!28f03 10108103 01/14/04 04/23/04 08101104 11/09104 02/17105 OS/28/05 09/05105 o 12/14/05 14000 12000 10000 8000 11000 i 4000 2000 0 ·2000 12/14105 3 to remai.iag areas based o. WF &, pilot EOR peñormaace. -4 8..109 Well test history 2000 4000 .. GOR ~A;Mt ß'-HOOAS: ~$-123H20 HIOO 3600 1600 3200 1400 2800 1'200 -I 11:000 2000 ß "00 '600 "00 1200 400 600 200 400 0 0 08101/04 09120104 11/09/04 1212$/04 02117/05 04108105 00/28/05 07117105 09/05105- 10125/05 5 wen liquid/RMI production and GORNRR \I. ~4000 ;¡ Ð 'I It:: '0 () l- ll. ;¡ It:: ~ Q III ~ 1roJ ~ 'I It:: '0 () I- il :R AURCIl~ AURCIlI/RIJ!! , I I { J , , I Joo(ì4 Aprm 4 ~. " Figure 6 MI (green) and barrel equivaient 1800 1600 1400 Mar 04- Jul04 Nov 04 Mar OS Julœ 7 MI (green) and reservoir barre' equivalent (blue) 5000 :t!'~Ml'AAQfF¡t 4QOO '" '" 51 i ~ooo "" ~ '" E' :,¡ " ~2iJOO 'E ïi '" 1000 Jon M., A", M... Jun JYI A.. $"" 5 #3 bp ) ) RECEIVED APR 1 3 2004 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 April 12, 2004 Alaska Oil & Gas Cons. Commission Anchorage John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Supplemental Information - Amendments to Aurora Pool Rules and Area Injection Order CO 457 A and AIO 228 Dear Chair Norman: On March 26, 2004 the Prudhoe Bay Unit (PBU) Working Interest Owners filed with the Alaska Oil & Gas Conservation Commission (Commission) an March 25, 2004 application for Amendments to Conservation Order 457 A (as amended by Conservation Order 492) and Area Injection Order 22B, the Aurora Pool Rules and the Area Injection Order for the Aurora reservoir. During subsequent conversations, Commission staff have requested additional information in support of this application. Therefore, please accept the attached April 12, 2004 Supplementary Information to the March 25, 2004 application and incorporate this information into the record. The attachments, referenced data and other supporting information referenced in this Supplementary Information were provided to the Commission in the March 25, 2004 application submittal. Please also maintain the attachments referenced in this Supplemental Information as confidential in accord with AS 31.05.035 and 20 AAC 25.537. Please contact Gary Gustafson at 564-5304 or Frank Paskvan at 564-5749 if you have any questions or need additional information. Sincerely yours, .~~~ Gil Beuhler GPB Waterflood Manager Attachment: April 12, 2004 Supplementary Information to the March 25, 2004 Amendments to the Aurora Pool Rules and Area Injection Order 1 1"\~hïEU JUN 2, £ '¿(il:' ') ) Cc: Francis Sommer, BPXA Marc Vela, ExxonMobil Dan Kruse, ConocoPhillips G.P. Forsthoff, Chevron Bradley Brice, Forest Oil Jane Williamson, AOGCC Mike Kotowski, DO&G Gil Beuhler, BPXA Frank Paskvan, BPXA Gary Gustafson, BPXA Jim Copen, BPXA Leslie Senden, BPXA Rosy Jacobsen, BPXA Gary Benson, BPXA Steve Luna, ExxonMobil Jeff Farr, ExxonMobil Mark Menghini, ConocoPhillips Mark Worcester, ConocoPhillips SC/\N,~\JEU JUN 2 9 200l~ 2 SC/\f~NE[) JUN 2 ~ 2004 1/12 April 12, 2004 Supplemental Information Aurora Pool Rules And Area Injection Order ) ') ) ) I. GEOLOGy............... ............................................ ........ ...... ....... ..... ................................ 3 Introduction.................................................................................................................. ... 3 Stratigraphy.... ... ..... .......... ..... .... ............... ... ... .... ..... ....... ...... ....... ......... ...... ........ ........ .....3 Structure....................................................................................................................... ... 7 Fluid Contacts........................................ ......................................................... ......... .......8 P 00 I Limits ...................................................................................................................... 8 Hydrocarbons in Place...... ............................. .................... .............................................9 II. PLAN OF DEVELOPMENT AND OPERATIONS.................................................... 10 Wells........... ................................................. ....... ............................................ .... ........... 10 Drill Sites and Pipelines................................................................................................ 10 Support Facilities........................................................................................................... 11 Production..................................................................................................................... 11 W aterfl ood. .. ..... ... ..... . ... . ..... . . ... ... ... . . . .. .. .. .. . .... ... ... ... . .. .. . . .. . .. . .. .. .... . .... ... . ...... ... ... ... .... ... ... 11 Production Allocation................................................................................................... 11 Enhanced Recovery Techniques ...................................................................................11 2/12 5CAN~~EC JUN 2 9 2004 ) ') I. GEOLOGY Introduction The Aurora Pool is located on Alaska's North Slope and was confirmed in 1999 by the drilling of the V-200 well. The reservoir interval for the Aurora Pool is the Kuparuk River Formation. The Aurora Pool overlies the Prudhoe Bay Unit (PBU) Sadlerochit Group reservoirs in the vicinity of S-Pad. In addition to the V -200 well, the wells listed in Table 1 are recent Kuparuk River Formation penetrations in this area. The North Kuparuk 26-12-12 and Beechey Point State #1 wells, both drilled in 1969, were the first wells to penetrate and test hydrocarbons in the Aurora Pool. A number of PBU Sag River/Ivishâk development wells also penetrated the overlying Kuparuk River Formation. The S-24Ai well confirmed the presence of oil on the east side of the N-S dividing fault. Four S-Pad and M-Pad well penetrations and Term Well C define the southeastern limit of the Aurora accumulation. As shown in Attachment 4, the top of the Aurora structure crests at about 6450 feet true vertical depth sub-sea (tvdss). The deepest interpreted oil- water contact (OWC) is at 6835 feet (tvdss) in the Beechey Point State # 2 well. Attachment 1 shows the location of the Aurora Participating Area (AP A), including proposed expansion areas. Stratigraphy The productive interval of the Aurora Pool is the Kuparuk River Formation, informally referred to as the "Kuparuk Formation". This formation was deposited during the Early Cretaceous geologic time period, between 120 and 145 million years before present. Attachment 3 shows a portion of the open-hole wireline logs from the V -200 well. This "type log" illustrates the stratigraphic definition of the Aurora Pool. The log is scaled in true vertical depth subsea and also has a measured depth (md) track. In the V -200 well, the top of Kuparuk Formation occurs at 6,693 ft. tvdss (6,858.5 ft. md) and the base occurs at 7,070 ft. tvdss (7,253.5 ft. md). The Kuparuk Formation was deposited as marine shoreface and offshore sediments, and is composed of very fine to medium grained quartz-rich sandstone, which is interbedded with siltstone and mudstone. The sandstones typically have higher resistivity (3-50 ohm-meters) than the surrounding lithologic units. The Kuparuk Formation base is bounded by its contact with the Early SÇANNED .JUN 2, 3 200<~1· 3/12 ) ') Cretaceous Miluveach Formation and is distinguished by a change in lithology and conventional electric log character. The Miluveach Formation is shale with low resistivity (1 to 3 ohm-meters). The Kuparuk Formation top is defined by its contact with the Early Cretaceous Kalubik Formation or the overlying Early Cretaceous High Radioactive Zone (HRZ) Formation. Both are shales and they are distinguished from the Kuparuk River Formation by a change in lithology and conventional electric log character. The Kalubik Formation is a dark gray shale with a Gamma Ray log signature of 80 to 135 API units, and the HRZ is a black, organic-rich shale with a Gamma Ray log signature typically greater than 150 gamma API units. The Kuparuk Formation in the Aurora Pool is stratigraphically complex, characterized by multiple unconformities, changes in thickness and sedimentary facies, and local diagenetic cementation. As shown on the type log in Attachment 3, the Kuparuk Formation is divided into three stratigraphic intervals, from oldest to youngest, the A, B, and C intervals, with the A and C intervals divided into a number of sub-intervals. An overlying unit, called the D Shale, is locally present in the northern part of the Aurora Pool. Three unconformities affect Kuparuk thickness and stratigraphy. The Lower Cretaceous Unconformity (LCU) at the base of the Kuparuk C interval has erosional topography. It truncates downward and dips to the east where it successively removes the Kuparuk B and Kuparuk A intervals. The C-4 Unconformity at the base of the C-4 sub-interval also truncates downward to the east progressively removing the, C-3, C-2, and C-l sub- intervals before merging with the LCU. A younger unconformity, called the Pre-Aptian Unconformity also affects the Aurora Pool. At the Beechey Point wells in the western portion of the Aurora Pool, the Kuparuk Formation is unaffected and the HRZ interval above this unconformity is in contact with the Kalubik Formation. However, this unconformity also truncates downward to the east. At the V-200 well and other S-Pad wells to the east, the Kalubik Formation is eroded, and the HRZ interval is in contact with the Kuparuk C-4B sub-interval. This Pre-Aptian Unconformity eventually truncates the Kuparuk C4 locally and merges with the C-4 Unconformity and the Lower Cretaceous Unconformity at the eastern edge of the Aurora area. 4/12 5(;ANNED JUN 2 ~ 2004 ) ) The Kuparuk A and B units have a distinctly different stratigraphic thickness trend than the Kuparuk C units. Where not truncated, the lower A unit maintains a nearly uniform thickness throughout the Aurora area, suggesting that its deposition pre-dates significant fault movement. In contrast, the thickness, lithofacies, and diagenesis of the C units are variable and have been influenced by differential erosion, and variable diagenetic fluid effects. As a result of these processes, the entire Kuparuk C interval thins south and southeastward and reservoir quality varies laterally and vertically. The lower Kuparuk A interval contains two reservoir quality sub-intervals; the A-4 and A-5 sand units, which are 30 feet and 20 feet thick, respectively. In the V -200 well, these sands are wet. In structurally higher portions of the field to the east, these A sand units are expected to be oil-bearing and productive. The A-5 sand appears to be higher quality reservoir than the A -4 sand. The overlying Kuparuk B interval is dominated by siltstone and sandy mudstone with numerous discontinuous thin sandstone lenses, the thickest of which are up to 3 feet thick. In the V -200 well, wireline logs (Attachment 3) show these thin B interval sands to be wet. The uppermost unit, the Kuparuk C interval, contains the primary reservoir sands of the Aurora Pool. The thickness of this interval is variable and ranges from 0 feet at the eastern truncation to 210 feet at the Beechey Point wells in the northwestern portion of the Aurora Pool. The lithology of this upper unit is variable, consisting of interbedded very fine-grained to medium-grained sandstone with minor amounts of muddy siltstone and sandy-silty mudstone. The Kuparuk C sands are generally very quartzose and moderately sorted. The Kuparuk C interval is intensely bioturbated, contributing to the heterogeneous nature of the Kuparuk C. The Kuparuk C is further subdivided into the following sub-intervals from oldest to youngest: C-l, C-2, C-3 and C-4. The C-1 overlies the Lower Cretaceous Unconformity. The Kuparuk C-l and C-4 sub-intervals are coarser grained and contain variable amounts of glauconite and diagenetic siderite. The volume and distribution of siderite and glauconite plays an important role in the reservoir quality of the Kuparuk C-1 and C-4 intervals. These minerals are unevenly distributed and may affect a portion of the rock volume in the C-1 and C-4 sub-intervals. Due to the increase 5/12 SCANNED JUN 2 ~ 20 DtJ. ) ) in structural clay volume, compaction, and cementation, the porosity, permeability, and productivity of these sub-intervals are reduced. The C-l is the coarsest grained sub-interval. It is well-sorted medium-grained sandstone with occasional coarse and very-coarse grains. The C-l has a fairly uniform thickness of 14 feet to 18 feet except to the southeast where it thins due to truncation. The upper portion of the C-l sub-interval gradationally fines upward into the C-2 sub-interval. The C-2 sub-interval is the finest grained unit of the Kuparuk C interval and is considered non-reserVOIr. In the western portion of the Aurora Pool, it is dominated by silty mudstone with occasional very fine-grained sand laminations and interbeds. In the eastern part of Aurora, the C-2 lithology transitions to very fine-grained muddy-silty sandstone, indicating a lateral facies change from west to east. The C-2 interval has a somewhat uniform thickness of 28 feet to 36 feet in the western part of the field. The C-2 thins to the southeast and is eventually truncated. The C-3 sub-interval is composed of a coarsening upward senes of sandstone beds interbedded with silty mudstone. The sandstone beds range from 1 to 2 feet thick, silty, very fine-grain sand at the base up to 10 feet thick, fine-grained sand at the top. The mudstone interbeds display lateral facies variation, similar to the underlying C-2 sub- interval, in that they coarsen eastward to silty very fine-grained sandstone toward the truncation. The C-4 sub-interval continues the coarsening upward trend with fine-grained sandstone at the base to medium-grained sandstone toward the top. Due to the relatively coarse grain size and low volume of clay matrix, the C-4 sub-interval has the highest net to gross and reservoir quality in the Kuparuk Formation in the Aurora Pool area. The C-4 and C- 3 sub-interval's are separated by an intra-formational unconformity that marks the end of the coarsening upward trend. This unconformity, called the C-4 Unconformity, is a disconformity in the western half of the accumulation. However, it truncates downward through the stratigraphic section in the eastern half of Aurora, where it eventually merges with the Lower Cretaceous Unconformity. The top portion of the C-4 is a fining upward sequence into the overlying Kalubik Formation. C-4 interval thickness varies due to 6/12 ,JUN 2 ~ 2004 ) ) interaction by unconformities. The interval is thickest at the Beechey Point area where total C-4 thickness exceeds 60 feet. The interval thins southeastward and is eventually truncated. Structure Attachment 4 is a structure map on the top of the Kuparuk Formation with a contour interval of 50 feet. Top Kuparuk structure in the Aurora area is essentially a northwest- southeast oriented ridge, which is broken up by north-south striking faults. Gentle slopes dipping 2.5 to 6.5 degrees away from the structural crest characterize the northeast and southwest flanks of the ridge. In contrast, rotated fault blocks characterize the southern and western flanks of the ridge. A major north-south striking fault with up to 200 feet of down-to-the-west displacement effectively bisects the Aurora Pool area into an eastern half, which contains the S-Pad Sag River/Ivishak development wells, and a western half, which contains the V -200 well. This fault is best seen on Attachment 4, the Top Kuparuk Structure map, lying immediately west of the S-103, S-120i and S-117 well locations. The southeastern terminus of the Aurora Pool is coincident with the "Prudhoe High", a large basement-involved structural uplift that underlies the Prudhoe Bay field. Early Cretaceous and older sediments lapped over this structural high, and were later uplifted and subsequently beveled off by unconformities. Thus, this major structural high east of the Aurora accumulation is devoid of Kuparuk. The Kuparuk Formation thins southeastward to a zero edge against the Prudhoe High. The erosional truncation is orthogonal to the northwestern orientation of the overall structural ridge Attachments 5 and 9 are north-south oriented structural cross-sections through the western and eastern portions of the Aurora field, respectively (see Attachment 4 for location). These cross-sections illustrate the continuation of the Aurora reservoir beyond the northern and southern boundaries of the existing AP A. Attachment 6 and 10 are seismic traverses along the same lines of section. Attachment 7 is a northwest-southeast oriented structural cross-section paralleling the northern periphery of the Aurora field (see Attachment 4 for location). It, too, illustrates the presence of Kuparuk reservoir north of the existing AP A. Attachment 8 is a seismic traverse along the same line of section. 7/12 SCA~\H~ELì .JUN 2 ~ 20D4 ') ) Fluid Contacts Attachment 13 shows the interpreted Oil/Water Contact (OWC) and Gas/Oil Contact (GOC) in the Aurora Pool. Based on wireline logs, the OWC has been interpreted at 6835 feet tvdss. A common GOC for the Aurora Pool is not present. Based on well tests, mudlog and wireline logs, a GOC of 6678 feet tvdss is interpreted in the West Block. The North of Crest and Crest Block are gas-free based on production flow tests, sidewall core saturations and staining, and RFT pressure gradient data and fluid samples. In the Southeast of Crest Block logs from well S-16a indicate a local gas accumulation with a GOC of 6631 feet tvdss. Pool Limits The trap for oil and gas in the Aurora Pool is created by a combination of structural and stratigraphic features. as illustrated on the attached structure map and cross sections. The accumulation is bounded to the west by several faults where the reservoir is juxtaposed against impermeable shales of the overlying Kalubik Formation and HRZ Shale. To the southwest and north, the pool limit is defined by the down-dip intersection of the top of reservoir with the oil-water contact. Data acquired since the formation of the Aurora Participating Area indicate that the intersection actually lies beyond the northern and southern boundaries of the current P A. To the east and southeast the reservoir is truncated by the Pre-Aptian, C-4, and Lower Cretaceous Unconformities. These unconformities merge at the southeastern limit of the field. Subsurface well data and reprocessed seismic indicates that the recoverable hydrocarbon accumulation at Aurora Field extends beyond the boundaries of the existing Participating Area. The boundary of the proposed expanded Aurora PAis within the proposed boundary of the Aurora Pool. Attachment 11 is a net hydrocarbon pore foot map of the Aurora Pool with a contour interval of 2 feet. Attachment 12 is a net pay map of the Aurora Pool with a contour interval of 20 feet. Both maps show the extent to which recoverable hydrocarbons extend beyond the limits of the current P A. The geologic cross sections and seismic sections in Attachments 5 through 10 further illustrate the geological continuity from the current P A into the proposed expansion areas. 8/12 SCANNED JUN 2 ~ 2004 ) ) Reprocessing of the vintage 2000 Aurora seismic dataset greatly improved imaging of top Kuparuk structure. Attachment 6A provides an example of seismic data before and after reprocessing. As a result, the ability to more accurately predict top reservoir depth, and the location and magnitude of faults is greatly improved. Well S-102 was successfully sidetracked in October 2003 to within 1000' of the northern AP A boundary confirming the structural interpretation of the reprocessed data. Log data from the sidetrack, S- 102Ll, indicate reservoir quality Kuparuk sands extend northward and lie above the regional free water level. Well S-116i was drilled to within 1900' of the southern AP A boundary. Interpreted log data and pressure measurements from S-116i and logs from Term Well C, about 1400 feet south of the current P A, indicate that the Kuparuk A sand reservoir is present above the regional free water level south of the existing AP A. Hydrocarbons in Place Estimates of hydrocarbons in place for the Aurora Pool reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. The current estimate of original oil in place (OOIP) ranges between 165 mmstbo and 201 mmstbo. Formation gas in place ranges from 112 to 137 bscf, and gas cap gas ranges from 15 to 75 bscf. SC/\Nh·jE!.J JUN 2 9 20a,~ 9/12 ') ') II. PLAN OF DEVELOPMENT AND OPERATIONS Development of the Aurora Reservoir includes phased drilling of approximately twenty (20) to twenty five (25) production and injection wells from S-Pad. Initial (Phase I) drilling commenced July 2000 with production startup in November 2000. Water injection started in January 2002. Production is commingled with IPA production on S- Pad and processed at GC-2. Phase II drilling began in 2Q 2001. A total of nineteen (19) Aurora development wells have been drilled through end of January 2004. See Table 1, below. The Phase II program will continue through 2005. Tertiary recovery, utilizing IPA miscible gas for WAG (Water-Alternating-Gas injection) was started in the S-104i and S-101i wells during 4Q 2003. Wells Six wells were drilled during Phase I development (S-100, 10li, 102, 103, 104i, 105). Two Phase I wells (S-10li and S-104i) were drilled as pre-produced injectors. Phase II drilling commenced in mid-2001 and through January 2004 thirteen (13) Phase II wells have been drilled (S-106, S-107i, S-108, S-109, S-110i, S-112i, S-113B, S-114Ai, S-115, S-116i, S-117, S-118 and S-120i). Currently, five wells are on injection S-10li (WAG), S-104i (WAG), S-107i, S-110i, and S-112i. Injectors S-116i and S-120i will be pre- produced for 10 days then converted to water injection lQ 2004. As part of a proposed P A expansion for 2004 an additional well is being considered along the northern periphery of the current P A. Depending on its results, additional development in the northern P A area will be evaluated. The Aurora Owners will continue to evaluate optimal well count and well locations as development and depletion of the reservoir progresses. Unutilized IP A well-bores will also be evaluated to access Aurora reservoir targets. Although pattern spacing is expected to be irregular, minimum nominal inter-well spacing is estimated to be 80 acres. Drill Sites and Pipelines Aurora development will use the existing WOA infrastructure of pipelines, roads and pads. Initial development from S-Pad utilizes existing low-pressure pipelines from S-Pad to GC-2. Additional gravel was laid to expand the northern part of S-Pad to accommodate wells and drilling beyond Phase I. Aurora Owners installed vertical 10/12 SC;"\N~\!ED JUN 2 ~ 20Dt~ ) ) support members (VSMs) and trunk lines to the north of S-200 to extend the production/test/produced water and artificial gas lift headers. Aurora Owners have approved the expansion of an MI trunk to allow water injectors to be converted to WAG injection for the tertiary recovery project. Support Facilities Aurora will share North Slope infrastructure with the IPA as needed to support Aurora Operations, minimizing duplication of facilities. These include camp facilities, potable water and waste disposal facilities, shop and maintenance facilities, airstrip, construction pad, storage and warehouse space, oily waste disposal facilities and telecommunications systems. Production The wells at Aurora have a current combined production of approximately 10-15 MBD. The current water injection rate is approximately 20-25 MBWPD. The current miscible gas injection rate is approximately 20 MMCFPD. Attachment 14 shows Aurora production and injection history. Waterflood Waterflood operations began in January 2002. A waterflood configuration is anticipated to conform to the minimum nominal inter-well spacing of 80 acres. Injection water is obtained from the IP A for use in the Aurora waterflood. Production Allocation Aurora production allocation is being performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust the total Aurora production. A minimum of one well test per month is used to check the performance curves and to verify system performance. No NGLs are allocated to Aurora. Enhanced Recovery Techniques Miscible gas injection is expected to increase economic recovery of Aurora hydrocarbons by approximately 3-5 mmbo. 11/12 I ¡ P\~ 2: q ZOO{i: "./ i.. ,.. " if I ) ) Table 1: Aurora Wells Completed in the Kuparuk Formation - .~-.~.~...-'-- . . . ~ ". .- ~-- .-.-" - ¡ Well 1 API Number (Spud Date ( Well Status Desc: :~"W"""W'W"''''M'''''''''W'''''''''''''''''''''''''''HM'''M''''''W'''WMY'W..,y'''':t....w,...""'......""..,,,......M......'w.v.W........."'.......'·M·'.............·MW......"',..'.....w.wWM'.W-'y.WM·~~.'......WM.....".....WMW.Y.W......M'.M....Y,W......,.."".......,..."..y....,W.....W"M"......~:WMW.'M.MWMW...W'........,....w."..,w,.........W,..WMW.W,WMW.'..",""w.'H.·...........w.......,"'._'.w.",,'.....·...y......,.·,·.........w....,.'WM..."'WM·,""w....,.w.....·.·"·...w.·.............,,.w....,·...W.."....'WM·,W................m.w.w,·,·M....W,W.....w...W.W,.M·1 :jS-100 __, j5~~292296.~00 !7/9/~~00 ¡Oil Prod,u.cer_~lowi~~___ _ i 8-101 . 50029229680_~ . 8(9/2000 Miscible Injector Operating S-102 ,.. . ,500292?9?~00 9/14/20000_iI. P~,?ducer Gas Lift ,8-102L 1 500292297260 10/26/2003 Oil Producer Gas Lift 8-103 500292298100 ·11/6/2000 ·Oil Producer Gas Lift 8-104 500292298800 1/11/2001 Miscible Injector Operating 8-105 500292297700 10/25/2000 Oil Producer Gas Lift S-106 .500292299900 5/5/2001 Oil Producer Gas Lift - .. .. . . .-- . - . 'S-107 500292302300 6/29/2001 ,Water Injector Injecting - . S-108 500292302100 6/11/2001 Oil Producer Shut-In liS-109 500292313500! 12/31/2002 ::Oil Producer Gas Lift I . . S-112 500292309900 7/22/2002 Water Injector Injecting . - ~- -'- - . . -. - . ~ -- - ... S-113B ·500292309402 7/8/2002 Oil Producer 8hut-ln - - . .. - -- - . . S-114A 500292311601 9/19/2002 Water Injector Injecting .. L' _ ~ _ _. . . _ . . . _u . _ '. .. ." . .. ~ .. _ . ~ _. ....... . . S-115 500292313000 12/20/2002 Oil Producer Flowing . - 8-116 500292318300 12/6/2003 Water Injector, Not Yet Completed - '. ... - - . - - ~ S-117 500292313700 2/17/2003 Oil Producer Gas Lift ~~~~~1~~~= 5CANNEU .JUN 2 ~ 20D4· 12/12 #2 AO.FRM Publisher/Original Copies: Department .FiS, ca.. I,. De,p. ,artmel1t~ReceiVing ':( l\ ~\n\!FT" ..'tIN 2 9 ?OO~' 02-902 (Rev. 3/94) 71ION ~~~.. .......-:;:7 ~/~~~/ :/~, (.,~_. l !,-< / (~ '" -'-- ~ 2 3 4 REQUISITIONED BY: 73540 02140100 04 DIST LlQ NMR FY ACCT lC PGM CC SY AMOUNT FIN 02910 REF TYPE 1 VEN 2 ARD 3 4 PAGE 1 OF TOTAL OF 2 PAGES ALL PAGES$ COMMENTS IN TRIPLICATE. AOGCC, 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 NUMBER AMOUNT DATE SEND SEE ATTACHED STOF0330 Advertisement to be published was e-mailed D Classified DOther (Specify) D Display Type of Advertisement X Legal THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: April 2, 2004 ¿ Anchorage Daily News POBox 149001 Anchorage, AK 99514 (907) 793 -1 ),),1 DATES ADVERTISEMENT REQUIRED: DATE OF A.O. AGENCY CONTACT Jody Colombie PHONE F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M March 31, 2004 PCN AO-02414025 ) NOTICE TO PUBLISHER INV( ST BE IN TRIPLICATE SHOWING ADVERTISING ORDER }TIFIED AFFIDI-WII I OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACl-Il::u GOPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRES~ ADVERTISING ORDER NO. ) ) Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Aurora Oil Pool, Prudhoe Bay Field Request for expansion of area subject to pool rules and area injection order BP Exploration (Alaska), Inc. by application dated March 26, 2004, has applied for expansion of the affected area for the Aurora Oil Pool pool rules as defined in Conservation Order No. 457 A and for Area Injection Order No. 22B. The Commission has tentatively scheduled a public hearing on this application for May 6, 2004 9:00 am at 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 April 19, 2004. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit a written protest or written comments regardinß this application to the Alaska Oil and Gas Conservation Commission at 333 West i Avenue, Suite 100, Anchorage, Alaska 99501. Written protest or comments must be received no later than May 3,2004 except that if the Commission decides to hold a public hearing, written protest or comments must be received no later than the conclusion of the May 4, 2004 hearing. '\ If you are a person with a disability ¥~ a¡ need a special modification in order to comment or to attend the pub . in~, ple~ contact Jody Colombie at 793-1221 before April 30, 2004. ~! ~~ hn~an Chair Published Date: April 2, 2004 AO# 02414025 SCANNEt) JUN 2 ~ 20D4 ) L Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 J 4/2/2004 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 115260 04/02/2004 02414025 STOF0330 $121.18 $121.18 $0.00 $0.00 $0.00 $0.00 $0.00 $121.18 STATE OF ALASKA THIRD JUDICIAL DISTRICT Teresita Peralta, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the TIúrd Judicial Court, Anchorage, Alaska, and it now and has been published in the English language conti!lually as a daily newspaper in Anchora~e, Alaska, and it is now and durin~ all said time was printed in an office maintained at the aforesaid place of . publication of said newspaper. That the annexed is a copy of an' advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed ( ý¡?//aI/CÅ- Subscribed and sworn to me before this date: !}JvcY.. J. ;}(X)'1 Notary Public in and for the,State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: (ï¿Y/) ß ),)(07 1 ) jI \ll(((((((IF . \ !\ ,/) )). f 1 \\\ f,.ttLY ~ I'/~ / /, . / . J/í 1/ /J )I'Ij.,ý ~':....'t:. ' '~~.:.. '/ý;~ /'ì({jJ1fJ<A-l9·· 'Æ 1,/t,W ¡ :.,~O.~~,,;,:\ V l ::: ~ : ÞoSLIC ' ::: ~ ø . .... -~"~ -~- ,. t:;:: % :- :?,Q: ~\.~ . . :;" ~ ~..I ~,~".... '/j))} JJJJ Ù) l"\.\IE.1.. ·~·~t~!~~:~:6~~~:t~R~ . Þ:10skO:Oil arid Gas C~ns~r,y«;,.t¡o,~ .ComJ:l1ission . ~ ,'I . '" I :. , ' .Re: AuröraOIlP,ool, Prµdhoe ,Bay Field . ReqQest forexpan$ion of . arElosubJect'to p.ool rules an~ar~ainiecticin .o¡'de~ .:. ::!¡i!P.·.···E.·~~,·'~r;;~!il~.h':' !(~Iºska )ill1ç;:ß~,appllþþi. '. ·.tiQn,:idQte(·.:M(1rCI'l2l!¡~ÓG41 , h.as>·gPPI.IE!:d:f'or,:e)(pc¡n" sl ò nOf, theoffectédQre'o tor the Aurora OJ 1 Pool . pool rules as defined In Conservation Order No. 457A and tor Area Inlec- tion Order No. 22B. The' Commission· has· tentotlvely scheduled a public hearing on this ap- . pljcatior¡ far May 6, 2(104 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West : 7th Avenue, Suite 100; Anchorage, Alaska 99501. A perSQn ma,y.·request ïat the fentatlvelt .IL1N (; ~ 2004 ischèduled hearing be .held !:byf.llin g,a'l/Jf rltte nre- que..twitli theCoi'tll'nlc.;: !lIon no lol..r Ihon 4: 30 pm on April i9 iOO4 I ",::':':....,<>.:....,"::',,~,',',I .:: ',:': ,. ,.1 fareq uestfo r a' :' rire~;~~:¿·;mn~lsst¡~~ ~\ ~ I consider the issuance of an order without a hear- I ~~~miIs~o~ e~~ln h~fd \~~' 1~~I~~~~_r2~f.rlng, please In: êì dd it¡o~!6Pf~~ u r, ,rrlo\ >l.brnil 0 wrirtf,n prulE-')1 or wrlllt"n com· rnlÕ'l1l~ r"90r.::l,n9 1t,1~ 0)':', P"(Ollon IQ r1E:- Ala~ko 011 and Go~, COnSE:-rllat,or, : C O.m;!)1 i !'osi ~ n a.l333'N,esT 17t~:.:f:. v:~n;t{E!';'$'!l,lte··.l:.00, 1~~~Þf:~gpe~·6tJ~.~~ar9~~~,: " l11.elÌtsl1)ust,' berè.c e ,,;~ d i~~ ~~~~rthhgtrí~1'r~ e~c~~~! I ml~slon aec ,de-s 10 hOld a 'public ne-ormg, wrillt'n' 'protest or comments' must be received no later ,th.an t1e conclusion of the , Mav 4, 2004·hearlng. . , i : tfv,Qµ'ClreCl persOn I witha· dlspbiUtv Who may : need a spe,cialmodlfiça" : tion In ord!,!r to comment 'or to attend the public : he·aring, pleasecontad . JOdy·Còlombieat. 793-1221 i œforèAP·"tF30~2004,,· ,... ·:John N9rman ,. Çhalr :.AO# 02414025 Publish: April 4, 2004 RE: NotiCe ') ) Hi Jody: Following is the confirmation information on your legal notice. Please let me know if you have any questions or need additional information. Account Number: STOF 0330 Legal Ad Number: 115260 Publication Date(s): April 2, 2004 Your Reference or PO#: 02414025 Cost of Legal Notice: $121.18 Additional Charges Web Link: E-Mail Link: Bolding: Total Cost to Place Legal Notice: $121.18 Ad Win Appear on the web, www.adn.com: XXXX Ad Win Not Appear on the web, www.adn.com: Thank You, Kim Kirby Anchorage Daily News Legal Classified Representative E-Mail: legalads@adn.com Phone: (907) 257-4296 Fax: (907) 279-8170 ---------- From: Jody Colombie Sent: Wednesday, March 31, 20044:35 PM To: legalads Subject: Notice «File: Ad Order form.doc»«File: Aurora AIO.doc»«File: iodv colombie.vcf» Please publish on April 2, 2004. -lody SCA,NNED .JUN 2 9 2004 1 of 1 4/1/2004 2:32 PM STATE OF ALASKA ADVERTISING ORDER SE.E. BOTTOM FOR INVOICE ADDRESS NOTICE TO PUBLISHER·· ADVERTISING ORDER NO. INV~ )ST BE IN TRIPLICATE SHOWING ADVERTISING ORDER )RTIFIED 02 AFFIDfo\VI OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED l,u,' ? OF AO- 414025 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AGENCY CONTACT DATE OF A.O. AOGCC 333 West 7th Avenue, Suite 100 o llnchorage,AJe 99501 M 907-793-1221 R Jod)' Colombie March 31, ?004 PHONE PCN (907) 793 -1 ??1 DATES ADVERTISEMENT REQUIRED: ¿ Anchorage Daily News POBox 149001 llnchorage, AI<. 99514 April 2, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTEn IN ITS ENTIRETY ON THE nATES 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 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of . 2004, 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 2004, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 SCANNEC ~JUN 2 9 2004 AO.FRM PUBLISHER Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez 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 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 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 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 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 131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 El"· ¡\I i\\~ ~/;'j) 0, 20DlI. SCANN ,_../.1 ..,PJI.'-\' oP.. " ) David McCaleb IHSEnergy 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,ID 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 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 DalWin 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 11719 lied tØ¡6¥ Notice ) ) Please publish online. -Jody Jody Colombie <jody colombie@admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration ...._.........._.-.............._.....~..._._.~..._...-_....~........~......_ _..~.. ~..................._....__...._._....._.._ ..... ···_·_·__·____·~·..__~___..__u__...__~_...._.._..._.._.__._._.__..._~ Content-Type: applicationlmsword Aurora _ AIO.doci Content-Encoding: base64 . ~. IEf' ~¡)'N~)i Ii) '}OOR ,/\\\, hi _.L: ,J~, I /.0- iiff It . ~,¡. 1 of 1 3/31/2004 4:35 PM Notice ') ) Please publish on April 2, 2004. -Jody Jody Colombie <jody colombie@admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: applicationlmsword Ad Order form.doc, Content-Encoding: base64 1.':::,7:::,7:.7:::::::,7::::::::::,7::::::., "'" -....--........---......--...-....--.......................-............................-.....-.........-.......-.---.-......................-..--.--...--......--........-....-.-..--......-...-....... . ..."."",,,,,,,..,,,..,,,..,..,,..,,, .n....".......""'"""".......,, .,.......""""""""..."", "''' ""......",,,,,,,,,........,,,,,,,, "''''''''''''''''"' ""............., ,,,........,.,. ..., ....-...._..._......_._.._._-_._._.__.........._._...~..-... ..,..""...,..""",,,,,,,,,.. ..........,,,, """..., , i Content-Type: applicationlmsword ! Aurora AIO.doc! . - ! Content-Encoding: base64 i .......................""..".",.."..','.'".,..,.,.,,.".. JUN 2 ~ 2004 1 of 1 3/31/2004 4:36 PM Notice ) ) ...... ~..,.". ."-', ',""\ ,'. ,'-'-""'n.",,", .W.',',.. ,.'.... ...... ,'"" ...c,__"," ",....' _......,....,~....._. ..·...w....'-,.,'~ Jody Colombie ~jody colombie(á}admin.state.ak.us>· SC/\NNEL< ,JUN 2 ~ ZOO"~ lof2 3/31/2004 4:36 PM Notice 20f2 .') Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration ) Content-Type: application/msword Content-Encoding: base64 SCf'\1\.ft\r\",IIFrì JUfI"I; ~ r,J "ünr 3/31/2004 4:36 PM #1 bp March 25, 2004 ) ) 0'<','·· ~. ;";.' BP Exploration (Alaska) Inc, 900 East Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Amendments to Aurora Pool Rules and Area Injection Order CO 457 A and AIO 228 Dear Commissioners: Enclosed for your review and action is the Prudhoe Bay Unit (PBU) Working Interest Owners' application for amendments to Conservation Order 457A (as amended by Conservation Order 492) and Area Injection Order 22B, the Aurora Pool Rules and the Area Injection Or~er for the Aurora reservoir. These amendments are necessary because BP Exploration (Alaska) Inc. (BPXA), as Aurora Operator and Unit Operator, has applied to the Department of Natural Resources to expand the Aurora Participating Area and the Prudhoe Bay Unit. Accordingly, BPXA hereby petitions the Commission to amend ·the above referenced rules as necessary to accommodate this expansion. BPXA requests that Section #4 of Conservation Order 457 A and Section #4 of Area Injection Order 22B be amended as follows to reflect the revised legal description describing the expanded area affected by these orders. Umiat Meridian ITownshipl1 Range T11N R12E T12N R12E IISections Sec. 2 WY2 Sec. 3: All Sec. 4: E%, NW%, EY2SW% Sec. 5: EY2NE% Sec. 9: NE%, N%SE% Sec. 10: NW%SW%, WY2NW% Sec. 15: S%SE%, SW% Sec. 16: NW%, SY2 Sec 17: SY2, NE%, Sec 18: SE% See 19: NY2NE1A See 20: EY2, N%NW% Sec 21: All 1 · <'--I~- ., Jl ~N #.V '~I 'J C . ,_.( \,,11 ,-, ' I ;.r~ ',.' I ., ' t 'I ,'~. ~,,~I I~'~ ~., _~ ) Sec 22: All See 23: SY2, SY2NW%, S%NE% Sec 25: S%, SY2NW% Sec 26: All See 27: All; T12N R12E See 28: All See 29: EY2NE%, SE% See 32: EY2 Sec 33:· All Sec 34: All Sec 35: All Sec 36: All ) Information in support of these amendments is attached. Please maintain as confidential those certain attachments attached and labeled· "Confidential" in accord with AS 31.05.035 and 20 AAC·25.537. Please contact Gary Gustafson at 564-5304 or Frank Paskvan at 564-5749 if you have any questions or need additional information. Sincerely, ~~ GiI Beuhler GPB Waterflood Manager Attachments: Attachment 1 Attachment 2 Attachment 3 Attachment 4 Attachment 5 Attachment 6 Attachment 6A Attachment 7 Attachment 8 Attachment 9 Attachment 1 0 Attachment 11 Attachment 12 Attachment 13 Attachment 14 Location Map of the AP NPBU Expansion Areas Lease Map of Expanded APNPBU Aurora Type Log - Well V-200 - Confidential Top Kuparuk Structure with Cross Section Index - Confidential Cross Section A - A' - Confidential Seismic Section A - A' - Confidential Detail from Seismic Section A - A' - Confidential Cross Section B - B' - Confidential Seismic Section B - B' - Confidential Cross Section C - C' - Confidential Seismic Section C - C' - Confidential Aurora Field - Composite Net Oil Pore Foot Map - Confidential Aurora Field - Composite Net Pay Map - Confidential Fluid Contact Data - Confidential Aurora Production and Injection Plot 2 S-'ú··'/~ 'i\..H\!EL\' n nil ':1 0 200 R \¡J: 'Vk"1~ 'tj PJ ...J \\....I bJ (, ¿~ !_¡ ) ') Cc: Francis Sommer, BPXA Marc Vela, ExxonMobil Dan Kruse, ConocoPhillips G.P. Forsthoff, Chevron Bradley Brice, Forest Oil Jane Williamson, AOGCC Mike Kotowski, DO&G GiI Beuhler, BPXA Frank Paskvan, BPXA Gary Gustafson, BPXA Jim Copen, BPXA Leslie Senden, BPXA Rosy Jacobsen, BPXA Gary Benson, BPXA Steve Luna, ExxonMobil Jeff Farr, ExxonMobil James Rodgers, ConocoPhillips Mark Worcester, ConocoPhillips 3 SCl\N~~EU JUN 2 ~J 200::~ ) ) . - March 25, 2004 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Amendments to Aurora Pool Rules and Area Injection Order CO 457 A and AIO 228 Dear Commissioners: Enclosed for your review and action is the Prudhoe Bay Unit (PBU) Working Interest Owners' application for amendments to Conservation Order 457 A (as amended by Conservation Order 492) and Area Injection Order 22B, the Aurora Pool Rules and the Area Injection Order for the Aurora reservoir. These amendments are necessary because BP Exploration (Alaska) Inc. (BPXA), as Aurora Operator and Unit Operator, has applied to the Department of Natural Resources to expand the Aurora Participating Area and the Prudhoe Bay Unit. Accordingly, BPXA hereby petitions the Commission to amend the above referenced rules as necessary to accommodate this expansion. BPXA requests that Section #4 of Conservation Order 457 A and Section #4 of Area Injection Order 22B be amended as follows to reflect the revised legal description describing the expanded area affected by these orders. Umiat Meridian ITow·~ShipJ~rìg~-irsê~ti~iì~~:·........ ~.< ..~'",.... '" ~. n.. .-. u...........~. .."" '11 i - -'""' '" 1!sëê.2- wy;~-- .~.,~ ~-- -~~. ..~ -", ..-.... - ìl i ¡¡Sec. 3: All II T11 N R12E Ilsee. 4: E~2, N':"%. EY2SW% I¡<II ¡!Sec. 5. EY2NE~ Ij !!Sec. 9: NE1A, NV2SE1A 11 ¡¡Sec. 10: NW1ASW1A, WV2NW1A ........"'<,."...... ,. ...:¡!~.< 1'''< ~~ 1',- !~S·e~~·5: SV2SE1A, SW%~"-_·~' ,,,. ~ . i I{Sec. 16: NW1A, SV2 II ¡¡Sec 17: SV2, NE1A, I!~ 11 T12N I: R12E ¡jSec 18: SE1A i" I l,jSec 19: NV2NE1A I, I . i;Sec 20: EV2, NV2NW1A I¡ l~,..--.;;;--.__.._...,'--1.......,...,,:-_.,..;.,T:'.;:,,"'";.jl§.~-së.g.!~ ~ II~_, ........--,-..-:-;;:;.-.....=,...,.....-;;-,c..........-..--..--'''''';.,.'''''..,. .;';.;;.,____;;...;;;.';.'...-~-,--.,-._;;_;_:_...;..';:,,7..'-;'.'';..;:;::;..~;;_;;..",J ¡ 1 SC/\~\H\H?J,1 . fíIN 9' q ?QOt. R12E ) , ......"" ,,'. .,;",.,....,..........,..,.."",.,.."....",.""..................,..............."'.................,............................"...................."''''................'........,....... ~.............................._............._..........,............-................"........,......, r.:=-------'~~---~'---'~~~---=-_._--~""'<.."'.,_._-"""'"'"-~'-~---' I¡Sec 22: All ¡ ¡í I ¡Sec 23: SY2, SY2NW%, SY2NE% ¡ ! . I I Sec 25: SY2, SY2NW% I I Sec 26: All I ¡Sec 27: All; I I See 28: All I I See 29: EY2NEv.., SEv.. I ¡Sec 32: EY2 I i Sec 33: All I Sec 34: All I I See 35: All . .J Sec 36:1-\"",,_ ...."'" .. ............_._ -.J . ." T12N ~~4,%·.. ......... . "'""w^'<,,,,,...v.""""'..."",,"'.......,...,........,,,,,'"y Information in.support of these amendments is attached. Please maintain as confidential those certain attachments attached and labeled "Confidential" in accord with AS 31.05.035 and 20 AAC 25.537. Please contact Gary Gustafson at 564-5304 or Frank Paskvan at 564-5749 if you have any questions or need additional information. Sincerely, Gil Beuhler GPB Waterflood Manager Attachments: Attachment 1 Attachment 2 Attachment 3 Attachment 4 Attachment 5 Attachment 6 Attachment 6A Attachment 7 Attachment 8 Attachment 9 Attachment 10 Attachment 11 Attachment 12 Attachment 13 Attachment 14 Location Map of the AP A/PBU Expansion Areas Lease Map of Expanded AP A/PBU Aurora Type Log - Well V-200 - Confidential Top Kuparuk Structure with Cross Section Index - Confidential Cross Section A - A' - Confidential Seismic Section A - A' - Confidential Detail from Seismic Section A - A' - Confidential Cross Section B - B' - Confidential Seismic Section B - B' - Confidential Cross Section C - C' - Confidential Seismic Section C - C' - Confidential Aurora Field - Composite Net Oil Pore Foot Map - Confidential Aurora Field - Composite Net Pay Map - Confidential Fluid Contact Data - Confidential Aurora Production and Injection Plot 2 SC/c:\N~~EI.',i . ~UN ~? :9 2004 " ) -, ,,,' .. Cc: Francis Sommer, BPXA Marc Vela, ExxonMobil Dan Kruse, ConocoPhillips G.P. Forsthoff, Chevron Bradley Brice, Forest Oil Jane Williamson, AOGCC Mike Kotowski, DO&G Gil Beuhler, BPXA Frank Paskvan, BPXA Gary Gustafson, BPXA Jim Copen, BPXA Leslie Senden, BPXA Rosy Jacobsen, BPXA Gary Benson, BPXA Steve Luna, ExxonMobil Jeff Farr, ExxonMobil James Rodgers, ConocoPhillips Mark Worcester, ConocoPhillips 3 SG¡.:~!\~NElU JUN 2. 9 20Dl} ) " '- " . Producer A Injector Type Well Top Kuparuk Structure Attachment 1: location Map of the APAlPBU Expansion Areas PR UNIT DATE: 2004 ATTACHMENT 2 SCALE: 1:78,000 Attachment 2: lease Map of Expanded APAlPBU BPKI\, CEi.rta-;:¡r.f!pnYi~m"4853b.dg!1 5 GAS INJ RATE 70000 60000 50000 40000 30000 20000 10000 o 2000 f ' GAS RATE WATER RATE OIL RATE _ _ WATER INJ RATE 2001 2002 2003 2004 Attachment 14: Aurora Production and Injection Plot 18 Í\ , '" i bp e \õ)!E~ IEll~!E m¡ m1 MAR 2 6 2004 lid} e :,: , March 25, 2004 DIVISION OF OIL AND GAS BP Exploration' (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 Mark D. Myers, Director Division of Oil and Gas Alaska Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, AK 99501-3560 RE: Application to Expand the Aurora Participating Area and the Prudhoe Bay Unit - ADL's 028255,028256,028257,028260,028261,047448 and 047450 Dear Dr. Myers: Pursuant to Sections 5.3 and 9.1 of the Prudhoe Bay Unit Agreement (PBUA) and the provisions of 11 AAC 83.303, 83.351 and 83.356, BP Exploration (Alaska) Inc. ("BPXA"), acting in its capacity as Operator of the Prudhoe Bay Unit (PBU) and on . behalf of itself and the other PBU Working Interest Owners, Chevron U.S.A. Inc., ConocoPhillips Alaska, Inc., ExxonMobil Alaska Production, Inc. and Forest Oil Corporation, hereby applies to the Department of Natural Resources for approval of the expansion of the Aurora Participating Area (APA) and the corresponding expansion of the Prudhoe Bay Unit (PBU). The proposed APA expansion area encompasses approximately 2,240 acres while the PBU expansion includes about 1,120 acres (Attachment 1). These expansion areas are located within ADL's 028255, 028256, 028257, 028260, 028261, 047448 and 047450 (Attachment 2). As demonstrated by the additional attachments, the areas within the proposed APA and PBU expansions are capable of contributing to the production of hydrocarbons in paying quantities sufficient to justify the development and production of the Aurora Reservoir in these areas. BPXA respectfully submits that the proposed expansion of the APA and PBU meets the criteria of 11 AAC 83.303 because it will promote conservation of natural resources, promote the prevention of economic and physical waste, and will protect all parties, including the State of Alaska. It also provides for the protection of the environment through planned development that optimizes the use and minimizes duplication of existing facilities. The following attachments are provided in support of this APA and PBU expansion: Attachment 1 Attachment 2 Attachment 3 Attachment 4 Attachment 5 Attachment 6 Attachment 7 Location Map of the AP A/PBU Expansion Areas Lease Map of Expanded AP A/PBU Amended Aurora Participations and Tract Allocations Amended Aurora Plan of Development and Operations Aurora Type Log - Well V-200 - Confidential Top Kuparuk Structure with Cross Section Index - Confidential Cross Section A - A' - Confidential 2 :J 20 Attachment 8 Attachment 8A Attachment 9 Attachment 10 Attachment 11 Attachment 12 Attachment 13 Attachment 14 Attachment 15 Attachment 16 Attachment 17 e e Seismic Section A - A' - Confidential Detail from Seismic Section A - A' - Confidential Cross Section B - B' - Confidential Seismic Section B - B' - Confidential Cross Section C - C' - Confidential Seismic Section C - C' - Confidential Aurora Field - Net Oil Pore Foot Map - Confidential Aurora Field - Net Pay Map - Confidential Fluid Contact Data - Confidential Production Plot Notice of Intent to Enlarge PBU Attached are five (5) copies of the non-confidential portions of this application and three (3) copies of the confidential portion. We request that the geological, geophysical, and engineering portions of this application marked as "Confidential" be kept confidential under AS 38.05.035(a)(9). Should you have questions regarding this application or should you require additional information to aid in your review please do not hesitate to contact Gary Gustafson at (907) 564-5304. Technical inquires should be directed to Frank Paskvan at (907) 564-5749. Thank you for your timely consideration. Best regards, ~~ Gil Beuhler GPB Waterflood Manager Attachments Cc: Marc Vela - ExxonMobil Bradley Brice - Forest Dan Kruse - ConocoPhillips G.M. Forsthoff - Chevron Francis Sommer, BPXA GiI Beuhler, BPXA- ~ Frank Paskvan, BPXA Jim Copen, BPXA Gary Gustafson, BPXA Leslie Senden, BPXA Gary Benson, BPXA Rosy Jacobsen, BPXA· Mark Worcester, ConocoPhillips Steve Luna, ExxonMobil Jeff Farr, ExxonMobil James Rodgers, ConocoPhillips Jane Williamson, AOGCC Mike Kotowski, DO&G - ----- -- -------- ____ ________n__ -- --------------- - '..'....,...--........." 2 ! I¡ ~ March 25, 2004 - e Mark D. Myers, Director Division of Oil and Gas Alaska Department of Natural Resources 550 West ih Avenue, Suite 800 Anchorage, AK 99501-3560 RE: Application to Expand the Aurora Participating Area and the Prudhoe Bay Unit - ADL's 028255,028256,028257,028260,028261,047448 and 047450 Dear Dr. Myers: Pursuant to Sections 5.3 and 9.1 of the Prudhoe Bay Unit Agreement (PBUA) and the provisions of 11 AAC 83.303, 83.351 and 83.356, BP Exploration (Alaska) Inc. ("BPXA"), acting in its capacity as Operator of the Prudhoe Bay Unit (PBU) and on behalf of itself and the other PBU Working Interest Owners, Chevron U.S.A. Inc., ConocoPhillips Alaska, Inc., ExxonMobil Alaska Production, Inc. and Forest Oil Corporation, hereby applies to the Department of Natural Resources for approval of the expansion of the Aurora Participating Area (APA) and the corresponding expansion of the Prudhoe Bay Unit (PBU). The proposed APA expansion area encompasses approximately 2,240 acres while the PBU expansion includes about 1,120 acres (Attachment 1). These expansion areas are located within ADL's 028255, 028256, 028257, 028260, 028261, 047448 and 047450 (Attachment 2). As demonstrated by the additional attachments, the areas within the proposed APA and PBU expansions are capable of contributing to the production of hydrocarbons in paying quantities sufficient to justify the development and production of the Aurora Reservoir in these areas. BPXA respectfully submits that the proposed expansion of the APA and PBU meets the criteria of 11 AAC 83.303 because it will promote conservation of natural resources, promote the prevention of economic and physical waste, and will protect all parties, including the State of Alaska. It also provides for the protection of the environment through planned development that optimizes the use and minimizes duplication of existing facilities. The following attachments are provided in support of this APA and PBU expansion: Attachment 1 Attachment 2 Attachment 3 Attachment 4 Attachment 5 Attachment 6 Attachment 7 Location Map of the APA/PBU Expansion Areas Lease Map of Expanded APA/PBU Amended Aurora Participations and Tract Allocations Amended Aurora Plan of Development and Operations Aurora Type Log - Well V-200 - Confidential Top Kuparuk Structure with Cross Section Index - Confidential Cross Section A - A' - Confidential 1 . 1'.!N ~ J 7nOj, Attachment 8 Attachment 8A Attachment 9 Attachment 10 Attachment 11 Attachment 12 Attachment 13 Attachment 14 Attachment 15 Attachment 16 Attachment 17 e e Seismic Section A - A' - Confidential Detail from Seismic Section A - A' - Confidential Cross Section B - B' - Confidential Seismic Section B - B' - Confidential Cross Section C - C' - Confidential Seismic Section C - C' - Confidential Aurora Field - Net Oil Pore Foot Map - Confidential Aurora Field - Net Pay Map - Confidential Fluid Contact Data - Confidential Production Plot Notice of Intent to Enlarge PBU Attached are five (5) copies of the non-confidential portions of this application and three (3) copies of the confidential portion. We request that the geological, geophysical, and engineering portions of this application marked as "Confidential" be kept confidential under AS 38.05.035(a)(9). Should you have questions regarding this application or should you require additional information to aid in your review please do not hesitate to contact Gary Gustafson at (907) 564-5304. Technical inquires should be directed to Frank Paskvan at (907) 564-5749. Thank you for your timely consideration. Best regards, Gil Beuhler GPB Waterflood Manager Attachments Cc: Marc Vela - ExxonMobil Bradley Brice - Forest Dan Kruse - ConocoPhillips G.M. Forsthoff - Chevron Francis Sommer, BPXA GiI Beuhler, BPXA Frank Paskvan, BPXA Jim Copen, BPXA Gary Gustafson, BPXA Leslie Senden, BPXA Gary Benson, BPXA Rosy Jacobsen, BPXA Mark Worcester, ConocoPhillips Steve Luna, ExxonMobil Jeff Farr, ExxonMobil James Rodgers, ConocoPhillips Jane Williamson, AOGCC Mike Kotowski, DO&G 2 ') In , , , 0 J L ø "_, 1 , .---- :....._........_._......._-,.- "I ^ ^ ~ ~..^..^m'_._.._.._m_~.."; i, --------- Top Kuparuk Structure AP A & PBU Expansion Attachment 1: Location Map of the AP A/PBU ExpansiôñAreas 3 . Producer Injector Type Well PR .ATTACHMENT SC.ALE: 1:78.000 D.A TE: 2004 ., £. Attachment 2: Lease Map of Expanded APA/PBU BPítA C;.;rtDgr.;,;pÎ1yllrnHS53b.dgn 4 Attachment 3: Amended Aurora Participations and Tract Allocations Working Interest Ownership (%) Tract Tract lease Township/Range Section Acres Royalty BPXA CPAI EM Chevron Forest Participation % % 10 47448 12N-12E Sec. 23: S1/2, 480 12.5 26.35536 36.069385 36.39549 1 . 160000 0.019768 2.394 S1/2NW1/4, S1/2NE1/4 11 28256 12N-12E Sec. 15: SW1/4, 2,000 12.5 26.35536 36.069385 36.39549 1 . 160000 0.019768 24.164 (J) S1/2SE1/4 e ('') Sec. 16: S1/2, ;.Þ 2: NW1/4 2:- Sec. 21: All iii Sec. 22: All 12 28255 12N-12E Sec. 17: NE1/4, 1,120 12.5 26.35536 36.069385 36.39549 1 . 160000 0.019768 5.112 S1/2 >,,? Sec. 18: SE1/4 t) Sec. 19: N1/2NE1/4 Sec. 20: E1/2, N1/2NW1/4 20 28259 12N-12E Sec. 29: SE1/4, 560 12.5 26.35536 36.069385 36.39549 1 .1 60000 0.019768 2.789 E1/2NE1/4 Sec. 32: E1/2 21 28258 12N-12E Sec. 27: All 2,560 12.5 26.35536 36.069385 36.39549 1 .160000 0.019768 44.447 Sec. 28: All e Sec. 33: All Sec. 34: All 22 28257 12N-12E Sec. 25: S1/2, 2,320 12.5 26.35536 36.069385 36.39549 1.160000 0.019768 19.063 S1/2NW1/4 Sec. 26: All Sec. 35: All Sec. 36: All 47 28260 11N-12E Sec. 2: W1/2 320 12.5 26.35536 36.069385 36.39549 1 .160000 0.019768 0.085 48 28261 11N-12E Sec. 3: All 1,560 12.5 26.35536 36.069385 36.39549 1 .1 60000 0.019768 1.927 Sec. 4: E1/2, 5 49 47450 Total -'.~ '\ :) ,,;;' 11N-12E E1/2SW1/4, NW1/4 Sec. 9: NE1/4, N1/2SE1/4 Sec. 10: W1/2NW1/4 NW1/4SW1/4 Sec. 5: E1/2NE1/4 80 12.5 11000 BPXA - BP Exploration Alaska Inc. Chevron - Chevron U.S.A. Inc. CPAI - ConocoPhillips Alaska, Inc. EM - ExxonMobil Alaska Production, Inc. Forest - Forest Oil Corporation 26.35536 36.069385 36.39549 1.160000 0.019768 6 " 0.019 100 e e e e Attachment 4: Amended Aurora Plan of Development and Operations PLAN OF DEVELOPMENT AND OPERATIONS (2004) FOR THE AURORA PARTICIPATION AREA Development of the Aurora Reservoir includes phased drilling of approximately eighteen (18) to twenty five (25) production and injection wells from S-'Pad. Initial (Phase I) drilling commenced July 2000 with production startup in November 2000. Water injection started in January 2002. Production is commingled with IPA production on S-Pad and processed at GC-2. Phase II drilling began in 2Q 2001. A total of nineteen (19) Aurora development wells have been drilled through end of January 2004. See Table I, below. The Phase II program will continue through 2005. Tertiary recovery, utilizing IPA miscible gas for WAG (Water-Alternating-Gas injection) was started in the S-104i and S-lOli wells during 4Q 2003. Wells Six wells were drilled during Phase I development (S-IOO, 101i, 102, 103, l04i, 105). Two Phase I wells (S-lOli and S-104i) were drilled as pre-produced injectors. Phase II drilling commenced in mid-2001 and through January 2004 thirteen (13) Phase II wells have been drilled (S-106, S-107i, S-108, S-109, S-llOi, S-112i, S-I13B, S-114Ai, S-115, S-1l6i, S-I17, S-1l8 and S-120i). Currently, five wells are on injection S-lOli (WAG), S-104i (WAG), S-107i, S-llOi, and S-112i. Pre-produced injectors S-116i and S-120i will be pre-produced for 10 days then converted to water injection 1 Q 2004. As part of a proposed P A expansion for 2004, well S-119 will be drilled near the current northern P A boundary. Depending on its results, additional development in the northern P A area will be evaluated. The Aurora Owners will continue to evaluate optimal well count and well locations as development and depletion of the reservoir progresses. Unutilized IP A well-bores will also be evaluated to access Aurora reservoir targets. Although pattern spacing is expected to be irregular, minimum nominal inter-well spacing is estimated to be 80 acres. Drill Sites and Pipelines Aurora development will use the existing WOA infrastructure of pipelines, roads and pads. Initial development from S-Pad utilizes existing low-pressure pipelines from S-Pad to GC-2. Additional gravel was laid to expand the northern part of S-Pad to accommodate wells and drilling beyond Phase I. Aurora Owners installed Vertical Support Members (VSMs) and trunk lines to the north of S-200 to extend the production/test/produced water and artificial gas lift headers. Aurora Owners have approved the expansion of an MI trunk to allow water injectors to be converted to WAG injection for the tertiary recovery project. Support Facilities Aurora will share North Slope infrastructure with the IP A as needed to support Aurora Operations, minimizing duplication of facilities. These include camp facilities, potable water and waste disposal facilities, shop and maintenance facilities, airstrip, construction pad, storage and warehouse space, oily waste disposal facilities and telecommunications systems. 7 ;...- ,...~, p ~ ~ ~ r-, t1 ~'J17- Production e e The wells at Aurora have a current combined production of approximately 10-15 MBD. The current water injection rate is approximately 20-25 MBWPD. Waterflood Waterflood operations began in January 2002. A waterflood configuration is anticipated to conform to the minimum nominal inter-well spacing of 80 acres. Injection water is obtained from the IP A for use in the Aurora waterflood. For more details on waterflood surveillance and upcoming activities, see the attached AOGCC Annual Surveillance Report for the year 2003. Production Allocation Aurora production allocation is being performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust the total Aurora production. A minimum of one well test per month is used to check the performance curves and to verify system performance. No NGLs are allocated to Aurora. Enhanced Recovery Techniques Miscible gas injection is expected to increase economic recovery of Aurora hydrocarbons by approximately 3-5 mmbo. Table 1: Aurora Wells Completed in the Kuparuk Formation Sw Name 8-1 00 8-101 8-1 02 8-1 02L 1 8-1 03 8-1 04 8-1 05 8-1 06 8-1 07 8-1 08 8-1 09 8-11 0 8-112 8-1138 8-114A 8-115 8-116 8-117 8-118 8-120 Api 500292296200 500292296800 500292297200 500292297260 500292298100 500292298800 500292297700 500292299900 500292302300 500292302100 500292313500 500292303000 500292309900 500292309402 500292311601 500292313000 500292318300 500292313700 500292318800 500292318600 Spud Date 7/9/2000 8/9/2000 9/14/2000 1 0/26/2003 11/6/2000 1/11/2001 10/25/2000 5/5/2001 6/29/2001 6/11/2001 12/31/2002 8/13/2001 7/22/2002 7/8/2002 9/19/2002 12/20/2002 12/6/2003 2/17/2003 1/2/2004 12/21/2003 Well Status Desc Oil Producer Flowing Miscible Injector Operating Oil Producer Gas Lift Oil Producer Gas Lift Oil Producer Gas Lift Miscible Injector Operating Oil Producer Gas Lift Oil Producer Gas Lift Water Injector Injecting Oil Producer 8hut-ln Oil Producer Gas Lift Water Injector Injecting Water Injector Injecting Oil Producer 8hut-ln Water Injector Injecting Oil Producer Flowing Water Injector 8hut-ln Oil Producer Gas Lift Oil Producer Shut-In Not Yet Completed / Td Not Yet Reached. 8 51 9 GAS INJ RATE 70000 60000 50000 40000 30000 20000 GAS RATE OIL RATE _ _ WATER INJ RATE _ WATER RATE 10000 o 2000 2001 2003 2004 2002 Attachment 16: Aurora Production and Injection Plot 21 e e bp A'IT ACHMENT 17 0·······,.········.·.········ d î£(~HZ VIA CERTIFIED MAIL - RETURN RECEIPT REQUESTED Mt1re.h17,2004 Mark Uyer&, Dirndm Oil 8. Gas IJepartment of Natural Aesourçæ ,550 Wæt 1~ Avenue, S\Jit.e SOO AncooraQ4Jl¡ AK 9Q501 RÐ: N~å of Innamno Enlarge the Prudhoe Bay Unit toE~ e;q:t~~ to tÆ Aurora and Orion Þ<art:kip9ting Ateås DaM DLMyers: Pu~n. W See'tkln9,1í)11hePrudhœ BaylJrift Agmementand SMllon 1.00301 the Prudhœ BayUni' ~ra1jng .Agrø~nt" BP E;q:>lora!loo(A¡'¡sfœ:~ h"tc,. ~otAngin ~a eapdy B OperatM í)f th~ Prudhoe 81)' Unitt. h.4Jby ~$no1i:;.O' ~hfpPfOPoaêd ~ntiirg_.n' of tn. Pn.I~ Bay Unit AI'JMt!o iln.cCftl,p1H pr'~dBxpilmiQnl!ilQlhå Aurora. Md Orion Partioip&ting Ar>oas-"Thépmp~ eftsdive dlde. for tñe Bntii~n.a h~ thè 1m .t:kw ~ dMlcakmctar rnMth'olkMing ltJe œté ,pi thainai I~IJ mthtmtuglfrKl}tlby the A_ski ~nl cd NltumJ FMtoU~ The léu. or portiona 01 klaa. ccntem.éd for i~s:oo in the. Pftldhøø BayUntt Arearen1ârgernemAreu"') are liatêd on Exhibit A âM d~ on ExhibitB~ botb of which are a~ høretí) ·åßdinc~ated herein, As pn;w1œd by Section 9,1 of the Prucl:!œ Bay Unitt Agreement, h .~s ~ In 1. En.~". Arus haw ~ fi\3.IOOSb!y d..m"Il~ 10 be wtlhinlhD Aurorã ãfJd Orion R_f'\!\QIl"lf a portbJ'1 of ~Ictt ~r. witNn!h~Ptudhof) B,ay Un~ ArmLTha lrJclu~iôr1of t'" Enla~mM't AfMsln 1'" PftIc:1hoê 8.ay UnlArea ¥fll ettablella timely dJWè10pmEllttt of 1'" Aurora rmd Orion AHèNOira by ~aâlmt1fng the ~ Qf.~mg Prudhoo 8!iy unit faoil~ies, Thf) EII~n ~ ~ ProdMâ Bay Unrt Areà to include tbe Erwngernmm NUB wil prom0t9 ¢OOBatvRtion of natumt mS¡[flJrcœ. pfOm~e tht pæventkln of~ic and physical waste, and wll pftltect a11 ~f1ieI¡, !nœuding tht State o'Aaa~. Thee>ipension·aIso prOvidN fortha Pfotecliooot tn. ill'Wi~ !fhroughpfanMd dewlopn~nt whiohop~_ .... UH 0' i\:<Ì$1lng f~œ 100 p~ un~Ia'Y dup1lcath:m of Iscllltlæ. 2" ~ 20Dt¡ e e Pumœnt to 6èdioo 9.1 (b) of UJa· PrtlQhoe Bay Unit Agreement. ,¡:,!in'f Int~reittiM:t ~rty mey file wiiththa Unlt O~~or wrih::en objecticns., and' rea~'h~R}IOf~, toffie pfcpoHd'ni~~nt~ wiithin thjrty~30) daY$ ('If Ihit dªI~.hl$ Notlol9 W3$ m4úilad. il )/'00 ~e anycornrnùntš Of ~~fk¡n~. þlåaae coot:aotGáry Gustáf$Onal (907) 5&4", 5304. Maehm~t~ Exhibft A - PeUEnh~nl .Atiltl$ e~Pª.$1 I" .AÜfQra 8. OOOn Pª~lel~tjng Areª Expan$1eM E.xhlbae B - Map ·<Jf·PropO$Id fBU entl:u~m~t ArtJM Cc: Mark: Vela. eM wa cèt1ifiéd 11ft_I c... Kro$@, OPA.l vI.a cerUned :mllt' t. GurulD, Fo~ 01 w__rtilldrnal G.M. Formí:hOl, Oh~n v. c~ mail Gary Benson. BPXA Rose)' J~æn.,6PXA M_ WOfQi)ñr, CPAI ~ Luna, EM GIlJ GUltatlon. BPXA L~llitJS~dWf, BPXA Mite KõtôW'Skl. COIG JIfII Fl'ff. EM J~ Rodgetta, OPAl Judy Boono,BPXA 1 23 ('...;,.r.!\ !\~1\~f"_','j' 1'" W\\" ~ f\ ')f~ft~' e e ", EXHIBIT A PBl¡ };NLARGEMENT AIlE.AS TO IM....COMJ·¡\SS Tal: AUROR.1l A.1'oID ORION PARTICIPA TI~G AREA EXPANSIONS I. ,'\CRORJ\ PAR11(:[PATtNG iUU:',¡\J'-8U EXPANS10N - I,UG A~ I)e~rìp[ lr.ttI At:œ1I~ AI)L tft)·JI} I)' W~() ~ J 11 1N-R12E ].5~ 5] I1SrH!4, S\V I 14 16: 8112. NWl/4 ~~¡.oo ~lt24"lWIJ4. NEIJ4 900 02~256 j2.:5~ ~)t5491~ CPM :36.06931S$~ BPXA CT 1,1~ f'(ìœä£ O_O~ 916$" 12 JI2N·R!2E S¢dÎœ 1'1: NIH/4 100 (12:82:55 12,:5tJc :&\f 36.,395491'" CrA) 36.~:~S5* IPXA U,3:5S356% cr 1.1~ ri),œ$[O,OI9163~' ]I. ORION 'ARTICJP~\ TING ARF..AJPß{J EXPA~'¿SI0N - )to A(m¡. lJ'E ~¡jd~jQ~ å1& ~1}; !lm 1:3 T]2~~IIE ~tIoo 23: SWlJ4. WII2NW 1/;4 240 j,90J6ï EM 36..395491" ,PAl 36.069~I:l"i~ BPXA 26.355356'11 CT U~ (t01916'S~ L.efèmð EM - BuonMoÞil AlasK.n cr..u - Câ/Ï(JiL"ðPJrllüps¡ AI..~L:~, mc. BPXA - BiP E,tpl(}f.atitrrn (Alfl!>k4\!) Inc cr .-. ChßVrmll.J.S.A 1FK:. F~5t - f'oœst Oil C:orpí)J1ltioo iBPXA. CPAllmd EM II!:IW O~'n thCilOOve .rclc:re~d Aurom PMBU cxpmsioo íllCre. in ADl's¡ 021l2~S 8!)d023136 if I I,ª,'O dlt\l\'!.lIefíto"'·~p peh..~~es (~"PAflSO.EM aM :5~BPKN2.S~CP^IJ2:5~,SM). 18 in pl'l)Ç~S8Q{ ~t'I¡ <C~.$$iped by Bf'XA. CPAI:;mð EM intø the W::ìped PBU oWinerøp ~im1.~:Js indie3itœ ,¡¡oove, '3 ~ r {: f:!' 24 ~'" I\) V1 bp -- -- o BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 March 25, 2004 Commissioners Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 RE: Amendments to Aurora Pool Rules and Area Injection Order CO 457 A and AIO 228 Dear Commissioners: Enclosed for your review and action is the Prudhoe Bay Unit (PBU) Working Interest Owners' application for amendments to Conservation Order 457A (as amended by Conservation Order 492) and Area Injection Order 22B, the Aurora Pool Rules and the Area Injection Order for the Aurora reservoir. These amendments are necessary because BP Exploration (Alaska) Inc. (BPXA), as Aurora Operator and Unit Operator, has applied to the Department of Natural Resources to expand the Aurora Participating Area and the Prudhoe Bay Unit. Accordingly, BPXA hereby petitions the Commission to amend the above referenced rules as necessary to accommodate this expansion. BPXA requests that Section #4 of Conservation Order 457 A and Section #4 of Area Injection Order 22B be amended as follows to reflect the revised legal description describing the expanded area affected by these orders. Umiat Meridian f"''''''.'''''''''': . "....."'''''..""....''''.. ;~'own~,~,!p . ~~,~~e ¡Sections ····Sec: '''2'''''WY2 Sec. 3: All R12E ¡Sec. 4: EY2, NW%, EY2SW% !Sec. 5: EY2NE% ,Sec. 9: NE%, N%SE!4 ~Sec. 10: NW%SW%, W%NW!4 ·"!'Sec.15:"""'SY2SE%·;""Sw1Ä . (Sec. 16: NW!4, S% ;Sec 17: S%, NE%, R12E ;Sec 18: SE!4 :Sec 19: N%NE% Sec 20: EY2, NY2NW!4 Sec 21: All '''-'''''''' ."'.",,"'''''''.,'''',,"'..,.'.....,.......,...-......... ",,,,.,,'''..,,,"" '. .. ",,,,,,,,',." T11N T12N - "..", """"''',"'''" '''0 "",,,.",. . . "'"~''''''' . '"'"''''''''',"''''''''''''''''''''' 1 T12N ee R12E All S¥2, S¥2NW%, S¥2NE% S¥2, S¥2NW% All ec 27: All; ec 28: All ec 29: E¥2NE%, SE% ec 32: E¥2 ec 33: All ec 34: All ec 35: All ec 36: All Information in support of these amendments is attached. Please maintain as confidential those certain attachments attached and labeled "Confidential" in accord with AS 31.05.035 and 20 AAC 25.537. Please contact Gary Gustafson at 564-5304 or Frank Paskvan at 564-5749 if you have any questions or need additional information. Sincerely, ~~ Gil Beuhler GPB Waterflood Manager Attachments: Attachment 1 Attachment 2 Attachment 3 Attachment 4 Attachment 5 Attachment 6 Attachment 6A Attachment 7 Attachment 8 Attachment 9 Attachment 10 Attachment 11 Attachment 12 Attachment 13 Attachment 14 Location Map of the AP A/PBU Expansion Areas Lease Map of Expanded AP A/PBU Aurora Type Log - Well V-200 - Confidential Top Kuparuk Structure with Cross Section Index - Confidential Cross Section A - A' - Confidential Seismic Section A - A' - Confidential Detail from Seismic Section A - A' - Confidential Cross Section B - B' - Confidential Seismic Section B - B' - Confidential Cross Section C - C' - Confidential Seismic Section C - C' - Confidential Aurora Field - Composite Net Oil Pore Foot Map - Confidential Aurora Field - Composite Net Pay Map - Confidential Fluid Contact Data - Confidential Aurora Production and Injection Plot 2 ee Cc: Francis Sommer, BPXA Marc Vela, ExxonMobil Dan Kruse, ConocoPhillips G.P. Forsthoff, Chevron Bradley Brice, Forest Oil Jane Williamson, AOGCC Mike Kotowski, DO&G Gil Beuhler, BPXA Frank Paskvan, BPXA Gary Gustafson, BPXA Jim Copen, BPXA Leslie Senden, BPXA Rosy Jacobsen, BPXA Gary Benson, BPXA Steve Luna, ExxonMobil Jeff Farr, ExxonMobil James Rodgers, ConocoPhillips Mark Worcester, ConocoPhillips ee 3 bp _It · March 25, 2004 e e 0·"'······· . ". BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Commissioners Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 RE: Amendments to Aurora Pool Rules and Area Injection Order CO 457 A and AIO 228 Dear Commissioners: Enclosed for your review and action is the Prudhoe Bay Unit (PBU) Working Interest Owners' application for amendments to Conservation Order 457A (as amended by Conservation Order 492) and Area Injection Order 22B, the Aurora Pool Rules and the Area Injection Order for the Aurora reservoir. These amendments are necessary because BP Exploration (Alaska) Inc. (BPXA), as Aurora Operator and Unit Operator, has applied to the Department of Natural Resources to expand the Aurora Participating Area and the Prudhoe Bay Unit. Accordingly, BPXA hereby petitions the Commission to amend the above referenced rules as necessary to accommodate this expansion. · BPXA requests that Section #4 of Conservation Order 457 A and Section #4 of Area Injection Order 22B be amended as follows to reflect the revised legal description describing the expanded area affected by these orders. Umiat Meridian · T11N R12E T12N R12E ns ec. 2 W¥2 ec. 3: All ec. 4: E¥2, NW%, E¥2SW% ec. 5: E¥2NE% ec. 9: NE%, N¥2SE% ec. 10: NW%SW%, W¥2NW% ec. 15: S¥2SE%, SW% ec. 16: NW%, S¥2 ec 17: S¥2, NE%, ec 18: SE% ec 19: N¥2NE% ec 20: E¥2, N¥2NW% ec 21: All 1 T12N e e e_ ec 22: All ec 23: S¥2, S¥2NW%, S¥2NE% ec 25: SY2, S¥2NW% ec 26: All ec 27: All; R12E ec 28: All ec 29: EY2NE%, SE% ec 32: E¥2 ec 33: All ec 34: All ec 35: All ec 36: All · Information in support of these amendments is attached. Please maintain as confidential those certain attachments attached and labeled "Confidential" in accord with AS 31.05.035 and 20 AAC 25.537. Please contact Gary Gustafson at 564-5304 or Frank Paskvan at 564-5749 if you have any questions or need additional information. Sincerely, ~~ Gil Beuhler GPB Waterflood Manager · Attachments: Attachment 1 Attachment 2 Attachment 3 Attachment 4 Attachment 5 Attachment 6 Attachment 6A Attachment 7 Attachment 8 Attachment 9 Attachment 10 Attachment 11 Attachment 12 Attachment 13 Attachment 14 Location Map of the AP A/PBU Expansion Areas Lease Map of Expanded AP A/PBU Aurora Type Log - Well V-200 - Confidential Top Kuparuk Structure with Cross Section Index - Confidential Cross Section A - A' - Confidential Seismic Section A - A' - Confidential Detail from Seismic Section A - A' - Confidential Cross Section B - B' - Confidential Seismic Section B - B' - Confidential Cross Section C - C' - Confidential Seismic Section C - C' - Confidential Aurora Field - Composite Net Oil Pore Foot Map - Confidential Aurora Field - Composite Net Pay Map - Confidential Fluid Contact Data - Confidential Aurora Production and Injection Plot · 2 · Cc: · · . Francis Sommer, BPXA Marc Vela, ExxonMobil Dan Kruse, ConocoPhillips G.P. Forsthoff, Chevron Bradley Brice, Forest Oil Jane Williamson, AOGCC Mike Kotowski, DO&G Gil Beuhler, BPXA Frank Paskvan, BPXA Gary Gustafson, BPXA Jim Copen, BPXA Leslie Senden, BPXA Rosy Jacobsen, BPXA Gary Benson, BPXA Steve Luna, ExxonMobil Jeff Farr, ExxonMobil James Rodgers, ConocoPhillips Mark Worcester, ConocoPhillips . 3 ?'ì; ,~ ) J h J UJNfTERS KJ . Producer Injector Type Well 1'24000 STRTUTE NT Top Kuparuk Structure Attachment 1: location Map of the APAlPBU Expansion Areas 4 Unit PA SCALE: ATTACHMEM" 2 Attachment 2: lease Map of Expanded APAlPBU BPX.li, Ç'J!(¡'jogr,¡¡¡µhyt'lmJ 4~b.dg!1 GAS INJ RATE 70000 60000 50000 40000 30000 20000 10000 o 2000 GAS RATE WATER RATE OIL RATE WATER !NJ RATE 2001 2002 2003 2004 Attachment 14: Aurora Production and Injection Plot 18 I I ~