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Home My WebLink AboutAIO 023AREA INJECTION ORDER NO. 23 Northstar Unit Northstar Field Northstar Oil Pool 1. June 25, 2001 BPXA’s application for AIO and pool rules 2. July 2, 2001 Notice of Public Hearing, Affidavit of Publication, and mailings 3. July 31, 2001 BPXA’s request for administrative approval of gas injection, enhanced oil recovery, and application for maximum efficient rate (confidential portion of application held in secure storage) 4. August 13, 2001 BPXA’s public version of Northstar application for approval of pool rules and area injection order (public version replaced confidential versions submitted on June 25, 2001 and August 3, 2001) (confidential versions were withdrawn by the operator at the August 16, 2001 hearing and therefore shredded by AOGCC) 5. August 16, 2001 Public hearing sign-in sheet and transcript (confidential maps held in secure storage) 6. September 27, 2004 Public Notice regarding Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells 7. February 7, 2005 BPXA’s request for modifications to Northstar Oil Pool 8. December 29, 2005 BPXA’s request for administrative approval to continue gas injection operations (AIO 23.001) 9. January 10, 2006 BPXA’s response to administrative approval to continue gas injection operations 10. September 5, 2013 BPXA’s request for administrative approval to continue gas injection operations (AIO 23.002) 11. May 5, 2014 BPXA’s request for administrative approval to change the anniversary date from June 8th to August 31st for well NS29 (AIO 23.001 Amended) 12. May 5, 2014 BPXA’s request for administrative approval to change the anniversary date from October 19th to August 31st for well NS25 (AIO 23.002 Amended) 13. April 21, 2016 BPXA’s request for administrative approval to continue gas injection operations (AIO 23.003) 14. February 5, 2019 Hilcorp’s request to cancel AIO 23-002 (AIO 23.002 cancel) 15. March 30, 2020 Administrative approval to allow well Northstar Unit NS-17 (PTD 2021690) to continue gas injection service with a known inner annulus repressurization. (AIO 23.004) 16. November 17, 2021 Request for admin approval to continue gas injection operations (AIO 23.005) 17. December 1, 2021 Emails between Hilcorp and AOGCC ORDERS ') ') STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. allowing underground injection of fluids for enhanced oil recovery in Northstar Oil Pool, Northstar Field, Beaufort Sea, Alaska ) Area Inj ection Order No. 23 ) ) Northstar Field ) N orthstar Oil P 00 I ) ) October 9, 2001 IT APPEARING THAT: 1. By letter and application dated June 25, 2001, BP Exploration (Alaska) Inc. ("BPXA") requested an order authorizing the injection of fluids for enhanced oil recovery in the Northstar Oil Pool ("NOP") encompassing acreage within the Northstar Unit, Beaufort Sea, Alaska. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on July 5, 2001. 3. The Commission did not receive a protest. 4. By letter and application dated August 13, 2001, BPXA submitted a new public version of pre-filed testimony and exhibits to be entered into the public record for the August 16, 2001 public hearing. 5. A hearing concerning BPXA's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501 on August 16, 2001. Concurrently, the Commission heard testimony concerning proposed pool rules for the NOP. FINDINGS: 1. Commission regulation 20 AAC 25.402 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. 2. BPXA is the operator of the Northstar Unit. BPXA and Murphy Exploration, Inc. are working interest owners in the Northstar Unit. The State of Alaska and the US Federal Government are the landowners. 3. The proposed injection interval is the NOP, which consists of the accumulation of hydrocarbons that is common to, and correlates with, the interval between 12,418 feet and 13,044 feet measured depth ("MD") in the Seal A-Ol well. This accumulation occurs in the Sag River, Shublik and Ivishak Formations. Area Injection Order NL. ) October 9, 2001 ) Page 2 4. The average oil saturation of the Ivishak is 42% at the volumetric reservoir centroid, and the maximum oil column is estimated to range from 270 to 300 feet. 5. The NOP oil-water contact ("OWC") is 11,100 feet true vertical depth subsea ("TVDss"), based on core, RFT, MDT and well test data. 6. Original in place oil and gas volumes contained in the Ivishak Formation were estimated, by the Operator, using geologic and engineering data and reservoir modeling. The NOP contains approximately 247 million stock tank barrels ("MMSTB") original oil in place ("OOIP"), 487 BCF original gas in place ("OGIP") including an estimated 7 BCF gas cap inferred from reservoir data. 7. The Sag River Formation in the NOP contains approximately 37.7 million barrels OOIP and 52.1 BCF OGIP.· based on log and core analysis in addition to analog comparison to similar accumulations on the North Slope. There are currently no production tests in the Sag River Formation within the NOP. 8. At this time, there is insufficient information regarding Shublik Formation reserves. 9. The Operator studied miscible gas injection, waterflood with miscible gas injection, gas cycling, and primary depletion to evaluate recovery mechanisms. All of the cases used the same number of wells and locations. Injection was controlled to maintain reservoir pressure near the original conditions for the miscible gas and waterflood cases, with pressure declining in the gas cycling and primary depletion cases. The table below summarizes recovery of oil and natural gas liquids ("NGL") based on simulation evaluation. Recovery Oil NGL Total Liquid Factor MMSTB MMSTB MMSTB % OOIP (Oil) ------- - --- Miscible Gas 159.3 16.9 176.2 64.5 Injection Waterflood 128.3 6.6 134.9 52.0 Gas Cycling 123.6 12.1 135.7 50.0 Primary Depletion 89.1 5.1 94.2 36.1 10. The Operator selected miscible gas injection as the enhanced oil recovery method because the model studies indicated miscible gas injection would recover 12% and 14%, respectively, more oil than either gas cycling or waterflood. Water alternating with gas ("WAG") model runs indicated no increased additional recovery over miscible gas injection. 11. Miscible injectant will be made by blending make up gas from Prudhoe Bay Unit ("PBU") with Northstar produced gas. The present development plan anticipates NGL will be left in the produced gas during the miscible injection phase of the project that is expected by the Operator to last the first four years of field life. 12. The project will inject up to 60% hydrocarbon pore volume of miscible enriched Area Injection Order Nt., October 9, 2001 ) ) Page 3 natural gas and NGL into the oil column. The miscible gas injection phase will be followed by lean chase gas injection for the remainder of the oil production phase of field life. 13. Initial NOP drilling development plans comprise 22 wells. This well count includes five miscible gas injectors, sixteen oil producers, and one Class I disposal well. The injectors will be located in the thickest oil column in the central portion of the reservoir to maximize miscible sweep. Two of the injectors will be pre-produced to help load the production facility at startup. 14. Wells will be perforated with sufficient standoff from the OWC to maintain water production below the 30,000 barrels of water per day ("BWPD") facility limit. V ertical barriers to water coning in the NOP will be evaluated with reservoir pressure data obtained after field startup. 15. The Operator reports initial reservoir pressure measured in 1984 was 5305 pounds per square inch ("psi") at 11,100 feet TVDss. Current reservoir pressure (circa August 2001) at the same datum is estimated to be 5180 psi. The pressure decrease, as interpreted by the Operator, is attributed to regional communication with the Prudhoe Oil Pool through an aquifer common to both the Northstar and Prudhoe Bay Unit reservoirs. 16. Based on initial reservoir simulation results, the Operator's reservoir management strategy during miscible injection is for 100% voidage replacement and to maintain reservoir pressure within +/- 50 psi of the current pressure level, 5180 psi at 11,100 feet TVDss. 17. The Operator's objective, with respect to the reservoir management strategy, is to maximize ultimate recovery consistent with sound engineering practice. The injection project is being implemented concurrent with field startup in order to deliver maximum benefit. During the first year of the project, injection may exceed voidage replacement to ensure miscibility and compensate for pressure decline. 18. The Operator has indicated reservoir pressure in the Northstar reservoir will need to be managed in order to: ensure miscibility; minimize oil loss due to shrinkage from producing below the bubble point pressure; minimize oil loss due to pushing oil into the aquifer by over pressuring the reservoir; and achieve some aquifer influx to sweep the periphery and structurally low areas. Reservoir pressure may decline at about 6- 10 psi/year assuming continued pressure depletion through the Ivishak aquifer. The Operator anticipates average reservoir pressure will not be increased appreciably above its current level to prevent hydrocarbon displacement into the Ivishak aquifer. Injection wells will be located in the thick oil column areas of the reservoir to minimize oil pushed into the aquifer beneath injectors due to local pressure gradients. 19. The gas injection plant and a gas injection well will be commissioned prior to the initial startup of oil production using Prudhoe Bay Unit make up gas. This will reduce the amount of flared gas that is associated with the start up of new production facilities. Area Injection Order Nt., ) October 9, 2001 ) Page 4 20. Conductor casing requirements in 20 AAC 25.030(c)(2) have been waived for the Northstar development per the memo entitled "Dispensation for 20 AAC 25.030(c)(2)" dated March 1,2000. 21. All casing strings will be run and cemented in accordance with 20 ACC 25.030 and 30 CFR 250.404. Injection wells will have a cement evaluation log run to confirm isolation of the injection fluids to the approved injection intervals (Sag River and Ivishak Formations) as required per 20 AAC 25.030(d)(7). Such logs will also satisfy the requirements of 30 CFR 250.404( a)( 5). o Surface hole sections for all wells will be drilled to a depth of approximately 3160 feet TVDss (150 feet TVD below the SV6 geologic marker). o Gas injection well intermediate hole sections are planned to be drilled to top set casing at the Sag River Formation at approximately 10,645 feet TVDss. o Production wells will have two intermediate hole sections. The first will be drilled to top set the Miluveach Formation at approximately 9264feet TVDss; the second drilled to top set the Sag River Formation at approximately 10,645 feet TVDss. o Both production and injection hole sections will be drilled through the Sag River, Shublik, and Ivishak Formations to a TD in the Ivishak or the adjacent Kavik Formation. 22. Tubing and packers will be run in all wells. Injection well design will place the packer within 200 feet of the targeted injection zones, the Sag River and Ivishak Formations, in accordance with 20 AAC 25.412(b). Packer placement may result in a packer to perforation distance greater than 200 feet, to retain the option of perforating the Sag River Formation in the future. 23. All N orthstar wells are located offshore. With the exception of the Class I disposal well, all wells are capable of unassisted flow of hydrocarbons to the surface and will be equipped with a fail-safe automatic surface safety valve ("SSV") and a fail-safe automatic surface-controlled subsurface safety valve ("SSSV"). The SSSV's in both the producers and injectors will be wire line retrievable. The SSSV's are intended to comply with the requirements of both 20 AAC 25.265 and 30 CFR 250.801 and 250.806. 24. In the process of permitting the Class I disposal well on Northstar Island, the EP A determined no USDW's (freshwater strata) were present in the Northstar area. 25. The expected maximum injection pressure for the gas injection wells is 5300 psi. This injection pressure is insufficient to initiate or propagate fractures through the confining strata, and, therefore, will not allow injection or Formation fluid to migrate out of intended injection zones. Area Injection Order Noo...I) October 9,2001 ) Page 5 26. The Kingak Formation is approximately 1,000 feet thick in the area and serves as the upper confining zone. The Kingak Formation is continuous throughout the area and conformably overlies the Sag River Formation. The Kingak Formation was deposited as marine shale and silt during the Jurassic period and is impermeable. 27. The NOP is confined below by the Kavik Formation, a marine shale sequence of Permian age, which is continuous throughout the area. The Kavik Formation rests uncomformably on the carboniferous aged Lisburne Group. The Kavik Formation is essentially impermeable with a thickness of approximately 100 feet in this area. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An Area Injection Order is appropriate for the project area in accordance with 20 AAC 25.460. 3. There are no freshwater strata in the NOP area. 4. The proposed injection operations will be conducted in permeable strata. The injection pressures will be maintained below the fracture pressures of the confining intervals. 5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 6. Implementation of an enhanced recovery operation initially using miscible gas injected into the Sag River, Shublik and Ivishak Formations will preserve reservoir pressure energy and enhance ultimate recovery. The miscible gas injection phase will be followed by lean chase gas injection for the remainder of the oil production phase of field life. 7. The proposed NOP miscible gas /lean gas chase injection project will result in approximately 29% increased recovery (82 MMSTB) over primary production alone. 8. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 9. An Area Injection Order enabling enhanced oil recovery activity will not cause waste or jeopardize correlative rights. NOW THEREFORE IT IS ORDERED THAT: Underground injection of enriched miscible gas and lean gas pursuant to the project described in BPXA's application and subject to the conditions, limitations, and requirements established in the rules set out below (in addition to the statewide requirements under 20 AAC 25 to the extent not superceded by these rules) apply to the affected area encompassing all of State Oil and Gas Leases ADL 312798, ADL 312799 and ADL 312808, portions of State Oil and Gas Area Injection Order No. ) October 9, 2001 ) Page 6 Leases ADL 312809 and ADL 355001, and all of Federal Oil and Gas Leases OCS-Y- 1645, OCS-Y-0179 and OCS-Y-0181 to the extent such leases are located within the lands described below: STATE LEASES Umiat Meridian Township Range Sections T14N R13E 30 through 35: All State lands T13N R13E 2 through 18,20 through 24: All State lands T13N R14E 17 through 20,29 and 30: All State lands The affected area is more particularly described as follows: ADL 312798 Consists of Tract C30-46 (BF-46), a portion of Blocks 470 and 514 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79, more particularly described as follows: Those lands located easterly of the west boundary ofT.13N., R.13E., and T.14N., R.13E., Umiat Meridian, Alaska, being the north-south line intersecting the north and south boundary of Block 470, within the offshore three-mile arc lines listed as State area of Block 470 "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lands in Block 514 easterly of the west boundary of T.13N., R.13E., Umiat Meridian, Alaska (being identical with line 1-2 of Block 514) and lying northerly of the south boundary of Sections 7 and 8, T.13N., R.13.E, Umiat Meridian, Alaska (being identical with line 2-3 of Block 514) and that portion of Section 16, T.13N., R.13E., Umiat Meridian, Alaska, within the N1/2 S1/2 (being easterly of line 3-4 of Block 514), being a portion of the listed State area of Block 514 on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79. ADL 312799 Consists of Tract C30-47 (BF-47), a portion of Blocks 471 and 515 as shown on the "Leasing and Nomination map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79, more particularly described as follows: Those lands located in Block 471 within the offshore three-mile arc lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram", approved 10/4/79, and those lands in N 1/2, N 1/2 S 1/2 of Block 515 within the offshore three-mile arc lines being a portion of the listed State area on the "Supplemental Official O.C.S. Block Diagram " approved 10/4/79. ) Area Injection Order No. _ October 9,2001 ) Page 7 ADL 312808 Consists of Tract C30-56 (BF-56), a portion of Blocks 514,515,558, and 559 as shown on the "Leasing and Nomination Map" for the federal/state Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79, more particularly described as follows: Those lands located in the S1/2 S1/2 of Block 514, within Section 16 and 21 ofT.13N., R.13E.; Umiat Meridian, Alaska, (being those lands lying easterly of line 3-4 on Block 514), a portion of the state area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, and those lands in S1/2 S1/2 of Block 515, being a portion of the State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lands within Block 558 located in Section 21, T.13N., R.13E.; Umiat Meridian, Alaska, (being the portion easterly of line 1-2 and northerly of line 2-3 block 558), listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, and those lands in Block 559 lying northerly of the south boundary of Sections 21, 22, 23, and 24, T.13N., R.13E.; Umiat Meridian, Alaska, (being the northerly portion of Block 559), listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79. ADL 312809 Consists of Tract C30-57 (BF -57), a portion of Block 516 and 560 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79, more particularly described as follows: Those lands located in Block 516 within the offshore three-mile arc lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, containing 227.02 hectares, and those lands in Block 560 located within Section 24, T.13N., R.13E., Umiat Meridian, Alaska, and those lands in Block 560 located within Sections 19, 20, 29 and 30 ofT13N, R14E, Umiat Meridian, Alaska, within the offshore three-mile arc lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79. ADL 355001 That portion of Blocks 514 and 558 as shown on the "Leasing and Nomination Map" for the federal/state Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79, more particularly described as follows: Those lands in Block 514 lying located within Sections 17, 18, and 20 ofT.13N., R.13E., Umiat Meridian, Alaska, and those lands located in Block 558 within Section 20, T.13N., R.13E., Umiat Meridian, Alaska. Area Injection Order Nc>. ') October 9,2001 ,) Page 8 FEDERAL LEASES Lease Number OCS-Y-1645 OCS-Y-0179 OCS-Y-0181 Description All F ederallands All F ederallands All F ederallands The affected area is more particularly described as follows: OCS-Y-1645 That portion of Block 6510, OCS Official Protraction Diagram NR06-03, Beechey Point, approved February 01, 1996, shown as Federal 8(g) Area C on OCS Composite Block Diagram dated April 24, 1996. OCS- Y -0179 That portion of Block 470 lying east of the line marking the western boundary of parcel "1" and between two lines bisecting Block 470, identified as parcel "1", containing approximately 94.30 hectares, and parcel "2", containing approximately 15.27 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975; and that area lying between the two lines bisecting Block 471, containing approximately 611.95 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975; and that area lying northeasterly of the line bisecting Block 515, containing approximately 189.83 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975. OCS-Y-0181 That area lying northeasterly of the line bisecting Block 516, containing approximately 2076.98 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975; and that area lying northeasterly of the line bisecting Block 560, located in the northeast corner of Block 560, containing approximately 44.65 hectares, as shown on the Supplemental Official OCS Block Diagram, revised and dated 12/9/79 based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975. Rule 1: Authorized Strata for Enhanced Recovery Iniection Enriched miscible gas and lean gas may be injected for the purposes of pressure maintenance and enhanced recovery into strata in the Sag River, Shublik and Ivishak Area Injection Order Nc October 9,2001 ) ) Page 9 Formations that correlate with, and are common to, the interval in the Seal A-Ol well between the measured depths of 12,418 and 13,044 feet MD. Rule 2: Fluid Iniection Wells The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 3: Well Packer Placement Tubing and isolation packers must be run in all wells. Well design will place the packer within 200 feet of both targeted injection zones (Sag River and Ivishak Formations) in accordance with 20 AAC 25.412(b). As such, it is recognized that this packer placement may result in a packer to perforation distance greater than 200 feet MD, however, the future option of Sag River Formation perforations is maintained while not compromising zonal isolation given the depth and thickness of the Kingak Formation, the overlying confining interval. Rule 4: Monitorine: the Tubine:-Casine: Annulus Pressure Variations The tubing-casing annulus pressure of each injection well must be checked at least weekly to confirm continued mechanical integrity of the well. Rule 5: Demonstration of Tubine:-Casine: Annulus Mechanical Intee:rity A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. Rule 6: Well Intee:rity Failure Whenever injection rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must immediately shut in and secure the well, notify the Commission on the frrst working day following the observation, and submit a plan of corrective action on Form 10-403 for Commission approval. Area Injection Order Nt., October 9,2001 ) ) Page 10 Rule 7: Notification of Improper Class II In.iection The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 8: Other Conditions a. It is a condition of this authorization that the operator comply with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 9: Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated October 9, 2001. ~~CIU~" O"'J'~')f:è\, ~f J!. ~! 1: l:... 4 l't"', ~" '''''-'''T''':-' ~·l)·~\ ..III ~, . ~~"" ~.' .",\~. t", ..¡~ .ct 1\ r '1þ~ .-:' ,I- ~~ : '\,Þ '('~ \ \.' ¡ I "~, ,_;;: . '\. ~J! "i.' ,~. ~ ·'À \~it ~I '\.. '~'i'·· ¡ /........,.. I~. <. ,;~ '.:.\. ... ,,;t~ ...,' ......,,1, '\!-" \\ , '-. H~.··"~ .,<- "l, ~ r ~~~,t\t~1\1ji,i~)~i;;:' i í· L':~ ,:. .~~:.,. .. ~..,' J lì ~~ 00 .~ I;; ¡~, !{\ ,::}'. :;;:::; ..';ytf '-...'"þ'.. . t \\ .,···.~··'I' \'¡""::"..\," j 4':r.!> iï ..;.u:..vi,I)~~":~,~l:r(~ :~~i':,~;;.:"",,:, .it þ"\~' /f ~~.... '.~"ì"':'f:¡-'.".."'..."';.'.".~'.'~' ..... '1. .,. ..\." i! ~3~@¿~;:~'~;fJ:~~1~~~~§~~/' ,<1 P¡,.;.;; .', r;('?:IV'..:.,i >""'. .:: ':. .!:;~ ." ~"':. ::;: ,.," ~.~. ommlsslon D 'el T. Seamount, Jr, ommissioner Alaska Oil and Gas Conservation Commission 'C~ /11\./ ~Y.2Q1r Julie M. Heusser, 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 lO-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 non-action 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). PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SO BLDG 1050 CONNECTICUT A V NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 2121 NORTH BA YSHORE DR #616 MIAMI, FL 33137 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN,IL 61820 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 ) NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GA THERSBURG, MD 20898 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 ) OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LIBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 IOGCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SO, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MURPHY EXPLORATION & PRODUCTION CO., BOB SAWYER 550 WESTLAKE PARK BLVD STE 1000 HOUSTON, TX 77079 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 WORLD Oil, DONNA WilLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 ') OIL & GAS JOURNAL, BOB WI LLlAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 MARK ALEXANDER 7502 ALCOMIT A HOUSTON, TX 77083 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 TEXACO INC, R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC POBOX 338 AUSTIN, TX 78767 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 C & R INDUSTRIES, INC." KURT SAL TSGA VER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 ) PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXON MOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 WATTY STRICKLAND 2803 SANCTUARY CV KA TY, TX 77450-8510 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE,VVA 98101 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 ) RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151ST #4 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 ) JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE,ID 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN V ACTOR POBOX 683 PORTLAND, OR 97207 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DNR, DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OIL & GAS WILLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR AND ENG SERVICE, MIKE TORPY 2000 W. INT'LAIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 ANADRI LL-SCH LU MBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 ) ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 DEPT OF REVENUE, OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 UOA/ ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 ) GAFO,GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 US BLM AK DIST OFC, GEOLOGIST ARTHUR BANET 949 EAST 36TH AVE STE 308 ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 GORDONJ.SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 AL YESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 ) US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, JOANN GRUBER A TO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 ) US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 TESORO ALASKA COMPANY, PO BOX 196272 ANCHORAGE, AK 99519 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 RON DOLCHOK PO BOX 83 KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 ) HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 PENNY VADLA PO BOX 467 NINILCHIK, AK 99639 ) OPST AD & ASSOC, ERIKA OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 ENSTAR NATURAL GAS CO, PRESIDENT TONY 1220 POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, PETE 2SELEC2KY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ, AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 ) PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 VALDEZ PIONEER, POBOX 367 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG POBOX 416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 ') KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 COOK AND HAUGEBERG, JAMES DIERINGER, JR. 119 NORTH CUSHMAN, STE 300 FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 (à"Ù,-- í-;f II'~, ¡ r,Ñ:::JJ ,,'\ 'I Ij , ' L'I 'i ~ \ ~ I ' ~J (Ì) .J ~ LíL\ ,J 11 rm ~",..~..,....u' "7"'~ ,/ :fì I, ld/I fJ-Ù r-"~ l~~', lr"'L FRANK H. MURKOWSKI, GOVERNOR AlASKA. OIL AlO) GAS CONSERVATION COMMISSION 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 23.001 Mr. Steve Rossberg, Wells Manager BP Exploration (Alaska) Inc. 900 East Benson Blvd. P.O. Box 196612 Anchorage, AK 99519-6612 RE: NS-29 (PTD 201-041) Request for Administrative Approval Dear Mr. Rossberg: In accordance with Rule 9 of Area Injection Order 023.000, the Alaska Oil and Gas Con- servation Commission ("AOGCC" or "Commission") hereby grants BP Exploration (Alaska) Inc. ("BPXA")' s request for administrative approval to inject gas in the subject well. AOGCC finds that BPXA has elected to perform no corrective action at this time on NS- 29. The Commission further finds that, based upon reported results of BPXA's diagnos- tic procedures, NS-29 exhibits two competent barriers to release of well pressure. Ac- cordingly, the Commission believes that the well's condition does not compromise over- all well integrity so as to threaten the environment or human safety. This Administrative Approval to inject gas in NS-29 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rates daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures and injec- tion rates; 3. BPXA shall perform an annual MIT - IA to 1.2 times the maximum anticipated well pressure; 4. BPXA shall install and operate automatic well shut-in or pressure limit equipment on the well's tubing and IA; Mr. Steve Rossberg January 9, 2006 Page 2 of2 5. BPXA shall provide the Commission with details of the specific automatic well shut-in or pressure limit equipment selected before injecting gas in NS-29; 6. BPXA shall limit the well's IA pressure to 1500 psi; 7. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; and 8. after well shut in due to a change in the well's mechanical condition, AOGCC ap- proval shall be required to restart injection. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is consid- ered 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. aniel T. Seamount, Jr. Commissioner ç~~~ ~ COIrumssIOner f'-"'"" - , 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 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 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, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 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 Waldsm ith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ~IO 23.001 Northstar 29 Subject: AIO 23.001 Northstar 29 From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Mon, 09 Jan 2006 15:00:54 -0900 To: undisdlose~~recipients:; B,CC:,Ro, b, e,rt, E", '.",M.",'"in,',t,~ <rob" e,',rt,', _,",',m,'.' .,i,n,',tz..,@..,l,a.w,'. .,state...ak, ~u. S>. "..,..C. hr... istine,.... ., H.' .ansen.· <c.hansen@iogcc'.state.ok.us>,.·TerrieHubble <hubbletl@bp.com>,. Sondra Stewman <StewmaSD@BP;com>, Scott. & Cammy Ta;ylor<staylor@alaska.net> ,stanekj <stanekj@unocal.com>, ecolaw<esoI~"i@tl"p~tees~'Rrg>,trrnjrl-St~j~.l@aol.com>, jbridcl~e...<jbriddle@marathonoil.com>, shaneg.·.<sh~eg®ey~r~r~engas.cQn1?"' jdarlil1gtop-. ~jd~lington@forestoil.co111:>, nelson <knelson~p~tro\è.~11ln~\ys.com>, cbo~4r <~P9!qdy@u~ibe~li.'cQ~Tf>,¡MarkDalt011.. . .. .' ,. . <m(lf~.g~ltpn~p~~ipp.c.pml,~!lj~nB~H~P11f1~11X-<~haµ~oÐ.dpµnetly@çonQcophHlips~com>,· "Mark P. W o~ceste~.'.';<q}årk. p: worçester@cotl()c?phillips,.c0tIl~,.l3ob·..~Þ~þ@illlet~~eper.org>,wdv <~dv@dnr~~tate..~.l1s>, 'tjr~tjr®d11f .st~tr.ak.l1s~>,:bbritch.·Kbhritçh@alaska.net>, ..mjnelson <mjnelson@purvingertz.cqm<:,',Gµat:l~~ O'~onneH :-ScÞarl~s.<?'40nnell@vecQ.com>,"Randy L. .Skillern" <SkilleRL@Br'fQm~~"Deboral1,J..JQne~" <Jonesp6@BP.com¿>r"StevenR. Rq~s~e~g". .' <RossbeI{S®BP.co~>, Lpis.<19i~@il1letl<eeper;org>;, DanBr()sS<FRuacnews@kµac.org>, ·.Gordon Pospisil ,<]??spisG@BP;~om>, "Francis S. S()mmer" 1SommyrFS@BP.com>,NlikeLSchultz <Mikel.S~11~ltf@~~·c0n1?" ' ,"~Uç~... )\l~GIRyet:" '<GI~yerN)V(@~P. com¿', "I)¥yl. J~I<le~pill" <KleppipE@~f.p(itl}::>~·I'J:~rt fl... Platt': . <PI~tt'P@Bf..com>,...·'~Rosfµ1~~ ,M. '.J acpbsen" <J aCQbs~@~¡> .'c0l11~,?d?n1<~1 <:d~~nk~l@cfl.~rv.coP1>;mckay<mckay@gci.nyÞ>',. Barbara· F ·Fullmer <bar~.~a.f.f~11fl1yr@19~~o'ÇopÞinips.c~tp>~.ðocast~ff<bocastwf@bp.cOl1» ,.... C~arl~s.J~arker . <barker@u~g~.gpv~,' qoWg_ schultze <d9~g7sch-qJtze@xtoenergy.com:>,Hank Alford <hank..alf~rd~~x}(ppm()~q.çe,ni~,·..Mark. Kov~c.4yesno l.@gci.net>"..gspfoff <gspfoff@~uto~~pow~r '9om> , (Jregg Na~y <gregg.nady@shell.com>,Fr~d Steece <fred.stee~e@~tåte. sd. us>'. rcr()tty<rcr()tty@ch2m;ço~>, jejones <j ej ones@aurorapower.com>,dapa <dapa@alaska.net>,jroderick <jroderic~@gcLnet>, ~Yancy <eyancy@seal-tite.net>,"James M. Ruud" <j ames.fl1;ruud@conocop~iJlips;qorn::>, Brit, Lively <~apéilaskß.@ak.net>, j ah <j ah~dnr .state.ak.us>, buonoJ.· e <. b. U..· O..,n. Q,~,e,.,. ,..@..' ...Þ.,p... .'c0111. >,..' MarkH. an...., .ley«tµar. k_ h..an.· Ie, Y@.' .. .an,. .. adark. o',c. Qm. >, lor, en_... leman <loren_Ie111an(@gov .st,+te.ak. ~s>, J1.llie Hotlle<julie_houle@dpr.state.ak.us>,.JoOO.WKatz <jwkatz@sso.org>, SUZa11. J·Hìll <:suzan_hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, .Brady <brady@aoga.org>;· Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobi1.com>, marty <marty@rkindustria1.com>, ghammons <ghammons@ao1.com>, rmc1ean <rmc1ean@pobox.alaska.net>, mkm7200 <mkm7200@ao1.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, KaYnell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP .com>, Steve Lambe <lambes@unoca1.com>, jack newell <j ack.newell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, david roby <David.Roby@mms.gov>, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unoca1.com>, Todd Kratz <ToddKratz@chevron.com>, Gary I of2 1/9/2006 3:01PM ~IO 23.001 Northstar 29 Rogers <gary_rc?gers@revenut(.state.akus>,;ArthurCopoulç.s <Arthur _ Copoulos@dnr.state.ak.us>,· Ken <ken@secorp-inc.com>, Steve. Lambert <;s~lan1bert@unocaLcom>, Joe Nicks <riews@radiokenaLcom>, Jerry.. McCut~þe9n<susitnahydrdnow@yah09~com> ,<F,ml Todd <paulto@acsalaska.net>, Bill Walker <bill-wwa@)aknet>, Iris Matthews <Iris_ Matthews@legis.state.akus>, Paul Decker <paul_decker@dnr.state.ak.us>, Rob Dragnich <rob.g.dragnich@exxonmqbi1.com>,CynthiaB Mciver <bren _ mciver@admiIl.state.ak.us> ,······'1"""':::""""""""'" .., , " ",.,"""': " > . ..<, .,¡çontent- Type: ' application/pdf AIO 23.001'. pdf; .... :. '.:. . .......' ...... ..' . . .."......I.....~,~.~~.~~.~=~.~,~?~.l~.·~.:...,~.~~=~.;" , 2 of2 1/9/20063:01 PM 0 THE STATE °'ALASKA GOVERNOR SEAN PARNELL Mr. Doug Cismoski 0 Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.23.001 (Amended) Well Intervention Manager 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 Re: Request to change the Mechanical Integrity Test (MIT) anniversary date from June 8 to August 31 Request to change Condition 6 to allow OA pressure limit of 50 psi Northstar Unit NS-29 (PTD 2010410) Northstar Oil Pool Dear Mr. Cismoski: By letter dated May 5, 2014, BP Exploration (Alaska) Inc. (BPXA) requested approval to change the annual MIT date from June 8 to August 31 to align the testing with another well and seasonal work load constraints, and to set an OA pressure limit of 50 psi. The AOGCC GRANTS BPXA's requests in accordance with Rule 9 of AIO 23.000. Conditions 1 through 8 of AIO 23.001 is repealed and replaced by the following: AOGCC's approval to continue gas injection in NS-29 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus annually to 1.2 times the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 1500 psi and the OA operating pressure to as low as reasonably possible not to exceed 50 psi; 5. BPXA shall install, maintain and operate automatic alarms and well shut-in equipment linked to the well's outer annulus pressure and wellhead pressure. The actuation pressure for the outer annulus shall not exceed 50 psi, and the actuation pressure for the wellhead shall not exceed 5250 psi. Testing of the shut-in equipment (surface safety valve, shutdown valve, and mechanical or electrical pressure detection devices) shall be performed in conjunction with production well pilots and safety valves; AIO 23.001 (Amended) • May 16, 2014 Page 2 of 2 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date is August 31, 2014. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated May 16, 2014. 1 '1 '—,"1 0 Cathy . Fo ster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner F 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 maybe 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. Com In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, May 16, 201411:53 AM To: (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator, Alexander Bridge; Andrew Vandedack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose, Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey, Colleen Miller, Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy, David Goade; David House; David McCaleb; David Scott; David Steingreaber, David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt, Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Gary Schultz (gary.schultz@alaska.gov); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose, Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty, Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger, trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net, Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Woolf, Wendy C (DNR); William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA) (elaine Johnson@alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, To: Angela K (DOA); Turkington, Jeff A (DOA); Wallach , Chris D (DOA) Subject: AI023.001 Amended AI023.002 Amended (Northstar) Attachments: aio23-002 amended.pdf; aio23-001 amended.pdf Please see attached. Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. 0 • Mr. Doug Cismoski Well Intervention Manager BP Exploration (Alaska), Inc. Post Office Box 196612 Anchorage, AK 99519-6612 -(`2z:�-"%CS Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. Post Office Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Bernie Karl CIRI K&K Recycling Inc. Land Department Post Office Box 58055 Post Office Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 Richard Wagner Gordon Severson Post Office Box 60868 3201 Westmar Cir. Fairbanks, AK 99706 Anchorage, AK 99508-4336 Darwin Waldsmith James Gibbs Post Office Box 39309 Post Office Box 1597 Ninilchik, AK 99639 Soldotna, AK 99669 Jerry Hodgden Hodgden Oil Company 40818`h St. Golden, CO 80401-2433 North Slope Borough Planning Department Post Office Box 69 Barrow, AK 99723 Jack Hakkila Post Office Box 190083 Anchorage, AK 99519 2 ot"" THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 23.002 CANCELLATION Mr. Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 Re: Docket Number: AIO-19-003 Request to cancel Area Injection Order (AIO) 23.002 Northstar Unit NS -25 (PTD 2031660) Northstar Field Northstar Oil Pool Dear Mr. Rivard: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov By email dated February 6, 2019, Hilcorp Alaska, LLC (Hilcorp) requested cancellation of administrative approval (AA) Area Injection Order 23.002. In accordance with Rule 9 of Area Injection Order (AIO) 23.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request to cancel the AA. NS -25 developed a surface casing leak in May 2012 and on September 11, 2013 the AOGCC issued AIO 23.002 which was subsequently amended May 16, 2014. AOGCC determined that gas injection could safely continue if the then operator BP Exploration (Alaska) Inc and subsequently Hilcorp complied with the restrictive conditions set out in AA AIO 23.002. Hilcorp has converted the well from an injector to a producer in November 2018 under Sundry 318-400. Conditions of Sundry 318-400 included continued monthly reporting of daily well pressures and continuing the maintenance and operation of installed automatic alarms and well shut-in equipment with the inner annulus set at 1500 psi and the outer annulus set at 50 psi. AA AIO 23.002 is no longer necessary to the operation of NS -25 and is hereby CANCELLED. AIO 23.002 Cancellation February 8, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated February 8, 2019. Cathy/P. Foerster Daniel T. Seamount, Jr. Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE °fALASKA GOVERNOR MICHAEL I. DUNLEAVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 23.002 CANCELLATION Mr. Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 Re: Docket Number: AIO-19-003 Request to cancel Area Injection Order (AIO) 23.002 Northstar Unit NS -25 (PTD 2031660) Northstar Field Northstar Oil Pool Dear Mr. Rivard: 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 By email dated February 6, 2019, Hilcorp Alaska, LLC (Hilcorp) requested cancellation of administrative approval (AA) Area Injection Order 23.002. In accordance with Rule 9 of Area Injection Order (AIO) 23.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request to cancel the AA. NS -25 developed a surface casing leak in May 2012 and on September 11, 2013 the AOGCC issued AIO 23.002 which was subsequently amended May 16, 2014. AOGCC determined that gas injection could safely continue if the then operator BP Exploration (Alaska) Inc and subsequently Hilcorp complied with the restrictive conditions set out in AA AID 23.002. Hilcorp has converted the well from an injector to a producer in November 2018 under Sundry 318-400. Conditions of Sundry 318-400 included continued monthly reporting of daily well pressures and continuing the maintenance and operation of installed automatic alarms and well shut-in equipment with the inner annulus set at 1500 psi and the outer annulus set at 50 psi. AA AIO 23.002 is no longer necessary to the operation of NS -25 and is hereby CANCELLED. A10 23.002 Cancellation February 8, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated February 8, 2019. �nIL ty" //signature on file// //signature on file// s Cathy P. Foerster Daniel T. Seamount, Jr. Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 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 WIN X otoe • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage,Alaska 99501 Re: THE APPLICATION OF BP ) Area Infection Order No. 23.002 EXPLORATION (ALASKA) INC. ) for Administrative Approval allowing ) Northstar Unit well Northstar Unit NS-25 (PTD ) Northstar Field 2031660) to continue gas injection ) Northstar Oil Pool service with a known outer annulus x ) conductor pressure communication. ) September 11, 2013 By letter dated September 5, 2013, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to continue gas injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 023.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue gas injection in the subject well. BPXA discovered the surface casing leak on May 16, 2012 and the well was shut in. BPXA has now completed well diagnostics and confirmed a leak below the OA valve flange. The passing mechanical integrity test of the Inner Annulus (MITIA) on August 25, 2013 indicates that the well exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's approval to continue gas injection in NS-25 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus annually to 1.1 times the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 1500 psi and the OA operating pressure to as low as reasonably possible not to exceed 50 psi; 5. BPXA shall install, maintain and operate automatic alarms and well shut-in equipment linked to the well's outer annulus pressure and wellhead pressure. The actuation pressure for the outer annulus shall not exceed 50 psi, and the actuation pressure for the wellhead shall not exceed 5250 psi. Testing of the shut-in equipment (surface safety valve, shut- down valve, and mechanical or electrical pressure detection devices) shall be performed in conjunction with production well pilots and safety valves; 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and AIO 23.002 • • September 11,2013 Page 2 of 2 8. The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated September 10, 2013. �oltA,� . \ fi , , / Of 1 - 14.4 AfA„dd A`0 Cathy, Fo rster Daniel T. Seamount, Jr. Jo 611M IMF: 4;6 1 a.,\ Chaif, Commissioner Commissioner Commissioner IT JON:'.. 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. As provided in AS 31.05.080(b),"[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC 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. • • Singh, Angela K (DOA) From: Fisher, Samantha J (DOA) Sent: Wednesday, September 11,2013 1:37 PM To: Ballantine,Tab A(LAW); Bender, Makana K(DOA);Bettis, Patricia K(DOA);Brooks, Phoebe L(DOA);Colombie,Jody J (DOA);Crisp,John H (DOA); Davies,Stephen F(DOA); Ferguson,Victoria L(DOA); Fisher,Samantha J (DOA); Foerster,Catherine P (DOA); Grimaldi, Louis R(DOA); Hunt,Jennifer L(DOA);Johnson, Elaine M (DOA);Jones,Jeffery B (DOA); Laasch, Linda K(DOA); Mumm,Joseph (DOA sponsored); Noble, Robert C (DOA); Norman,John K(DOA);Okland, Howard D (DOA); Paladijczuk,Tracie L(DOA); Pasqua!, Maria (DOA); Regg,James B (DOA); Roby, David S(DOA); Scheve, Charles M (DOA);Schwartz, Guy L(DOA);Seamount, Dan T(DOA);Singh,Angela K(DOA); Turkington,Jeff A(DOA);Wallace,Chris D (DOA); (michael j.nelson @conocophillips.com);AKDCWelllntegrityCoordinator;Alexander Bridge;Andrew VanderJack;Anna Raff; Barbara F Fullmer;bbritch;bbohrer @ap.org; Bill Penrose; Bill Walker; Brian Havelock;caunderwood @marathonoiicom;Cliff Posey; Colleen Miller;Crandall, Krissell; D Lawrence; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David Goade; David House; David Scott; David Steingreaber; Davide Simeone;ddonkel @cfirr.com; Donna Ambruz; Dowdy,Alicia G (DNR); Dudley Platt; Elowe, Kristin; Francis S.Sommer; Frank Molli;Gary Laughlin;schultz, gary(DNR sponsored);ghammons;Gordon Pospisil;Gorney, David L.;Greg Duggin;Gregg Nady; Gregory Geddes;gspfoff;Jacki Rose;Jdarlington (jarlington @gmail.com);Jeanne McPherren;Jerry McCutcheon;Jim White;Jim Winegarner;Joe Lastufka; news @radiokenai.com; Burdick,John D(DNR);Easton,John R(DNR);John Evans;John Garing;Jon Goltz;Jones,Jeffrey L(GOV);Juanita Lovett;Judy Stanek; Houle,Julie(DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles;Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Luke Keller; Marc Kovak; Dalton, Mark(DOT sponsored); Mark Hanley(mark.hanley @anadarko.com); Mark P.Worcester, Kremer, Marguerite C(DNR); Michael Jacobs (michael.w Jacobs @p66.com); Mike Bill; mike @kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland;mjnelson; mkm7200; knelson @petroleumnews.com; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L(DNR); Paul Mazzolini; Pike, Kevin W(DNR); Pioneer; Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Vanish; Robert Brelsford; Robert Campbell; Ryan Tunseth;Sara Leverette;Scott Griffith;Shannon Donnelly; Sharmaine Copeland;Sharon Yarawsky;Shellenbaum, Diane P(DNR);Slemons,Jonne D(DNR);Smith, Kyle S(DNR); Sondra Stewman;Stephanie Klemmer;Moothart, Steve R(DNR);Steven R.Rossberg; Suzanne Gibson;sheffield @aoga.org;Tania Ramos;Ted Kramer; Davidson,Temple (DNR);Terence Dalton;Teresa Imm;Thor Cutler;Tim Mayers;Tina Grovier,Todd Durkee; Tony Hopfinger;trmjrl;Vicki Irwin;Walter Featherly;yjrosen @ak.net;Aaron Gluzman; Aaron Sorrell;Amanda Dial; Bruce Williams; Bruno,Jeff I (DNR);Casey Sullivan; David Lenig; David Ross;Donna Vukich; Eric Lidji; Erik Opstad; Franger,James M (DNR);Gary Orr;Smith,Graham 0 (PCO);Greg Mattson; Heusser, Heather A(DNR);James Rodgers; Jason Bergerson;Jennifer Starck;jill.a.mcleod @conocophillips.com;Jim Magill;Joe Longo;Jolie Pollet; King, Kathleen J (DNR); Laney Vasquez; Lois Epstein; Louisiana Cutler; Marc Kuck;Steele, Marie C(DNR); Matt Gill; Matthew Armstrong; Michael Quick;Bettis, Patricia K(DOA); Perrin, Don J (DNR); Peter Contreras; Peterson, Shaun(DNR); Pexton, Scott R(DNR); Pollard, Susan R(LAW); Richard Garrard; Ryan Daniel;Sandra Lemke; Talib Syed;Terence Dalton;Tim Flynn;Wayne Wooster;Woolf,Wendy C(DNR);William Hutto;William Van Dyke Subject: AIO 23.002 Northstar Unit Attachments: aio23-002.pdf 1 • Samantha Fisher Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage,AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) 2 Easy Peel®Labels i • Bend along ine to Use Avery®Template 51600 Feed Paper �� expose Pop-up EdgeTM AVERY® 5160® 1 sV Douglas A.Cismoski,P.E. BPXA Wells Intervention Manager BP Exploration(Alaska),Inc. Post Office Box 196612 Anchorage,AK 99519-6612 Etiquettes faciles paler • Repliez a la hachure aft del www avery com Willcox le aabarit AVERY®5160® - Sens de reveler le rebord Pop-upTM ; 1-800-GO-AVERY Easy Peel®Labels ' • MEM Bend along line to 0 }�'{/� ®50TA°1 1 Use Avery®Template 5160® Feed Paper "'®'° expose Pop-up Edgena A David McCaleb Penny Vadla IHS Energy Group George Vaught Jr. 399 W.Riverview Ave. GEPS Post Office Box 13557 Soldotna,AK 99669-7714 5333 Westheimer,Ste.100 Denver CO 80201-3557 Houston.TX 77056 Jerry Hodgden Richard Neahring Mark Wedman NRG Associates Hodgden Oil Company Halliburton President 40818'St Post Office Box 1655 6900 Arctic Blvd. Golden,CO 80401-2433 Colorado Springs,CO 80901 Anchorage,AK 99502 gsP , Bernie Karl aft! K&K Recycling Inc. Land Department 795 E.9il�Tools Post Office Box 58055 Post Office Box 93330 795 E.94 Ct. Fairbanks,AK 99711 Anchorage,AK 99503 Anchorage,AK 99515 4295 North Slope Borough Richard Wagner Gordon Severson Planning Department Post Office Box 60868 3201 Westmar Ciir. Post Office Box 69 Fairbanks,AK 99706 Anchorage,AK 99508-4336 Barrow,AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs Post Office Box 190083 Post Office Box 39309 Post Office Box 1597 Anchorage,AK 99519 Ninilchik,AK 99639 Soldotna,AK 99669 .\(A .....A%-Q.C...L. 'Q,Q"k%1(•& (Z t! \3,2_=a��j Cak- A tiquettes faciles paler ; Sens Benitez a la hachure aft de; aVery ....e.e__._I__.�`—..S&asnrm, coon* 1 rL.rnle►9e re9.wrAaww...4 9 1 9..4M1_rA_®ifCAV t 0 THE STATE °fALASKA GOVERNOR SEAN PARNELL • Alaska k Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.23.002 (Amended) Mr. Doug Cismoski Well Intervention Manager 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 Re: Request to change the Mechanical Integrity Test (MIT) anniversary date from October 19 to August 31 Northstar Unit NS-25 (PTD 2031660) Northstar Oil Pool Dear Mr. Cismoski: By letter dated May 5, 20t4, BP Exploration (Alaska) Inc. (BPXA) requested approval to change the annual MIT date from October 19 to August 31 to align the testing with another well and seasonal work load constraints. The AOGCC GRANTS BPXA's request in accordance with Rule 9 of AIO 23.000. Condition 8 of AIO 23.002 is repealed and replaced by the following: 8. The MIT anniversary date is August 31, 2014. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. AIO 23.002 (Amended) 0 May 16, 2014 Page 2 of 2 DONE at Anchorage, Alaska and dated May 16, 2014. S��P., Cp� Cathy P. Foer4er 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 maybe 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. Com 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. E Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, May 16, 2014 11:53 AM To: (michael j.nelson@conocophillips.com); AKDCWellIntegrityCoordinator, Alexander Bridge; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey, Colleen Miller, Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Gary Schultz (gary.schultz@alaska.gov); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz, Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty, Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer, Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net, Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jilt.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen 1 (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Woolf, Wendy C (DNR); William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA) (elaine Johnson@alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, To: Angela K (DOA); Turkin9 ton, Jeff A (DOA); Wallac•Chris D (DOA) Subject: AI023.001 Amended AI023.002 Amended (Northstar) Attachments: aio23-002 amended.pdf, aio23-001 amended.pdf Please see attached. Sa.mant`ia Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. • Mr. Doug Cismoski Well Intervention Manager BP Exploration (Alaska), Inc. Post Office Box 196612 Anchorage, AK 99519-6612 • Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. Post Office Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Bernie Karl CIRI K&K Recycling Inc. Land Department Post Office Box 58055 Post Office Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 Richard Wagner Gordon Severson Post Office Box 60868 3201 Westmar Cir. Fairbanks, AK 99706 Anchorage, AK 99508-4336 Darwin Waldsmith James Gibbs Post Office Box 39309 Post Office Box 1597 Ninilchik, AK 99639 Soldotna, AK 99669 Jerry Hodgden Hodgden Oil Company 40818t6 St. Golden, CO 80401-2433 North Slope Borough Planning Department Post Office Box 69 Barrow, AK 99723 Jack Hakkila Post Office Box 190083 Anchorage, AK 99519 THE STATE °'ALASKA GOVERNOR BILL WALKER Mr. Wyatt Rivard Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.23.003 Well Integrity Engineer Hilcorp Alaska, LLC. P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: AIO-16-017 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well Northstar Unit NS-28 (PTD 2050160) to continue gas injection service with a known inner annulus repressurization. Northstar Unit (NSU) NS-28 (PTD 2050160) Northstar Field Northstar Oil Pool Dear Mr. Rivard: By letter dated April 21, 2016, Hilcorp Alaska, LLC. (Hilcorp) requested administrative approval to continue gas injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 23.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to continue gas injection in the subject well. Hilcorp reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. Hilcorp completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on January 27, 2016 which indicates that NS-28 exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of approximately 15 psi/day and AOGCC finds that Hilcorp is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 23.003 April 28, 2016 Page 2 of 2 AOGCC's approval to continue gas injection in NS-28 is conditioned upon the following: I . Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a mechanical integrity test of the inner annulus (MITIA) annually to 3500 psi; 4. Hilcorp shall limit the well's IA operating pressure to 2000 psi; 5. Hilcorp shall install, maintain and operate automatic alarms and well shut-in equipment linked to the well's inner annulus pressure and wellhead pressure. The actuation pressure for the inner annulus shall not exceed 2000 psi, and the actuation pressure for the wellhead shall not exceed 5250 psi. Testing of the shut-in equipment (surface safety W 7 valve, shutdown valve, and mechanical or electrical pressure detection devices) shall be performed in conjunction with production well pilots and safety valves; Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and The MIT anniversary date is January 27, 2016. xooe_ � DONE at Anchorage, Alaska and dated April 28, 2016. J P; ,,V , Cathy t. Foerster QDa T. ount, Jr. Chair, Commissioner Commissioner .TION 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 Sled within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, April 28, 201612:24 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWeIIIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; 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 Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; 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; Mealear Tauch; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); 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; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff 1 (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; 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; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard 1 (LAW); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster, William Van Dyke Subject: aio 23.003 Attachments: aio23.003.pdf Please see attached. Jody J. Colombie AOGCC Specia(Assistant Ataska Oi(andGas Conservation Commission 333 West 7" Avenue .anchorage, A(aska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 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 Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. 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 Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Wyatt Rivard Richard Wagner Darwin Waldsmith Well Integrity Engineer P.O. Box 60868 P.O. Box 39309 Hilcorp Alaska, LLC Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 244027 Anchorage, AK 99524-4027 0�z- "��CL Angela K. Singh TME STATE °ALASKA GOVERNOR MICHAEL 1. DUNLEAVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 23.004 Mr. David Gorm Operations Engineer Hilcorp Alaska, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 Re: Docket Number: AIO-20-008 Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogc c.o lasko.gov Request for administrative approval to allow well Northstar Unit NS -17 (PTD 2021690) to continue gas injection service with a known inner annulus repressurization. Northstar Unit (NSU) NS -17 (PTD 2021690) Northstar Field Northstar Oil Pool Dear Mr. Gorm: By email dated March 30, 2020, Hilcorp Alaska, LLC. (Hilcorp) requested administrative approval to continue gas injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 23.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to continue gas injection in the subject well. Hilcorp reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. Hilcorp completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 8, 2020 which indicates that NS -17 exhibits at least two competent barriers to the release of well pressure. The well has a fluctuating IA build up rate of approximately 180 psi/day and AOGCC finds that Hilcorp is able to manage the IA pressure with periodic pressure bleeds every two week period. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 23.004 April 2, 2020 Page 2 of 2 AOGCC's approval to continue gas injection in NS -17 is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a mechanical integrity test of the inner annulus (MIT1A) annually to 2500 psi; 4. Hilcorp shall limit the well's IA operating pressure to 2000 psi; 5. Hilcorp shall install, maintain and operate automatic alarms and well shut-in equipment linked to the well's inner annulus pressure and wellhead pressure. The actuation pressure for the inner annulus shall not exceed 2000 psi, and the actuation pressure for the wellhead shall not exceed 5250 psi. Testing of the shut-in equipment (surface safety valve, shutdown valve, and mechanical or electrical pressure detection devices) shall be performed in conjunction with production well pilots and safety valves; 6. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date is March 8, 2020. DONE at Anchorage, Alaska and dated April 2, 2020. Jeremy M. Price Jeremy M. Price Chair, Commissioner Daniel T. ° "Iry$I n hyWn1l TSeunoun4Jr. Seamount, Jr. xoua.azossz¢e Daniel T. Seamount, Jr. Commissioner JemieL ft »aW .L Chmielcw ki o,,.:�ommanu.arua Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after mitten 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 oftime above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 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 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 AREA INJECTION ORDER NO. 23.005 December 1, 2021 Mr. Torin Roschinger, NSI Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-21-029 Request for Administrative Approval to Area Injection Order 23, Gas Injection Northstar Unit NS-18 (PTD 2021410), Kuparuk Oil Pool Dear Mr. Roschinger: By letter received November 17, 2021, Hilcorp Alaska, LLC (Hilcorp) requested administrative approval to continue gas injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue gas injection in the subject well. Hilcorp reported a potential TxIA pressure communication to AOGCC based on a review of long-term pressure trends on October 20, 2021. Hilcorp had previously performed a passing state-witnessed mechanical integrity test (MIT) of the inner annulus to 2,429 psi on February 7, 2019. On November 12, 2021, Hilcorp performed a passing Positive Pressure Packoff Test – Tubing (PPPOT-T) to 5,300 psi. As a condition of this approval, Hilcorp is required to complete a MIT of the inner annulus to 3,500 psi once gas injection has stabilized. A passing MIT will indicate that NS-18 exhibits at least two competent barriers to the release of well pressure. AOGCC believes Hilcorp can safely manage the TxIA pressure communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue gas injection in NS-18 is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; AIO 23.005 December 1, 2021 Page 2 of 2 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a MIT of the inner annulus annually to a minimum of 3,500 psi; 4. Hilcorp shall limit the well’s inner annulus operating pressure to 2,000 psi and the outer annulus to 1,000 psi; 5. Hilcorp shall install, maintain, and operate automatic alarms and well shut-in equipment linked to the well’s inner annulus pressure and wellhead pressure. Actuation pressure for the IA not to exceed 2,000 psi. Actuation pressure for the wellhead not to exceed 5,250 psi. Testing of shut-in equipment shall be performed in conjunction with production well pilots and safety valves; 6. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated December 1, 2021. Daniel T. Seamount, Jr. Jessie L. Chmielowski 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. Dan Seamount Digitally signed by Dan Seamount Date: 2021.11.30 16:08:26 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.12.01 07:26:30 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Area Injection Order No. 23.005 (Hilcorp, Northstar Unit) Date:Wednesday, December 1, 2021 8:06:19 AM Attachments:AIO 23.005.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Area Injection Order 23.005, granting Hilcorp Alaska, LLC’s request for administrative approval to continue gas injection operations into the Northstar well. 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 12/1/21 gs INDEXES 17 From:Salazar, Grace (OGC) To:Torin.Roschinger@hilcorp.com; dhorner@hilcorp.com Cc:Wallace, Chris D (OGC) Subject:RE: Northstar well NS-18 (PTD# 202-141) Request for Administrative Approval Date:Wednesday, December 1, 2021 7:56:00 AM Attachments:AIO 23.005.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Area Injection Order 23.005, granting Hilcorp Alaska, LLC’s request for administrative approval to continue gas injection operations into the Northstar well. If you have any questions, please do not hesitate to contact Mr. Chris Wallace, Senior Petroleum Engineer, at (907) 793-1250 or via email at chris.wallace@alaska.gov. 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/ From: Darci Horner - (C) <dhorner@hilcorp.com> Sent: Wednesday, November 17, 2021 11:32 AM To: AOGCC Permitting (CED sponsored) Cc: Oliver Sternicki; Joleen Oshiro; Torin Roschinger Subject: Northstar well NS-18 (PTD# 202-141) Request for Administrative Approval Hello, Please find the attached Request for Administrative Approval to continue Gas Injection Operations for Northstar well NS-18 (PTD# 202-141). If you have any questions, please contact Oliver Sternicki (907) 564-4891. Thanks, Darci Horner �r� Hilcorp Alaska, LLC Torin Roschinger, NSI Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 11/15/2021 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Northstar Unit NS-18 (PTD# 202141) Request for Administrative Approval to continue Gas Injection Operations Dear Mr. Price, Hilcorp Alaska, LLC (HAK) requests administrative approval for continued gas injection into Northstar well NS-18 with slow tubing by inner annulus (IA) communication. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. NS-18 was flagged as having slow TxIA communication upon review of long-term pressure trends on 10/20/2021. AOGCC notification was made at that time. The slow nature of the IA repressurization and a passing online AOGCC witnessed MIT-IA to 2429 psi on 02/07/2019 indicates the tubing, packer and production casing are competent. HAK plans to conduct a MIT- IA to 3500 psi as part of this administrative approval to verify production casing integrity and set the anniversary date for subsequent annual tests. Pending a passing MIT-IA, two barriers will have been established providing evidence that the well can be safely operated. No repairs are planned at this time. In summary, HAK believes Northstar well NS-18 is safe to operate as stated above and requests approval for continued gas injection operations. If you have any questions, please call me at 406-570-9630 or Oliver Sternicki at 907-564-4891. Sincerely, Torin Roschinger NSI Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic By Grace Salazar at 1:36 pm, Nov 17, 2021 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2021.11.17 10:39:36 -09'00' Torin Roschinger (4662) Northstar Well NS-18 Technical Justification for Administrative Approval Request 11/15/2021 Well History and Status NS-18 was originally converted from a producer to a gas injector in March 2019 under sundry #318-412. A passing AOGCC witnessed pre-injection MIT-IA to 2253 psi was conducted on 01/22/2019. A passing AOGCC witnessed post-injection MIT-IA to 2429 psi was conducted on 02/07/2019. On 03/08/2019 the tree successfully passed a test to 6500 psi, but the tubing hanger test void failed testing. These testing results indicated that the tubing hanger secondary seals had integrity, but there was a slow leak in some other tubing hanger component below the secondary seals. This did not impact the integrity of the IA as the secondary seals provided a barrier between the tubing and IA. Review of long-term pressure trends of NS-18 on 10/20/2021 showed slow TxIA repressurization and was reported to the AOGCC. On 11/12/2021 the tubing hanger test void passed to 5300 psi. Current gas injection pressure in NS-18 is ~4760 psi. HAK does not support annual pressure testing of the production casing on NS-18 to max injection pressure as the frequent high pressure cycling of the well components present the risk of inducing premature failure of the well barriers we are relying upon. For assurance that the well barriers remain competent we propose an annual test cycle with an online MIT-IA to 3500 psi. To account for this lower test pressure, we also propose installation of alarms and automated actuation tied to the SSV on NS-18 such that the well would be shut-in if IA pressure exceeded 2000 psi or wellhead pressure exceeded 5250 psi. Pending approval and successful completion of our proposed risk mitigation measures HAK has determined that well NS-18 would be safe to operate and requests an AA for continued gas injection. Recent Well Events: 11/12/2021 PPPOT-T passed to 5300 psi 10/20/2021 IA repressurization noted and reported to the AOGCC 03/08/2019 PPPOT-T failed to 6500 psi 02/07/2019 Post-injection AOGCC witnessed MIT-IA to 2429 psi 01/22/2019 Pre-injection AOGCC witnessed MIT-IA to 2253 psi 03/01/2019 Converted from Producer to GI Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. Pending a passing pressure test of the IA to 3500 psi, the primary and secondary barriers would be considered competent. No further diagnostics/ repair attempts are proposed at this time due to the extremely slow nature of the TxIA communication. Pressure on the inner annulus will be maintained below MOASP of 2000 psi when the well is on-line with periodic bleeds of the IA. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. Perform an annual MIT-IA to 3500 psi. 4. IA MOASP= 2000 psi, OA MOASP= 1000 psi 5. Install, maintain and operate automatic alarms and well shut-in equipment linked to the wells inner annulus pressure and wellhead pressure. Actuation pressure for the IA not to exceed 2000 psi. Actuation pressure for the wellhead not to exceed 5250 psi. Testing of shut-in equipment shall be performed in conjunction with production well pilots and safety valves. 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 7. MIT-IA anniversary date based on passing MIT-IA to 3500psi. TIO/ Injection Plots Wellbore Schematic Post Office Box 244027 Anchorage, AK 99524-4027 11ii.rp .A64.. 1.1.1: 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8301 March 30, 2020 Commissioner Jeremy Price Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Northstar Well NS -17 (PTD # 2021690) Request For Administrative Approval to AID 23: Continued Gas Injection Operations Dear Commissioner Price, Hilcorp Alaska, LLC (HAK) requests approval for continued gas injection into Northstar well NS -17. NS -17 exhibits slow inner annulus pressurization while injecting gas that is manageable by bleeds. Passing diagnostic mechanical integrity test on the inner annulus conducted on 3/08/2020 indicate the tubing and production casing are competent. Based upon sound engineering practice, two barriers have been established and the well can be safely operated. Therefore, no repairs are planned at this time. In summary, HAK believes Northstar well NS -17 is safe to operate as stated above and requests approval for continued gas injection operations. If you have any additional questions concerning this request, please contact me at 777- 8333 or by email at dgorm@hilcorp.com. Sincerely, `b✓ David Gorm Operations Engineer Hilcorp Alaska, LLC Pzec 12 Attachments: Technical Justification TIO Plot Wellbore Schematic CC Chris Wallace Guy Schwartz James Regg P n e e 13 Northstar Well NS -17 Technical Justification for Administrative Approval Request March 30, 2020 Well History and Status NS -17's conversion from an Ivishak gas injection well to a Kuparuk gas injection well began in September 2019 with gas injection starting in October 2019. The well was placed on injection on 10/22/19 but demonstrated TxIA pressure communication of 1000 psi/day while online and 500 psi/day while shut-in. A leak detect log found the leak in the bottom connection of a 7"x5-1/2" crossover ^'6' below the tubing hanger. To restore integrity in the well, a tubing patch was installed across the leak. A nipple reducer was installed in the lower nipple profile at 13,247'. The upper 5-1/2" nipple at 1,183' was found to be damaged and a nipple reducer would not seal in the profile. A 5- 1/2" permanent packer with a 3-1/2" profile was set at 1,143' for a profile to hold the injection valve. The TBG patch was installed using a 5-1/2" permanent packer set at 48' and a seal assembly tied back to the tubing hanger back pressure profile. The well was placed back on gas injection on 2/25/20 after the TBG patch installation, IA pressurization appeared to have stopped. During monitoring, annulus pressure varied in conjunction with injection temperatures but overall a very slow IA pressurization trend was observed. Pressurization over the monitoring period is manageable with bleeds occurring roughly every 2 weeks. Well Value as a Gas Injector NS -17 is a necessary gas injector into the Kuparuk reservoir in the Northstar Unit. To improve the voidage replacement in the Kuparuk formation, additional produced gas needs to be reinjected into the Kuparuk. The gas injected into this reservoir decreases the decline of the reservoir pressure and aids in increased ultimate recovery of reserves. Recent Well Events: 4/10/19: Witness MIT -IA passed 2,900 psi. 8/02/19: Rig on well Pull 7" TBG 9/23/19: Rig on well, ran 5-1/2" Completion 9/28/19: MIT -T 3,600 psi w/fluid pass 10/20/19: Perforate Kuparuk 10/22/19: Initiate Gas Injection, Identify TxIA pressure 11/8/19: Leak Detect log confirmed leak at 7"x5-1/2" crossover 6' below the hanger 1/21/20: Set Nipple Reducer at 13,208' MD, identified damaged profile at 1,183' 2/15/20: Set 5-1/2" permanent packer at 1,143 MD 2/23/20: Set TBG patch, Pressure up TBG to 4,800 psi, IA bled to 37 psi, passed Ptiec 14 2/24/20: Pre -MIT - IA 2,700 psi, Pass 2/25/20: Initiate gas injection 3/8/20: Witnessed MIT—IA 2,700 psi, Pass 3/9/20: Well on gas injection for 28 day monitoring IA pressure build up rate. Barrier Evaluation The primary and secondary barrier systems consist of the tubing and production casing and associated hardware. Since the IA pressurization was first observed, a diagnostic MIT-IAs passed to ^2500 psi, demonstrating competent barrier systems. Proposed Operating and Monitoring Plan 1) Record wellhead pressures and injection rate daily. 2) Submit a monthly report of well pressures and injection rates to the AOGCC. Flag annular bleeds. 3) IA pressure is bled prior to reaching 2000 psi. A software alarm is set at 1750 psi to provide additional warning. 4) Perform a 2 -year, AOGCC witnessed, MIT -IA to 2,500 psi. 5) The well will be shut-in and the AOGCC notified if there is a change in the well's mechanical condition. 15 NS -17 TIO Plot Bleeds: Date Annulus Start Press End Press Comments 2/25/2020 IA 1600 400 Bled IA numerous times due to thermal expansion of diesel pumped down IA to perform MIT IA. 3/02/2020 IA 1750 751 Bled IA down from 1750-751psi. At 850psi swapped to all diesel. 9.5 gallons bled to tank. 3/09/2020 IA 2782 783 performed a MIT test onthe l/A 3/12/2020 IA 1830 753 Thermal expansion bleed, gas for the first 500 psi then all liquid after that 3/19/2020 IA 1894 751 The first 600psi was gas then it was all diesel after that. if Hilrwn LL1.. I'Ll to Blur.' 553711IFEkv.:4005510815.4) 10=14396' (MD)/TD=11314'(iW) PBFD. 1499D (M)) / PBTD. 11310ra W l Pci, 16 Northstae Unit Well. NS -17 Last Completed: 10/21/2019 TREE & WELLHEAD OPEN HOLE / CEMENT DETAIL T. I ABBWI TG.SBN -� 13.318" 5H6 v Pf 4', 4M sa Clam Wan 36 We I "Pitted I A88-VGI 1}Sjrfhoubw, 6 S 9.5/11' ]050x1 Ecoroli 66Usx'3'ine12-1/4"Nele 1,143' T 4-2/2' CASING DETAIL M2x[lass'G•ts83/2'Xale 1 1Ms15Ckm"G-in6'Xak 1103' Sim Type Wt/Crest C. ID Top Bim 6 13,217 W. Conaua 169 1LS61WA WA sunc"a 201' a 13160, 1}3 • Surkce N/1"80 oke 12.415 Sum`a. 3,837 0 13300' 4510" IMermeaine 535(1.481 BK4A 8535 Sarlan 15,6)6' 12 15,487 7" Maaptlion 29 LJO/HyEn151] Sam 15,eB8' 1),)46' 14 171496' 4412" Unc ]2.61 VAM Au 3958 1) 92' 18 16 17,540' 41/2'RN,C0e-ID=3437• TUBING DETAIL 1),553' 0.1/2"RN Nwple-aNNID.3360`II7,5$Y EIAO) 111 1],X1' Sl/Y TubN 17/13f:R/1FEBear 1 4892 SUXaw 33p36 M 17,583' 7' Tuse 32/1.95 VAM-lOP 6091 13,300' 15,433' 18119' 11,091' 41/2• Tmi 18. 3 VAM-TOP 3.610 LSp33' 17,565' 18,119' WELL INCLINATION DETAIL NOP! 1,3)5' Maa Xale .."des 06862' A%k ac Tep Ped -0On. @ 17,999' JEWELRY DETAIL 11,130' Na Output Item 1 403' BNS®I Sua(UPgr Pai& lzdau.n) imil.1 nxmall. 1 487 4 ;M MPecker w/3"ID L. Peed Ualaupnl 3 1,143' i]/9, Permanem PM w(3-1/2-x-p.oMe 00R 813• 4 1103' 43/8•SVW(10=1562•I(tlamaeea) 5 13,351 41@"B Nlpple ID9562') 6 13,217 45/8"e5112"WXigmmTM Perr,m�wM Paler 7 13,247' 61/8" B WOO. (K) 4567 w(}1./3' R[Iluwr pD. 2.813"1 a 13160, 5,112- M Nip h, INS.ID4ASS• 9 131317 6]/2'yuEG(m 4767') 0 13300' ]'Tulin Seco TopE000 U. 15,433' 7'x4 -V2 -MO 12 15,487 45(0'.7'lunc To Packer 13 15609' 45/8"+7"lune. He,. 14 171496' 4-1/2"Ph,pge-10=3431 15 1)51)' 1e0. "baker Premum Pacbr, 8).991• 16 17,540' 41/2'RN,C0e-ID=3437• 17 1),553' 0.1/2"RN Nwple-aNNID.3360`II7,5$Y EIAO) 111 1],X1' )•e63/4"Baker Zlm LTPaM )'s5"BakerNu NNNr 0 17561' 41/2' HES Self Aliflni Md... - Sum @1),565' M 17,583' S'a4112•[0 21 1)9)0 P.. seat,with TOC w 17939' RM PERFORATION DETAIL Santls Top(MD) Btm(MD) Top(I am (TVD) I IT I Data Status BUPA 35325' 15,345' 9,019, 9032' w 1}3AMO Ow 15397 V1427 9,066 9018' M 19 Open 15154 15,110' 1915' 9,927' "_%219 BUPC 15,1A' 35,19E 8,93r0.947 7O /39 Open 15196' 15 16' 8,947 4953' 20 ]0/2t 19 open 15,836 1;336' B,SS3' ILMS' m ]0(20/19 open 17,9W 18059, 11 2' 11091' 60 713:105 CIOMa MSWk 1go59, 18119' 11,091' 11,130 60 10/11/02 Cbse3 18,119' 339' 11,130' 11,262' 200 5/4/02 Clasea Relcerce SMR lewelr t en3/1 3 WELL INFO 14 Wallace, Chris D (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Wednesday, February 6, 2019 11:18 AM To: Wallace, Chris D (DOA); Darci Horner - (C) Cc: Taylor Wellman Subject: RE: [EXTERNAL] RE: January TIO report for HAK North Slope Monitored Well Chris, We did convert NS -25 for an extended production test with a surface casing leak for a period of up to one year under sundry 318-400. There was a possibility of initially seeing an unfavorable response as a producer and then requesting to convert the well back to injection. I can confirm now that the well will remain as a producer going forward and that if we should need to convert back to injection at some point in the future we will have addressed the surface casing leak by then and will not need an AA. Hilcorp requests to cancel AIO 23.002. The well will remain on our monthly TIO report as a condition of Sundry 318-400 until the surface casing leak is repaired. The admin approval field on NS -25's TIO report has been updated to the sundry number going forward. Thank You, Wyatt Rivard I Well Integrity Engineer I Hilcorp Alaska, LLC 0: (907) 777-8547 1 C: (509)670-80011 wrivard@hilcorp.com 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 From: Wallace, Chris D (DOA)[mailto:chris.wallace@alaska.gov] Sent: Wednesday, February 06, 2019 9:21 AM To: Darci Horner - (C) <dhorner@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: [EXTERNAL] RE: January TIO report for HAK North Slope Monitored Well Darcy, Wyatt, Thank you for the report. If NS -25 (PTD 2031660) was converted to a producer, AA AIO 23.002 for OAxOOA is no longer needed and Hilcorp should request a cancellation. Otherwise am I to assume the well could be brought back on injection at some point? Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7"' Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.¢ov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. From: Darci Horner - (C) <dhorner@hilcorp.com> Sent: Tuesday, February 5, 2019 3:57 PM To: Wallace, Chris D (DOA) <chris.wallace@alaska.gov>; Schwartz, Guy L (DOA) <guv.schwartz@alaskAgov>; Regg, James B (DOA) <jim.regg@alaska.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: January TIO report for HAK North Slope Monitored Well 0 Please see the attached January 2019 TIO Report for the Northstar, Milne Point & Endicott monitored wells operating under a Sundry or Admin Approval. Monthly TIO Wells Included (12): Endicott: Injection rates reduced on 12/30/18 for compressor repairs. END 1-05 (PTD 1861060) END 3-01 (PTD 1861900) END 3-35 (PTD 1870200) END 3-49A (PTD 1970570) END 5-01 (PTD 1801200) END 5-02 (PTD 1811180) Milne Point: MP E-03 (PTD 1890170) MP F-13 (PTD 1950270) MP F-92 (PTD 1981930) Shut in on 5/2/18 for rig workover on neighboring well. Northstar: Injection rates reduced 12/24-12/26/18 for separator piping repairs. NS -25 (PTD 2031660) Conversion to producer was completed on 10/31/18 NS -28 (PTD 2050160) NS -29 (PTD 2010410) Please call either myself or Wyatt Rivard (777-8547) with any questions. Regards, Darci Horner Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Office: (907) 777-8406 Cell: (907) 227-3036 Email: dhorner@hilcorp.com 13 Hilcorp Alaska. LLC April 21, 2016 Commissioner Cathy Foerster Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RECEIVED APR 2 12016 AOGCC Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone:907/777-8300 Fax:907/777-8301 Re: Northstar Well NS-28 (PTD # 2050160) Request For Administrative Approval to NO 23: Continued Gas Injection Operations Dear Commissioner Foerster, Hilcorp Alaska, LLC (HAK) requests approval for continued gas injection into Northstar well NS-28. NS-28 exhibits slow inner annulus pressurization while injecting gas that is manageable by bleeds. Passing diagnostic mechanical integrity tests on the inner annulus conducted on 1/27/16 and 9/26/15 indicate the tubing and production casing are competent. Based upon sound engineering practice, two barriers have been established and the well can be safely operated. Therefore, no repairs are planned at this time. In summary, HAK believes Northstar well NS-28 is safe to operate as stated above and requests approval for continued gas injection operations. If you have any additional questions concerning this request, please contact me at 777- 8547 or by email at wrivard@hilcorp.com. Sincerely, Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC Page 12 Attachments: Technical Justification TIO Plot Wellbore Schematic CC Chris Wallace Guy Schwartz James Regg Page 13 Northstar Well NS-28 Technical Justification for Administrative Approval Request April 14, 2016 Well History and Status NS-28's conversion from a production well to an injection well began in April 2015 with gas injection starting in May 2015. During semi-annual testing of SVS at Northstar in July 2015, the MCX injection valve for NS-28 failed to hold DP. Following the re -set of the MCX and carrier, IA pressurization was observed. The MCX was reset multiple times but slow IA pressurization could not be eliminated. An acoustic LDL was performed on 1/8/16 indicating a leak at the GLM at 4551'. The dummy GLV was found to be damaged and, once replaced, IA pressurization appeared to have stopped. Injection resumed for monitoring on 1/29/16. During monitoring, annulus pressure varied widely in conjunction with injection temperatures but overall a very slow IA pressurization trend was observed. Pressurization over the monitoring period was manageable with bleeds occurring roughly every 2-4 weeks. Well Value as a Gas Injector NS-28 is a necessary gas injector into the Ivishak reservoir in the Northstar Unit. The gas injected into this reservoir maintains reservoir pressure and aids in the ongoing FOR gas flood project. The structural location of the NS-28 well in the Ivishak reservoir, improves the displacement of oil from the pore spaces and therefore the ultimate recovery of the reservoir. Recent Well Events: 4/13/15: Passing IC hanger void test to 2750psi. 5/20/15: Well began gas injection following conversion and passing pre MIT -IA. 5/29/15: Passing AOGCC witnessed MIT -IA obtained to 3003 psi. 8/24/15: Sub surface injection valve replaced after failing during 180 day SVS testing. 9/4/15: IA pressurization identified, well SI. 9/14/15-9/22/15: Multiple attempts to change out MCX to regain control line integrity. IA pressurization reduced but not eliminated. 10/29/15: Well returned to injection for 28 day monitoring to obtain warm BUR. 1/8/16: Acoustic LDL performed indicating small leak at GLM at 4551' 1/24/16: Dummy GLV pulled and replaced and IA pressures holding flat. 1/27/16: Passing diagnostic MIT -IA to 2977 psi. 1/29/16: Well returned to injection for 28 day monitoring. Monitoring extended twice due to variations in IA corresponding to injection temp changes. Page 14 Barrier Evaluation The primary and secondary barrier systems consist of the tubing and production casing and associated hardware. Since the IA pressurization was first observed, two diagnostic MIT-IAs passed to —3000 psi, demonstrating competent barrier systems. *Note: Production casing is set on a slip style hanger with max test pressure of 3800 psi. The hanger is isolated from the inner annulus pressure by the packoff but it is not recommended to routinely test the inner annulus in excess of 3800 psi if it can be avoided. In the event that the pack off fails while IA is >3800 psi, hanger could be over pressured. Maximum recommended MIT test pressure is 3500 psi. The casing hanger void was tested on 4/13/15 to verify pack off integrity prior to conversion. Proposed Operating and Monitoring Plan 1) Record wellhead pressures and injection rate daily. 2) Submit a monthly report of well pressures and injection rates to the AOGCC. Flag annular bleeds. 3) IA pressure is bled prior to reaching 2000 psi. A software alarm is set at 1750 psi to provide additional warning. 4) Perform a 2-year, AOGCC witnessed, MIT -IA to 3,500 psi. 5) The well will be shut-in and the AOGCC notified if there is a change in the well's mechanical condition. Page 15 NS-28 180 Day TIO Plot NS-28 TIO Plot 5,000 60,000 4,500 -. y 50,000 4,0W r i 3,500 40,000 3,000 -. N i � ti 2,500 30,000 E a i 2,000 2.0,000 1,500 1,000 k 10,000 500 + r 0-IrTIM 0 u, � � io � � � � e � � � � � � � 0 o s o s o 0 0 0 0 o- o 0 0 0 0 0 0 0& o o s- o 0 0 0 0 0 0 0 0 0 0 0 N N N N \ N \ \ N \ N \ N \ N \ N N N N N N N \ N \ N N N N N N N N f� r-1 i7 lD N � e\i N O � O in ,--, lD �--� lD N —Tubing —IA —OA —Gas Inj Bleeds: Date Annulus Start Press End Press Comments 04/11/2016 OA 796 20 04/11/2016 IA 1752 458 02/26/2016 OA 539 4.8 Bled to flow line. Mostly diesel w/some gas. IA and 02/26/2016 IA 1753 124 01/31/2016 IA 736 15 01/30/2016 IA 779 140 01/08/2016 IA 936 39 01/03/2016 IA 1881 451 12/28/2015 IA 1894 878 12/17/2015 IA 1883 500 12/04/2015 IA 1754 113 11/20/2015 IA 1950 60 11/04/2015 IA 1870 94 OA trending up, 20 degF increase in injection temp over last 5 days. Bled to flow line. Mostly diesel w/some gas. IA and OA trending up, 20 degF increase in injection temp over last 5 days. IA bled after well brought online IA bled after well brought online Bled NS-28 IA to support slickline leak detect log. The bleed was periodically stopped and restarted due to change -out of shifts and crews; the well was bled over a 12hr period, when factoring these pauses. All gas Gas Liquid freeze protect Page 16 14 Li a11M!IrM. luA KBE - 55.67/ BFE=41Y M5L (CB 15.67') 2ir ' . u 5' Northstar Unit Well: N5-28 SCHEMATIC Last Completed: 5/9/2005 PTD: 205-016 CAS€ dG DETAIL Site Trae wt( G'aIe Cc, nI ID Top Btm ear Conductor is=j x-ss; rI;'. N/A Surface 200' 13-3/r Surface 68 j L-8J Ft=c. 12.415 Surface 3,590' 9-.5}8" Aroducrian 53.5 Et: c. 8.535 Surface 10,671' 7" Liaer 29 1 L-80 / H drd 521. 6.1M 10 513' 12 365' 4-1/r liner 12-6/13Crso/ 3.9S8 12,11W 14,15(Y TUBING DETAIL 4-llr I Tubnng 1 126/LW.W/ I 3.9ss I Surface 1 12,11W JEWELRY DETAIL No Depth ftern 1 1 OW 4-Vr TRM-0E SSW, JD= 3TSr: LOCKED OUT 4/22�b6, Co.rm', line Ported Open 2 45S1' GLM-M16IG Dum" wl RK Loch 3 10,504° 9-S/8' x 7" Baker ZiKP LTP, 1). 6-30" 4 10,SM 9-5/8" x 7" Baker Flex Lode tits Filargor, ID- 6.33" 5 12,0!96r 4-1/2'X flipp e,. ID=3.813 6 12,117 4-1/2" Fiber Optic Transducer, ID= 3-958 7 12147 7" x 4 '2" Eak:er'S-3 Packer IN 3.975" 8 12 65' 4- "X Ni - e IEk=3.813 9 12,176' 41/2'Xflrlipp-e IE=3.'25"(12,1%'ELM) 10 12,11W 7' x 5' Ba leer H PD LTP w/ 11-3/4' Tieback, ID- 4.430' 11 12jW 4-Vr Self A ignift Mule Shoe, ID= 39S8" 12 IZAW 7'x5'BalerFlex Lock Umm Haiew, ID=4.39" 13 IZ21V S' x 41,/2' XO, 0- 3-91" PERFORATION DETAIL 1 WELL INCLINATION DETAIL KOP @ 250' q t."a:�Hc!e =89 .113,55ff IJa. A: g a at Tep Perf 85 Deg 013,282' :PEN HOLE /CEMENT DETAIL A 1 !' 2' A 16 TD-14,150 (AtD) / TD- 11,170{TVDI PBTD-14,1D6' I WD) / PBTD - L1.IWDVD) _J Drier 542 sic PF'L', 472 sx Class "W in 16' Hole -5 c 645 sK Extended. 458 sx.Claw 'G' in 12-1 4" Hole 438 sx Class "G` n 8-1/2' Hole - 210 sx Class'a' in 6' Hole TREE & WELLHEAD Tr a CW S-18"' SW (upeated to 6-SW) We:!Ihead A=81340 13-Vr Mutibowi6-Simi GENERAL WELL INFO API.5"29-230n-MOD Completed - 4/15/2002 Add Perforations-10-23-20DS SSSVLock Out- 22 006 SAFETY NOTE Well requires a safety valve, 4-1/2" Chrome Tubing Liner status 12 • BP Exploration (Alaska) Inc. Doug Cismoski, Well Intervention Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 May 5th, 2014 Ms. Cathy Foerster, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 bp RE MAY 0 6 Z014 t�C C Subject: Northstar Unit NS25 (PTD #2031660) Request For Revision of NO Administrative Approval 23.002 Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests a revision to Administrative Approval 23.002 dated September 11, 2013 for Well NS25. BP would like to change the anniversary date from October 19th to August 31st. This would allow the required mechanical integrity testing to be aligned with NS29 (PTD #2010410) and seasonal workload constraints. A separate request has been made to change the anniversary date for gas injector NS29 to August 31st If you require any additional information, please contact me at 564-5637 or Jack Disbrow / Laurie Climer at 659-5102. Sincerely, Doug Cismoski Well Intervention Manager Attachments Wellbore Schematic TIO Plot 0 0 Injector NS25 (PTID # 2031660) TIO Plot April 21, 2014 Well: NS-25 0 Tbg IA OA OOA OOOA On 00 '4 U1514 0222,14 4 4�`Z!4 �,? 1a03,122 14 01'25 0405 � 0 Injection Plot Well NS-25 ml 3OXIC, 3� 2 Z% — —GI 2 J,,'kG —Othe, on 2 0 11 BP Exploration (Alaska) Inc. Doug Cismoski, Well Intervention Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 May 5th, 2014 Ms. Cathy Foerster, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 • by RECEIVE[ MAY 0 6 2014 AOGVC Subject: Northstar Unit NS29 (PTD #2010410) Application for Amendment of NO Administrative Approval 23.001 Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests a revision to Administrative Approval 23.001 dated 01/09/2006 for Well NS29. BP would like to change the anniversary date from June 08th to August 31st. This would allow the required mechanical integrity testing to be aligned with NS25 (PTD #2031660) and seasonal work load constraints. A separate request has been made to change the anniversary date for gas injector NS25 to August 31 st Additionally, BP requests that the outer annulus pressure limit be changed to 50 psi in order to provide consistency with NS25. An updated technical justification is attached. If you require any additional information, please contact me at 564-5637 or Jack Disbrow / Laurie Climer at 659-5102. Sincerely, Doug Cismoski Well Intervention Manager Attachments Revised Technical Justification for Administrative Relief Request Wellbore Schematic TIO Plot • • Northstar Unit NS-29 Revised Technical Justification for Administrative Relief Request April 25, 2014 Well History and Status Northstar Unit well NS29 (PTD 2010410) has a shallow surface casing leak demonstrated by outer annulus by conductor communication indicated by failing MIT- OA's with fluid and subsequently with Nitrogen, producing returns to surface. However a passing AOGCC witnessed MIT -IA to 6300 psi on June 8, 2013 demonstrates competent tubing / packer and production casing, in line with current AA requirements. Recent Well Events: > 06/08/2013: Set PRN Plug, AOGCC witnessed MIT -IA to 6300 psi passed > 06/09/2013: Pull PRN Plug from 12,945'MD Barrier and Hazard Evaluation The well has two competent well barrier systems to prevent the atmospheric release of injection gas and to safely operate the well. The primary barrier is the tubing/packer. In the event of a leak, the secondary well barrier system composed of the production casing will contain any pressure. These systems have been pressure tested to 1.2 times the maximum gas injection pressure to ensure competency. Barrier competency is monitored using wellhead pressure plots (TIO plot) and periodic pressure tests to 1.2 times the maximum anticipated injection pressure. Primary Well Barrier System: Tubing / packer competency is demonstrated by the passing MIT -IA to 6300 psi on June 08, 2013. Competency will be monitored by daily annulus pressure observations, by frequent review of a TIO plot to monitor pressure trends and by annual demonstration of tubing integrity. Secondary Well Barrier System: Production casing competency is demonstrated by the passing MIT -IA to 6300 psi on June 08, 2013. Competency will be monitored by daily annulus pressure observations, by frequent review of a TIO plot to monitor pressure trends and by annual demonstration of production casing integrity. Also, maximum allowable inner annulus surface pressure will be limited to 1500 psi. Thermal Overpressure of the OA: Maximum allowable OA pressure will remain at 50 psi due to the shallow production casing leak. The well is equipped with overpressure alarms. Any OA pressure above the pressure limit would trigger an alarm and the board operator would shut in the well. Injection fluid temperatures are warmer than the wellbore temperatures to the depth of the surface casing shoe. This results in the well cooling off when shut-in, preventing thermal overpressure. Mechanical Condition: The surface casing is not considered a component in the well barrier systems. The tubing/packer and production casing are the 2 competent well barrier systems and have been confirmed. The well will be shut-in at any indication of barrier competency loss. Automatic Shutdown: The maximum allowable injection pressure will be limited to 5250 psi. The pressure transmitter PI-0029AI installed on the well head will shut the SDV on the wellhead, isolating the well from the injection manifold piping. A soft alarm set point of 5100 psi will provide notification when the pressure is climbing. The average operating pressure of NS29's well head is approximately 4700 psi. Proposed Operating and Monitoring Plan 1. Maintain containment in the cellar. 2. Continue gas injection. 3. Record well head pressures and injection rates daily. 4. Submit a report monthly of well surface pressures and injection rates to the AOGCC. 5. Annually demonstrate the integrity of the tubing and production casing. 6. Stop injection and notify the AOGCC if there is any indication of a compromise of mechanical condition. 0 0 Injector NS29 (PTD # 2010410) TIO Plot April 21, 2014 Well: NS-29 4.000 1000 —f— IA —+— OA IWO OOA i OOOA 1000 On p125i4 ,.2D"14 kt U.. » 021514 fi2,2214 0 , 1.14 03,W14 131514 D32214 03=2914 0005,14 14t12,14 04,1914 Injection Plot Well: NS-29 4.10 • -cr�`� j/�•-� bp BP Exploration(Alaska)Inc. 00 Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager �� P.O. Box 196612 Anchorage,Alaska 99519-6612w0› (IPd September 5, 2013 Ms. Cathy Foerster, Chairperson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Northstar Unit well NS-25 (PTD 203-166) Request for Administrative Approval: Continue Gas Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue gas injection operations into well NS-25. The well has established outer annulus by conductor communication and has been shut in since May 2012. A mechanical integrity test of the inner annulus (MIT-IA)to 1.1 times the maximum anticipated gas injection pressure passed on August 25, 2013. This proves competency of the primary and secondary well barrier envelopes. The technical justification attached includes monitoring of well barrier envelope competency through well inspection and daily annulus pressure observations, by quarterly review of well pressure and operational trends and by proposed annual demonstration of casing integrity through a passing MIT-IA test. In addition revised IA and OA MOASP pressure limits, and OA freeze protect fluid mitigations will be applied. This request for approval is consistent with Area Injection Order 23: Rule 9, in that sound engineering and operating practices have established two competent barriers in addition to an operating and monitoring plan developed to ensure continued safe operations. These measures will ensure continued safe gas injection operations. If you require any additional information, please contact Ryan Daniel (BPXA Wells Integrity and Compliance Team Lead)at 564-5430. Sincerely, cry , -� _ Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager CC: Jim Regg, Chris Wallace Attachments Technical Justification for Administrative Relief Request TIO Plot Wellbore Schematic • Northstar Unit NS-25 • Technical Justification for Administrative Approval Request Well History and Recent Well Events The surface casing leak was discovered on May 16, 2012 after operations reported freeze protect fluids in the sealed cellar. At that time, the well was shut-in and on May 21, 2012 secured from the reservoir with a tubing tail plug. A MIT-IA was performed to 5000 psi to confirm the integrity of the tubing and production casing on May 22, 2012. A failed MIT-OA occurred on May 24, 2012 with diesel, and a subsequent leak depth determination was performed on July 5, 2013 with nitrogen which indicated the leak was approx 37" below the OA valve flange. A passing MIT-IA was performed to 5775 psi on August 25, 2013. The well is currently secured with a downhole plug in the RN nipple at 18627'. Well Barrier and Hazard Evaluation The well has two competent well barrier envelopes to prevent a loss of containment and allow safe well operations. The primary barrier is the tubing/packer. In the event of a leak, the secondary well barrier envelope comprised of the production casing is capable of containing well pressure. Primary Well Barrier Envelope Tubing / packer competency is demonstrated by a passing MIT-IA to 5775 psi on August 25, 2013. Competency is monitored by well inspection and daily annulus pressure observations, by quarterly review of well pressure and operational trends and by proposed annual demonstration of tubing integrity through a passing MIT-IA. Secondary Well Barrier Envelope Production casing competency is demonstrated by the passing MIT-IA to 5775 psi on August 25, 2013. Competency is monitored by well inspection and daily annulus pressure observations, by quarterly review of well pressure and operational trends and by proposed annual demonstration of casing integrity through a passing MIT-IA test. In addition, a revised IA maximum operating annular surface pressure limit of 1500 psi will be imposed. Thermal Overpressure of OA A revised OA maximum operating annular surface pressure limit of 50 psi will be imposed due to the shallow production casing leak. Any OA pressure reads above this limit will trigger a HiHi alarm and the well shut-in by the board operator. Injection fluid temperatures are warmer than ambient wellbore temperatures so shutting in the well decreases OA pressure. Periodic ejection of small quantities of freeze protect fluids from the OA leak point while operating will be mitigated. This is analogous to NS- 29 (PTD2010410) operating under AA 23.001. Ejected fluids will collect in the steel lined well cellar box, then pumped directly to a slope tank. Injection Operating limit and Automatic Shutdown The maximum expected injection pressure is limited to 5250 psi. The pressure transmitter PI-00025AI on the wellhead will shut the SDV, isolating the well from the injection manifold piping if the injection pressure reaches or exceeds the 5250 psi limit. A soft alarm set point of 5100 psi will provide notification when the pressure is climbing. The average operating pressure of NS-25's well head is approximately 4900 psi with the maximum expected pressure of 5250 psi. • „ • • I, • NS25 (PTD # 2031660) TIO Plot Well NS-25 • —III—TN /1•904"°4 —II—LA / 00A • • 000A 1. 2 ZEE, • lll i122 32.142 2,5,'"5''.2 1E,12 'E'2 772 213 NS25 (PTD #2031660 Injection Plot Well NS-25 52= -55,050 sa.cao :45000 —WHIP I -A1.000 2.602 -35.000 zi 2.400 2200 -30020-g —GI —Other 2000 1,2000 -25020 .■• 1,652 :25,000 1.400 1.200 :15 CCO 1.00S 800 -10 COO -5.0ZO 2395/1 mill rnem aviai 11;11111 01/12112 001'1312 051512 071'512 001'0,42 •" '2 Z'1513 05.0isi oil 7 _..t A. .„,.. TREE= ABB-V017'&SKS 00A SAFETY NOTES:WELL REQUIRES A SSSV"""4-1/2" WELLHEAD= ABB-VG113-5fr MILTON&6,91.9 N,25 CHROME TIE Ea 18091'-16371'"'""r LNR IS A ACTUATOR= BAKER MIXTURE OF C FROM E&1-10 CSO KB.ELEV= 56.42' o/ - BE E.EV= 4013'(C6 15,671 / , 200' 1-420.cot...rum:1R,leo,x sa,ID=18 378" 1 KOP= 100' __ Ota-31147. A( __ . , 4,a, i-------{ 1791" 1-r 32#i-no SLVN,0=5.9631 °dun MD= 18462" I"i .,.(NO COKTROL LINES) ,bsturn TVD= 10600'SS 4 e e .116 1 113-3/6"CSG,6611,L-80 STC,13 a 12 415' 1-14521' IY Minimum ID=3.260"•18S27' 4-1/2"HES RN NIPPLE / Z I 16691. Hr i4:1/2"X0,16=3 578"1 Jr 1SG,324,1-95E,,0361 bpi,CI=6.094' H 16091* V 1-ropoFruft H 16144' 1---' ---.I 16164' I .4'Oa') ?"FIK R 7 I16178' 1 [.,ytt-,, 1"F4s.k I,I),,1.0 0,_ I 4-1,2"TM 1366,13C1116 VAAI 1116091'-1837r I >.< 1 9-S1"WINDOW 16378".16394' TOP HC(7 JTS) 0129 W,ID.3 640' WrclIPSIXXX(02-05-04) -I 16378' • 9-5/8"COG.53,54,L-80 BTM-C,1-1 -16378' I ID e.-8535' . I 18572' HES R NIP,ID=3.43r I 18693' 1-17"X 4-1Ir SOT S-3 PKR,113--. 60- 18616' 4-1/2"HES RNP,D=3.43r I 111- 18627" 1-I4-112"HES RN RP,13.3,260"Mew ELMO) 1 -------------4 18627' -14-1/r PF44 R.OG(05/21112) I 18636' 1-Ir X 5'NKR 7XP I NR TDPPISR.0=? I 4-1/2"TBG,18 81,L-80 VAN TOP HO, -1 18641' I '."----.......::: 18641' 4-lir WLEG,13=3 850' .0129 bpf,13=3.840' (113G()RFT=3.515') ,1 18669' -17:X 5"BKR FLEX LOCK NISIL1221.1 . ,,, ,J . 88668' 1- 5*)-F-CTI-15-xg,ID-,3 X58-1 r UR,264,L-80/13CRI0 WOW 511, _i i'nor 1—,411 . ■ .0383 bpf,0=6.276'(SEE SAFETY NOTE) PERFORATION SUMIARY REF LOG: LIMO ON 02/23/04(TE-IN LOG GROCL 03/16/04) I ANGLEAT TOP FERE: 20°far 18985' Nste.Refer to Production ID for historical pert data SEE SPE INTERVAL(KD) OpniSqz SNOT SO2 2418" 6 - 18995-19064 ' 0 - 10/03/05 - 2-7/8" 6 19064-19204 0 04/11/04 riliairl—fiiiviiiCrirTITI IFen)1— 19248' I. 4Y4V4vei 4.112'1741,1266,1.80 VAIA-AcE, --f 19253' 4484.11 6666664 .0152 bpf,0=3 958" ' CATE rtcv ny OOMMONTO DATE rEV BY COMCNTS NORTHSTAR 03/02/04' RAC ORIGINAL COMPLETION 02/17/11 ? /44) A000)SSSV SAFETY'MOTE WEIL: NS25 i 04119/04 rilW ACFERF 05130112 VIEC/JNID SET PEN PLUG(05/21/12) PEf81T kb. 2031660 1 10/08835 F61111111 ACFEFF&NEW FORMkT .04/22/13 IIAMNID 9-5/8'CSG CORRECTIONS AR Na: 50-029-23181-00 1 11/27/07 V'464PJC INELLEILILOCA TEN COHRECIX 04/30/13 LAMPAD 9-5/8'CSG/WS EDITS/ACCED 20'03N) SEC 11,T13N,R13E,1289'FSL&647'FR 106/30/08 vwswid CiRAWKIG cocarcnoNs ,03118/09 RCPSV RN rip D CORR(03/05/09) ... EIP Esploration(Alaska) n 9 ZE January 10, 2006 John K. Norman, Chair Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, AK 99501 Re: NS29 (PTD 201-041) Administrative Approval to Inject Gas Dear Commissioner Norman: BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 JAN 1 3 2000 1933ka 0", & O da N' ,I� Q� This letter is in response to your letter of January 9, 2006 granting administrative approval to inject gas into the subject well. Conditions of the AOGCC's approval require BPXA to install and operate automatic well shut-in or pressure limit equipment on NS29's well head and IA and provide the Commission with details of the specific automatic well shut-in equipment selected before injecting gas in NS29. In accordance with conditions 5 and 6 of the above referenced letter, BPXA is submitting to the AOGCC the details of the automatic well shut in system that is planned for this well. NS29's well head and IA pressure shall be limited to 5250 and 1500 psig respectively. The automated shut down systems for this well have been modified and documented in accordance with Northstar's Management of Change project number 35699. The NS29 well head pressure transmitter PT-0029A shall alarm at 5100 PSIG and close NS29's SDV at 5250 PSIG. The normal operating pressure of the NS29's well head is around 4700 psig. The NS29 inner annulus pressure transmitter PT-0029D shall alarm at 1300 psig and shut down the well by closing the SDV at 1500 PSIG. Please do not hesitate to contact me at 564-5167, or the Northstar Operations Manager at 907-670-3576, with any questions. Sincerely, ZJohn D. Garing Northstar Subsurf m Leader BPXA, ACT, Northstar ITIV-01 Lm i BP Exploration (Alaska) Inc. Steve Rossberg, Wells Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 December 29, 2005 Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, Alaska 99501 CR,/ , , D fakqN s 2� 006 Qre Gas corps go Subject: Northstar Unit well NS-29 (PTD 2010410) Request for Administrative Approval: Continue Gas Injection Operations Dear Mr. Norman, BP Exploration (Alaska) Inc. requests approval to continue gas injection operations into well NS-29. Well NS-29 has outer annulus by conductor communication. The well has failed an MIT-OA with Nitrogen at 10 psi with returns of gas to surface. However, two competent barriers have been established thus it is BP's contention that the well can be safely operated. The barriers are competent tubing and production casing that have passed pressure tests to 1.2 times the maximum anticipated injection pressure. Observed annulus operating pressures do not exceed 45% of the casing's rated burst pressure. The proposed operating and monitoring plan attached includes frequent monitoring of the competency of the barriers by recording daily surface pressure and injection rate data, increasing the frequency of mechanical integrity tests and increased reporting to the AOGCC. These measures will ensure continued safe gas injection operations. Considering the presence of two competent barriers, physical repairs in this well are not necessary for safe operation. If one of the competent barriers should become compromised, the well will be shut in, the Commission notified and physical corrective options will be evaluated. This request for approval is consistent with Area Injection Order 23, in that sound engineering and operating practices have established two competent barriers in addition to an operating and monitoring plan developed to ensure continued safe operations. There is no underground source of drinking water, thus no USDW is endangered. If you require any additional information, please contact me at 564-5637 or Joe Anders / Anna Dube at 659-5102. Sincerely, y Steve Rossberg Wells Manager Attachments Technical Justification for Administrative Relief Request Wellbore Schematic TIO Plot Northstar Unit NS-29 Technical Justification for Administrative Relief Request December 29, 2005 Well History and Status Northstar Unit well NS-29 (PTD 2010410) has a shallow surface casing leak demonstrated by outer annulus by conductor communication indicated by failing MIT-OA's with fluid and subsequently with Nitrogen, producing returns to surface. However a passing MIT -IA to 6300 psi on 12/26/05 demonstrates competent tubing / packer and production casing. Recent Well Events: > 10/29/05: OA Injection test - FAIL, returns to surface from 4" nipple on 20" conductor. > 10/29/05: PPPOT-13 5/8" to 1000psi - PASS > 11/10/05: MIT-OA to 500 psi w/N2 - FAIL, returns to surface up flutes, no returns from 4" port. > 12/25/05: PRN plug set @ 12945' > 12/26/05: AOGCC MITIA Passed to 6300 psi Barrier and Hazard Evaluation The well has two competent well barrier systems to prevent the atmospheric release of injection gas and to safely operate the well. The primary barrier is the tubing/packer. In the event of a leak, the secondary well barrier system composed of the production casing will contain any pressure. These systems have been pressure tested to 1.2 times the maximum gas injection pressure to ensure competency. Barrier competency is monitored using wellhead pressure plots (TIO plot) and periodic pressure tests to 1.2 times the maximum anticipated injection pressure. Primary Well Barrier System: Tubing / packer competency is demonstrated by the passing MIT -IA to 6300 psi on 12/26/05. Competency will be monitored by daily annulus pressure observations, by frequent review of a TIO plot to monitor pressure trends and by annual demonstration of tubing integrity. Secondary Well Barrier System: Production casing competency is demonstrated by the passing MIT -IA to 6300 psi on 12/26/05. Competency will be monitored by daily annulus pressure observations, by frequent review of a TIO plot to monitor pressure trends and by annual demonstration of production casing integrity. Also, maximum allowable inner annulus surface pressure will be limited to 2000 psi. Thermal Overpressure of the OA: Maximum allowable OA pressure will remain at 0 psi due to the shallow production casing leak. Any OA pressure increase would be observed by the Operators conducting daily well inspections and the well would be shut-in. Injection fluid temperatures are warmer than the wellbore temperatures to the depth of the surface casing shoe. This results in the well cooling off when shut-in, preventing thermal overpressure. Mechanical Condition: The surface casing is not considered a component in the well barrier systems. The tubing/packer and production casing are the 2 competent well barrier systems and have been confirmed. The well will be shut-in at any indication of barrier competency loss. Automatic Shutdown: The maximum allowable injection pressure will be limited to 5250 psi. The pressure transmitter PI-0029AI installed on the well head will shut the SDV on the wellhead, isolating the well from the injection manifold piping. A soft alarm set point of 5100 psi will provide notification when the pressure is climbing. The average operating pressure of NS-29's well head is approximately 4700 psi. Proposed Operating and Monitoring Plan 1. Maintain containment in the cellar. 2. Install operating pressure limiting controls. 3. Continue gas injection. 4. Record well head pressures and injection rates daily. 5. Submit a report monthly of well surface pressures and injection rates to the AOGCC. 6. Annually demonstrate the integrity of the tubing and production casing. 7. Stop injection and notify the AOGCC if there is any indication of a compromise of mechanical condition. -�5 ABB-VGI 7" WELLHEAD = ABB-VGI 13-5/8" MULTIBOWL 6.5KSil ACTUATOR = KB. ELEV = 56.17' BF. ELEV = 40.77' (CB 15.4') KOP_ Max Angle = Datum MD = Datum TV D 13-3/8" CSG, 68#, L-80 BTC, ID = 12.415" 3798' Minimum ID = 5.75" @ 12945' 7" OTIS RN NIPPLE ICHEM CUT I CHEM CUT 1--1 13057' TOP OF 7" LNR 1 13156' 7" TBG, 32 #/ft, T-95 VAM TOP HC, .0361 13163' bpf, ID = 6.094" , CONNECTION ID = 6.059" 9 5/8", 53.5# L-80 BTC-M, ID = ?.???" 1334Z PERFORATION SUMMARY REF LOG: USITIGR/CCL (06/05/01) NEW DEPTH LOG (10/31/03) = TOP OF PERF 13576-13590' A NGLE AT TOP PERF: INITIAL PERF - CHARGE 4505 POWERJET, HMX, PENETRATION: 54", HOLE 0.42", PHASE 72 DEG. Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL (MD) Opn/Sqz DATE 4-1/2" 5 13590 - 13760 O 06/23/01 PBTD -1 1366T 7" LNR, 29#, L-80 NSCC, 13679' .0371 bpf, ID = 6.184" S� NOTES: POSSIBLE LNR DAMAGE @ 13377' SL N S 2 9 M. SEE 11/9103 WSR &PHOTOS ON S:DRIVE 2147' 7" HRQ SSSV w /HRQ SV LN = 5.963" 12888' —{7" OTIS R NIP, ID = 5.875" 12910' BAKER 9-5/8" X 7" S-3 PACKER, ID = 6.08" 12934' 7" OTIS R NIP, ID = 5.875" 12945' 7" OTIS RN NIP, ID 12945' j$7X PLUG SET (12125/05) ????? 5.5" XO, ID = ???? 12974' 5-1/2" TT STINGER W/MULESHOE, ID = 4.930" (DRIFT=4.875") 129$2' 7" OTIS R NIP, ID = 5.875" 13003' BAKER 9-5/8" X 7" S-3 PACKER, ID = 6.08" 13027' 7" OTIS R NIP, ID = 5.875" 13039' 7" OTIS RN NIP, ID = 5.75" 1305T 7" OVERSHOT ASSY, ID = 7.188" (DRIFT=6.00") 13093' -j7" OTIS R NIP, ID = 5.963" 13114' BKR SABL-3 PACKER, ID = 6.00" 13139' 7" OTIS R NIP, ID = 5.963" 1315W 7" OTIS RN NIP, ID = 5.77" 13163' —1 7" WLEG, ID = 6.184" ELMD TT NOT LOGGED? DATE REV BY COMMENTS DATE REV BY COMMENTS 04/25/01 INITIAL DRILL 06/08/01 ORIGINAL COMPLETION 11/19/03 BNF IRWO 11/11/05 TLH NEW FORMAT 12/26/05 JLW/PAG I RX PLUG PULLED (08/19/03) 12/26/05 JLW/PAG I PRN PLUG SET I FISH: 3-3/8" BKR IBP w / 1.75" FISHING NECK I NORTHSTAR WELL: NS29 PERMIT No: "2010410 API No: 50-029-23005-00 BP Exploration (Alaska) t' #8 ) ) .,. ,\wr.,,,. ~, ...~ ' ~...~ ~~- ~...~ ....~ ~~... ·',1'·'1'- .,. bp BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 ';'0,' :r-.#~ :F"" q '\ 1re:: ~ it(\ c \G C tl '\¡ t'C: ·3r.~¿1 January 10,2006 . '\ l\¡ "1 is]) '100r- .J /-11\ J 0 L \) John K. Norman, Chair Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage,AK 99501 3i 0:21$ Gmù~" (;¡¡)mlPni£¿¡~(t~ßTI ;11liùlr;~©¡P§!\lJæ\ Re: NS29 (PTD 201-041) Administrative Approval to Inject Gas Dear Commissioner Norman: This letter is in response to your letter of January 9, 2006 granting administrative approval to inject gas into the subject well. Conditions of the AOGCC's approval require BPXA to install and operate automatic well shut-in or pressure limit equipment on NS29's well head and IA and provide the Commission with details of the specific automatic well shut-in equipment selected before injecting gas in NS29. In accordance with conditions 5 and 6 of the above referenced letter, BPXA is submitting to the AOGCC the details of the automatic well shut in system that is planned for this well. NS29's well head and IA pressure shall be limited to 5250 and 1500 psig respectively. The automated shut down systems for this well have been modified and documented in accordance with Northstar's Management of Change project number 35699. The NS29 well head pressure transmitter PT-0029A shall alarm at 5100 PSIG and close NS29's SDVat 5250 PSIG. The normal operating pressure of the NS29's well head is around 4700 psig. The NS29 inner annulus pressure transmitter PT-0029D shall alarm at 1300 psig and shut down the well by closing the SDV at 1500 PSIG. Please do not hesitate to contact me at 564-5167, or the Northstar Operations Manager at 907-670-3576, with any questions. Sincerely, #7 by • • 0- BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 February 7, 2005 (907) 561-5111 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 W. 7 h Ave 9100 Anchorage, Alaska 99501-3539 RE: Modifications to Northstar Oil Pool. Dear Mr. Norman, BP Exploration (Alaska) Inc. (BP), as operator of the Northstar Unit, requests a modification to the Area Injection and Conservation Orders in the Northstar Field and Northstar-Oil Pool. Currently finding number 42 of Conservation Order No. 458 and finding number16 of Area Injection Order No. 23, both dated October 9, 2001, set the operating floor for the reservoir pressure at 5130 psi. BP seeks modification of this finding to lower the floor of the operating pressure from 5130 psi to 5100 psi. The results of BP's reservoir modeling, depicted on attachment 1, indicate no significant impact to the ultimate field recovery. If you should have further questions or suggestions, feel free to contact me at (907) 564- 5567 or John Garing at (907) 564-5167. Sincerely R. L. Skillern Landman -Alaska cc: Bob Crandall Attachment: Modeling Results - Summary ort a� Modeling Results - Summary Northstar Pressure Regimes 4.0 2.0 0.0 E -2.0 -4.0 .e 4750 4800 4850 4900 4950 5000 5050 5100 5150 5200 Average Field Pressure at -11100 Datum (PSIA) Significant Reserve Loss does not occur until average reservoir pressure is dropped below 5000psia. BP does not plan on operating with average reservoir pressure below 5100psia. byThe positive effect of aquifer support was not modeled. bp BP Exploration (Alaska) Inc. Steve Rossberg, Wells Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 December 29,2005 R€C€/~ JAN 0 'E:D Alaska Gl. 3 2006 " Nt Gas f'I A (,,()fls C I'fnCh . ·0lrlfh· oragO"#ISS;Oß Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West ¡th Avenue Anchorage, Alaska 99501 Subject: Northstar Unit well NS-29 (PTD 2010410) Request for Administrative Approval: Continue Gas Injection Operations Dear Mr. Norman, BP Exploration (Alaska) Inc. requests approval to continue gas injection operations into well NS-29. Well NS-29 has outer annulus by conductor communication. The well has failed an MIT-OA with Nitrogen at 10 psi with returns of gas to surface. However, two competent barriers have been established thus it is BP's contention that the well can be safely operated. The barriers are competent tubing and production casing that have passed pressure tests to 1.2 times the maximum anticipated injection pressure. Observed annulus operating pressures do not exceed 45% of the casing's rated burst pressure. The proposed operating and monitoring plan attached includes frequent monitoring of the competency of the barriers by recording daily surface pressure and injection rate data, increasing the frequency of mechanical integrity tests and increased reporting to the AOGCC. These measures will ensure continued safe gas injection operations. Considering the presence of two competent barriers, physical repairs in this well are not necessary for safe operation. If one of the competent barriers should become compromised, the well will be shut in, the Commission notified and physical corrective options will be evaluated. This request for approval is consistent with Area Injection Order 23, in that sound engineering and operating practices have established two competent barriers in addition to an operating and monitoring plan developed to ensure continued safe operations. There is no underground source of drinking water, thus no USDW is endangered. If you require any additional information, please contact me at 564-5637 or Joe Anders / Anna Dube at 659-5102. Sin~ereIY, ¡;! gSSberg , Wells Manager Attachments Technical Justification for Administrative Relief Request Wellbore Schematic TIO Plot Northstar Unit NS-29 Technical Justification for Administrative Relief Request December 29, 2005 Well History and Status Northstar Unit well NS-29 (PTD 2010410) has a shallow surface casing leak demonstrated by outer annulus by conductor communication indicated by failing MIT-OA's with fluid and subsequently with Nitrogen, producing returns to surface. However a passing MIT-IA to 6300 psi on 12/26/05 demonstrates competent tubing / packer and production casing. Recent Well Events: > 10/29/05: OA Injection test - FAIL, returns to surface from 4" nipple on 20" conductor. > 10/29/05: PPPOT -13 5/8" to 1000psi - PASS > 11/10/05: MIT-OA to 500 psi w/N2 - FAIL, returns to surface up flutes, no returns from 4" port. > 12/25/05: PRN plug set @ 129451 > 12/26/05: AOGCC MITIA Passed to 6300 psi Barrier and Hazard Evaluation The well has two competent well barrier systems to prevent the atmospheric release of injection gas and to safely operate the well. The primary barrier is the tubing/packer. In the event of a leak, the secondary well barrier system composed of the production casing will contain any pressure. These systems have been pressure tested to 1.2 times the maximum gas injection pressure to ensure competency. Barrier competency is monitored using wellhead pressure plots (TIO plot) and periodic pressure tests to 1.2 times the maximum anticipated injection pressure. Primary Well Barrier System: Tubing / packer competency is demonstrated by the passing MIT-IA to 6300 psi on 12/26/05. Competency will be monitored by daily annulus pressure observations, by frequent review of a TIO plot to monitor pressure trends and by annual demonstration of tubing integrity. Secondary Well Barrier System: Production casing competency is demonstrated by the passing MIT-IA to 6300 psi on 12/26/05. Competency will be monitored by daily annulus pressure observations, by frequent review of a TIO plot to monitor pressure trends and by annual demonstration of production casing integrity. Also, maximum allowable inner annulus surface pressure will be limited to 2000 psi. Thermal Overpressure of the OA: Maximum allowable OA pressure will remain at 0 psi due to the shallow production casing leak. Any OA pressure increase would be observed by the Operators conducting daily well inspections and the well would be shut-in. Injection fluid temperatures are warmer than the wellbore temperatures to the depth of the surface casing shoe. This results in the well cooling off when shut-in, preventing thermal overpressure. Mechanical Condition: The surface casing is not considered a component in the well barrier systems. The tubing/packer and production casing are the 2 competent well barrier systems and have been confirmed. The well will be shut-in at any indication of barrier competency loss. Automatic Shutdown: The maximum allowable injection pressure will be limited to 5250 psi. The pressure transmitter PI-0029AI installed on the well head will shut the SDV on the wellhead, isolating the well from the injection manifold piping. A soft alarm set point of 5100 psi will provide notification when the pressure is climbing. The average operating pressure of NS-291s well head is approximately 4700 psi. Proposed Operating and Monitoring Plan 1. Maintain containment in the cellar. 2. Install operating pressure limiting controls. 3. Continue gas injection. 4. Record well head pressures and injection rates daily. 5. Submit a report monthly of well surface pressures and injection rates to the AOGCC. 6. Annually demonstrate the integrity of the tubing and production casing. 7. Stop injection and notify the AOGCC if there is any indication of a compromise of mechanical condition. TREE = ABS-VGI7" EL5KSI WELLHEAD:: ABS-VGI 13-5/8" MUL T!BOWL 6.5KS! L-80 BTC, to:: 12.415" 3798' 1 CUT CUT 13057' 13342' 13156' 13163' VAMTOPHC, .0361 10 6.059" BTC-M, ÆRFORA TION SUMMARY LOG USITfGRlCCL (06/05/01) NEW OEPTH LOG TOP OF PERF 13576-13590' AT TOP - CHARGE: 4505 POWERJET, HMX, 54", HOLE: 0.42", PHASE: 72 DEG. Production DB for historical perf data SIZE SPF INTERVAL (MD) Opn/Sqz DATE 4-1/2" 5 13590 - 13780 0 06/23/01 13667' 13679' IT' LNR. 29#. L-80 NSCC, .0371 bpf, ID 6.184" COMMENTS DRIll ORIGINAL COMPLETION RWO NEW FORJ'v!A T JLW/PAG PLUG PULLED (08/19/03) PRN PLUG SET ..¡ I I ~~ DATE NOTES: LNR 13377' SLM. SEE 1119103 WSR & PHOTOS ON S:DRlVE HRO SSSV w IHRO ~ R NIP, :: 5.875" X 7" 8-3 10 6,08" I 10 6.08" 13057' 13093' 13114' 13139' OTIS R NIP, 10 = 5,875" I OTIS RN NIP, 10 5.75" I OVERSHOT ASSY, 10 7.188" (DRIFT=6.00") T' OTIS R NIP, 10 = 5,963" SABL-3 PACKER, 10 = 6.00" OTIS R NIP, 10 5.963" 13163' ~ 113644' FISH: 3-3/8" SKR 1 .75" FISHING NORTHSTAR WELL: NS29 ÆRM!TNo: '2010410 API No: 50-029-23005-00 BP Exploration 9/29/2005 Plot #6 ( ( '~ì ~? i~\ ~ ~:.;¡ 1'-= II ld , i,\ \,1 . I ,,,,,\, !, I i\ \II! PI '.. \. 1 'I ! 1',\ J ,jl ¡. \ '] 1· .f...., . I,' \1J' ;1 ¡.j-,\ U'· ,j ,~ 1J i..i W" ,~ fñ';¡ ,;-.J ¡, JI I ; 11, 'Ii ::::J .1 "J 'I i ¡ ! J.) 1 I 'I \,~ :..J , ') "I ,./~,,T:,\,,' 0J '.",;J,!,,\,!.,',7 ./-:-iJ.i~\ \\ L~ l L ~~ ·ii ~.~ u"j FRANK H. MURKOWSKI, GOVERNOR AI~A~1iA. OIL AND GAS CONSERVATION COMMISSION 333 w. rrw AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing arèa injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Injection Order "Demonstration of Mechanical Integrity" Affected Rules "Well Integrity Failure and Confinement" " Administrati ve Action" Area Injection Orders AIO 1 - Duck Island Unit AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; Western Operating Area AIO 4C - Prudhoe Bay Unit; Eastern Operating Area AIO 5 - Trading Bay Unit; McArthur River Field AIO 6 - Granite Point Field; Northern Portion AIO 7 - Middle Ground Shoal; Northern Portion Ala 8 - Middle Ground Shoal; Southern Portion AIO 9 -Middle Ground Shoal; Central Portion AIO 10B- Milne Point Unit; Schrader Bluff, Sag River, Kuparuk River Pools AIO 11 - Granite Point Field; Southern Portion AIO 12 - Trading Bay Field; Southern Portion AIO 13A - Swanson River Unit AlO 14A - Prudhoe Bay Unit; Niakuk Oil Pool Ala 15 - West McArthur 6 7 9 6 7 9 6 7 9 6 7 9 6 6 9 6 7 9 6 7 9 6 7 9 6 7 9 4 5 8 5 6 8 5 6 8 6 7 9 4 5 8 5 6 9 '~ :( Affected Rules "Demonstration of "Well Integrity "Administrati ve Injection Order Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River 6 7 10 Unit; Tam Oil Pool 6 8 AIO 17 - Badami Unit 5 AIO 18A - Colville River 6 7 11 Unit; Alpine Oil Pool AIO 19 - Duck Island Unit; 5 6 9 Eider Oil Pool AIO 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AIO 21 - Kuparuk River 4 No rule 6 Unit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 Unit; Aurora Oil Pool 6 9 AIO 23 - Northstar Unit 5 AIO 24 - Prudhoe Bay lJnit; 5 No rule 9 Borealis Oil Pool AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Disposal Injection Orders DIO 1 - Kenai Unit; KU No rule No rule No rule WD-l DIO 2 - Kenai Unit; KU 14- No rule No rule No rule 4 DIO 3 - Beluga River Gas No rule No rule No rule Field; BR WD-l DIO 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DIO 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DIO 6 - Lewis River Gas No rule No rule 3 Field; WD-l DIO 7 - West McArthur 2 3 5 River Unit; WMRU D-1 DIO 8 - Beaver Creek Unit; 2 3 5 BC-3 DIO 9 - Kenai Unit; KU 11- 2 3 4 17 DIO 10- Granite Point 2 3 5 Field; GP 44-11 Affected Rules "Demonstration of "Well Integrity "Administrative Injection Order Mechanical Failure and Action~' Integrity" Confinement" DIO II - Kenai Unit;KU 2 3 4 24-7 DIO 12 - Badami Unit; \VD- 2 3 5 1, WD- 2 DIO 13 - North Trading Bay 2 3 6 Unit; S-4 D 10 14 - Houston Gas 2 3 5 Field; Well #3 010 15 - North Trading Bay 2 3 Rule not numbered Unit; S-5 DIO 16 - West McArthur 2 3 5 River Unit; WMRU 4D DIO 17 - North Cook Inlet 2 .., 6 -' Unit; NCill A-12 010 19 - Granite Point 6 Field; W. Granite Point State 3 4 17587 #3 010 20 - Pioneer Unit; Well 3 4 6 I702-15DA wnw 010 21 - Flaxman Island; 3 4 7 Alaska State A - 2 010 22 '... Redoubt Unit; RU 3 No rule 6 Dl 01023- Ivan River Unit; No rule No rule 6 fRU 14-31 DIO 24 - Nicolai Creek Order expired Unit; NCD #5 DIO 25 - Sterling Unit; SU 3 4 7 43-9 DIO 26 -Kustatan Field; 3 4 7 KFl Storage Injection Orders SIal - Prudhoe Bay Unit, No rule No rule No rule Point McIntyre Field #6 SIO 2A- Swanson River 2 No rule 6 Unit; KGSF #1 SIO 3 - Swanson River Unit; 2 No rule 7 KGSF #2 Enhanced Recovery Inj ection Orders EIO 1 - Prudhoe Bay Unit; No rule 8 Prudhoe Bay Field, Schrader No rule Bluff Forrnation Well V-I0S ( Injection Order EIO 2 - Redoubt Unit; RU-6 "Demonstration of Mechanical Integrity" 5 ~' Affected Rules "Well Integrity Failure and Confinement" 8 "Administrative Action" 9 I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO,FRM STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO" CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATIACHED COpy OF ADVERTISEMENT MUST BE SUBMITIED WITH INVOICE F AOGCC 333 West ih Avenue, Suite 100 Anchorage, AK 99501 907-793-1221 AGENCY CONTACT DATE OF A.O. R o M Jody Colombie September ?7, ?004 PHONE PC\¡ (907) 793 -I ?,) I DATES ADVERTlSEME;\IT REQVIRED: T o Journal of Commerce 301 Arctic Slope Ave #350 Anchorage, AK 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 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 Public Notices ~: ,( Subject: Public Notices From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 29 Sep 2004 13:01 :04 -0800 To:pn~isèlg~~d-rè:ipi~~~st;............. ......>:> .......................' ..... ......<.............................. .... ....... ......................i '.' B?Ç;·.?ytìthî~~~cirer~br~n71l1ciy7r~~~~;~ta.t~.å1Ç._~~~~.~~1a.,~""'~~þ .' .... ... ......>i '. .'. .' ....... ." .......... ~.~i.,..Ir.I&.~ge' <stan~kj.@unocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, tnnjrl <trmjr 1 @aol.com> ,jbriddle '<jbriddle@marathonoi1.com>, rockh-ill <ròckhilI@aoga.org>, shaneg <sh~eg@evergreengas.com>, jçlarlington' <jdarlington@fo~estoi1.com> ,nelson <knelson@petroleurtinevvs~com>, cbodd-y <cbpddy@usibellLcom>, . Mark Dalton ". <mark.dalton@hdtinc.,com>, Shannon Donnelly <shannon.donne-lly@conocophillips~com>~. '~Mark P. , ". , >. ' ' Worcester"- <mark.p..worcester@conQcophillips.com>, "-Jerry C. Dethlefs,r , ! <jerry.c.dethlefs@êonocophillips.col11>,· Bob <bob@inletkeeper.org>, wdv <wdv@dnr.statè.ak.us>, tjr <tjr@dnr~state.ak~ us>, bbrítch <bÞritch@alaska.nèt>,.mjnelson <rrtjnelson@pu~lngertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "R.andyL. Skillern" <SlCilleRL@BP..com>, "Deborah J. Jones'" <JonesD6@BP.com>,"PauIG.Hyatt" <byattpg@BP.com>, nSteven R. Rossberg" <RossbeRS@BP .com>, Lois <lois@inle~eeper.org>, D~ll Bross<kuacnews@Jcuac.org>, Gordon Pospisil <PospìsG@BP.com>, "Francis S; Sorrimer" <SommetFS,@BP.com>, Mikel· Schultz <Mike1.Schultz@BP.com>, "NickW. Glover" <GloverNW@BP.com>,."Dmjl J; Kleppin" <KleppiDE@BP.com>, "JanetD. Platt" <PlattJD@BP.com>,"Rosanne M. Jacobsen" <JacobsRN1@BP.com>, ddonkel <ddonkel@cfl.rr;com>,-Collins Mòurtt . <collins_ mount@revenue.state.ak.us>, mckay <mckay@gci.net=?,,:Barbara F Fullmer <bar1>ara.£fullmer@conocophillips.coJ.1l>, bocastwf <bocastwf@bp.com>, Charles Barker : <barker@usgs.gov>, doug_schultze <doug__schultze@xtoenergy.com>, Hank Alford' ' , <hank~alford@exxO:nmòbil.com>, Maik.·Kovac <yesn~l@gci.net>, gspfQff . <gspfoff@àurorapower.com>, GreggN ady<gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>:, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyapcy@seal-tite.net>, "James M. Ruud" <janies.m.ruud@conocophillips.com>, Brít Lively <maPal~ka@alcnet>,jah <jah@dnr.state.ak.us> ,Kurt EDIson <kurt _ olson@legis.state.ak.us>,buonoje<buonoje@bp.com>, Mark Hanley <m.ark~hanley@anadarko.com> ,.loren _leman <lòre~léroJm@gov.state.ak. us>, Julie Houle'<';ulie_houle(@dnr.state.ak.us>,JohnW Katz<j,wkatz@sso.org>, SuZan 1 Hill ' <suzan _ hil1@dec.state.ak.u~>, tablerk<tab-lerk@unocal.com>, }Jrady <bracJy@~oga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp· <bpopp'@boro~gh~enai.ak. us>, Jittl WJÛte· ' <jimwhite@satx.rr.com>, "John S. HawQ~'" <j0bn.sJ~aw<?rth@exxonmobil.com>, marty <marty@rkindustrial.com> ,ghanimons <ghammom@aol.co~, nnëlean .'. .' ,. <rrÌ1clean@póbQx.alaskli;.n.eÞ, riikm 7200 <mkni 7200@ao1..com>, Brian Gillespie . . ' " ' ' ',' . ".' -. <ifbIl1g@uaa.al~ska.edu>,-Davìd L'~öel~ns <db()elens@a~()rapowe~.co111>, loCi4J?urkee <TDURKEE@~G.com>, Gary Sc~urti'<gary ~schultz@dnr.state.,ak.us>,.W ayne:Rancier <RANCIER@petr()~canada.ca>, Bill Miner <BiIt. Mill~t@'xto81as~a.com> ,:1.Jrandón Gagnon <bgagnon@brerialaw.com>, Paul Winslow <pmwinslo.w@forestoil.com>, C;.an:y'Catron <catrongr@bp.com>, Sharmaine C()peland <c()pelasv@bp.criin~ ,SQZ~ë'Allex.ail <sanexan@helrhen~rgy.com>, KristÏi1 Dirks, <kristin.-:. dirks@c:fur;'statð.åk.us>~' KayneIl Zeman <kjzeman@¡parathonoil.com>, JohnTower <ìobD.Tower@eia.<;fue.gov;', Bill Fowler " . <Bill_ Fowler@anadaiko. COM>, v aughn·Swårtz <vaughn.s\Yéll1~@!þ~çi11.~Çºm?';§9ºt:f:Ç~~ª"!Y!Ç~ 1 of2 9/29/2004 1: 10 PM Public Notices <$cott.cranswick@J;J1I1ls.goV>,· ¡Jraø· McKi111 <ÏIlckirnbs@BJ?~corn? <, .";'::'," . ,,":. """ "; , : "" I ~~~~$e fin.cft:lJ,éã9t~.~he.d . ·~()tice .ari9-At:ta(Z~mep.t:fò~~%~'~:?J?9~~~. améñdmèat of '9;I.l~e:vgrog:n<i<i.nj§p~±()n orders . and, the PtJ.b1:ic ·'þJ;'otic~EIêtPPY'V~J.:J.t;y #1.0\. y;<.)¢ly Cöloriibie . . ' . '" .. " ....... , .. , , ,,' .':: ,.:..." ' . .." : . :':... , ...." , .... . ,'." ".....:: n,"" : ; ,"" .:..: ~, : .. , " : ' :. '" ... ': ;.. _: . : .... ..' .... ..... ... ......... '.. ". ........ ~.. ..... . .... .... . ......... .........¡C()J1têl1,t-ty(l~~ applicatiot1/m.swordi ¡.l\t~cha~lçallntegrltypr9posatd~lc i.,. . .'. .".......... ..,.'...........,,'....................:..'......:.......... '...:...:.............'. ..:..........,..................,...,.......'.~.......................... .... b..··. ......'.................... c............... :.)1..','.' ~ ... .... . .... . .. ". . .... .... :Content...EncodQlg:aseu!-t _"'." _'._ .,.... ,~_._.,,', ,._:.", .... ~.:.;....;;.M ....,_... ,~',,·.....~':~..A..._" .,:,...., "';" '"' .. ......'....' ._, ~:. ;.._., ..," .........." ~w ~...,.~~, :0.; "''''~ .,;,;~':...,,~ _......_.,.~_ :_..,~.;......:.....;"..:. _~.~ ,",.~.' ,.....;; "_':-"~"'_'_'_" ,_..._... ...." .., ,'.,,' "~ ,.., ....1..., ~~-.;.__ '... . ,..._~~__..,........~. ..,,~.. ..:~...,...". Meëhållicallntegrity of Wells Notice.dQc ¡·C··.. . . ···E'.··'.'.······.·d····.····, .. ·b········,.·· 6 4....·· . .. ..... ., ! ·ontent~L.,colng: ·ase. ...... ............... .,...... ........ ...... . .....i. ............... .. ..' .... ..... ... .' ¡C()Ilt~nt..Wýp~: apþlìc:ition/msw()rd Hå.ppYValleyIO_lIearlngNottce..doc.· C..·· ........... .,' ............. ....... .. . .....E'..................../......,.... ·.,d.··.··.·.·....··.".···.·.··......... . ". 'L ......... ···..·.·..6·.·.·4···.·. ... i . ontent--rineo·.·· g: vase . .,~ ........,.",.._v·~......,~~"__". ......_.~"._..,~.~__'. '~'':'~~.:.~~__.:.".._.,.."......_~.,_..,_......,~,,~. _.._,.~;".._;':"-_."., '" _... --.:".,~............ _,..:.:"._.:......... ..:....,,_,_..,:.'_.:,~ .'._,,; ,_~..,:.";~.:.:.'.,..:~~~~...-:..~",..:._~,.;:~,_..;.~':~;;....-:.;..;._........,,__"'" . ~~,_,.,.."...':"._.,.._~ ....;..~ _.__ 2 of 2 9/29/2004 1: 10 PM f.ublic Ng.tice I{ ~ Subject: Public Notice From: J ody Colombie <jody _ colombie@admin.state.ak. us> Date: Wed,29 S~p200412:55:26 -0800 To:legal@alas}(ajØum~.com Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Content-Type: applicationlmsword Mechanical Integrity of Wells Notice.doc ' Content-Encoding: base64 Content-Type: applicationlmsword ,Ad Order form. doc Content-Encoding: base64 1 of 1 9/29/2004 1: 10 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 /'1a1kd /Ô/¡ð', 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, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 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 1 90083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1 597 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 .. {Fwd:'Re:' Consistent Wording for Injection( ~rs - Well Integrity ... I~' , Subject: [Fwd: Re: Consistent Wording for Injection Orders - Well Integrity (Revised)] From: John Nonnan<john_ norman@adß1in~state.ak.us> Date: Fri, 01 Oct 2004 11 :09:26 -0800 TQ: JQd,', YJColonlbie,. <jody, colòmbie@admin.state,.ak.us",> . - ,'-" ", -, . more -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert mintz@law.state.ak.us> To:jim regg@admin.state.ak.us CC:dan seamount@admin.state.ak.us, john norman@admin.state.ak.us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commission." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <¡im regg@admin.state.ak.us> 8/25/20043:15:06 PM »> Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...J to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg@admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sf. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alterna.te methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 10f2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection ~rs - Well Integrity .,. - specific to Ala 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see 010 25 and 26) - consistent language regardless of type of injection (disposal, EaR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several OIOs Administrative Actions - adopts" Administrative Actions" title (earlier rules used" Administrative Relief'); - consistent language regardless of type of injection (disposal, EaR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USOWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman(Q?admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission 20f2 10/2/2004 4:07 PM .[fwd: Re:'Consistent Wording for Injection ( rs - Well Integrity... ( Subject: [Fwd: Re: Consistent Wording for Injection Orders - Well Integrity (Revised)] From: John Norman <john_norman@admin.state.ak.us> Date: Fri, 01 Oct 2004 11 :08:55 -0800 To: lody JColombie<j.ody _colombie@adrnin.state.,ak.us> please print all and put in file for me to review just prior to hearing on these amendments. thanx -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz@law.state.ak.us> To:dan seamount@admin.state.ak.us, jim regg@admin.state.ak.us, john nonnan@admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as red lines on the second document attached. »> James Regg <jim regg@2admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions 10f2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection :rs - Well Integrity ... - adopts "Administrative Actions" title (earlier rules used "Administrative Reliefl'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu ofterrns like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K.Norman <John Norman@admin.state.us> Commissioner , Alaska Oil & Gas Conservation Commission Content-Type: application/msword Injection Order language - questions.doc . Content-Encoding: base64 Content-Type: application/msword Injection Orders language edits. doc Content-Encoding: base64 20f2 10/2/20044:07 PM Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Form 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Inte,grity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once e\Jery tv/o years in the case of a slurry injection well), and before returnin,g a \vcIl to service follo\viº~aft.eF a workover affecting mechanical integrity, and at least once every Il years while actively injecting. For ~;¡urry injection \vells, the tubing/casÏng i.lllllUlus lnust be-t-ö-SW·E:Ì.--fuf-mechanical integrity every 2 years. Unless an alternate lneans is approved by the Cornnlission. lnechanìcal integrity 111Ust be demonstrated by a tubin.Q: pressure test using a~ M±+-surface pressure of must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that ffHiSt-show~ stabilizing pressure that doesand rnay not change more than 1 O~ percent during a 30 minute period. -Aflÿ altenlate il1cans of dem.onstrating lncchanical integrity nlu~~t be approved by the C01nn1issìon. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as otherwise provided in this rule~ +1he tubing, casing and packer of an injection well must demonstrate lnaintain integrity during operation. \Vhenever any pressure con1munication. leaka,ge or lack of injection zone isolation is indicated by injection rate, operating pressure observation, h?st, survey, log. or other evidence. t+he operator HH:tS-t-shaIl immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval.:. whenever any pressure C01TIlnUnication, leakage or lack of injection zone isolation is indicated by injection fate, operating pressure ohservation, test, survey, or log. The operator shall shut in the wel! if so directed bv the Comn1ission. The operator shall shut in the \veIl \vithout awaitin,g a response fÌ"om the Comlnission if continued operationvvould be w1safe or would threaten contamination of freshwaterIf there is no threat to fresl1\vater, injection tTIay continue until the COlTIlnission requires the \\'ell to be shut in or secured. Until corrective action is successfully completed, 'Aª monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. ·(Fwd:) Re: [Fwd: AOGCC Proposed WI La~ Je for Injectors]] ( Subject: [Fwd: Re: [Fwd: AOGCC Proposed WI Language for Injectors)] From: Winton Aubert <winton~aubert@adrnin.state.ak.us> Date: Thu, 28 Oct 2004 09:48:53 -0800 \ ""," '-"',' ','.'. " .",... " '," I ',", ..".' '" , To,'·.,:,·.,.], ,ödyJ C()lolIlt)íe<,j()di3~01öinþ,ìe@,ad, ',1nin,', '.', . $ta, , te, .ak,..us> . ','. .,'" -, " ",'.. . . . . This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngeIHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven¡ Engel, Harry R¡ Cismoski, Doug Ai NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.¡ Reeves, Donald F¡ Dube, Anna T¡ NSU, ADN Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** lof3 10/28/2004 11 :09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI LanE, : for Injectors]] returning a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall * immediately* ** notify the Commission" - This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte A¡ Digert, Scott Ai Denis, John R (ANC) ¡ Miller, Mike E¡ McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of Wells Notice.doc» ~ of3 10/28/2004 11:09 AM #5 , /11 Co rl I- \.. , Oca/¿ d 1"(' (' >-'Y)' /' f ' ~C~, }\ / I ( , c e t'-/'- 6 '-- ~ ~ /¡ø.5 No . AYð f\Jo ¡Vb Nn Yr:S A/() No Ne 1U? r\)ò No Nô. TESTIFY (Yes or No) .f{ ~-5¿ àY 5~4- 4-bb<- ~ b<t-- <l-o~ 3. 24 ~ - 'l1b~- ;;J; r '- 67~ t ~ Lf'6 . 3~ ~ ~ S-bLJ- 5"8 } 't 7~~--/2.3tY 7 C, ""3 - Id.- '2- (¿, (PLEASE PRINT) ~ ì=-F lu f'Å-\.'<J~ \ ~ ~ \ ~ \Î\J\ofl \<Q LI'.t'- .:£h~ C /.k,è..()v-(.4~ {(¿ ¡ FL;}D pr£Q/lJp/JQ!C7, I!/lj.¡; VèJ.rlUj, ~~Ü' ~~e'$ f(etV~ klW';( fé)O ê , 8.{'/VsÒM ßIL, ILL 1(j~ßUL,L 11 ~Vl vt€- p,'c(CQ f '( ~ I "-"---C~J.)~ ~~ -.}Ð fé\ 7/(>n g,./~~/a{¡O\ ~}t2--DD~6 A~ '(' \ ~ Ø1l Ne<;tY? P N Á Ter~ W; I Lo~ %8 E ßC^fM #~~~ ;4ld¿fr;c \JAtIlf W:((iCt*t?&i A 0& ~c .:¡>. D· .Þ:v 772 +'-'1 k~ I 5 ¿...,~ 5~ (.0 I()Z~ /A). $K)~ rJv~ 4Þ1.c,h. fC,6'I?; I ~O(J f, t~I"-,t;{J~ 56q--4-~ lJ l~q (Ç l~ 9Q50Y o,lI-'ì E ~ttk dì} ~~~ , If / '17/..' 1f8 ADDRESS/PHONE NUMBER AU2ust 16" 2001 9:00 AM NAME - AFFILIATION NORTHSTAR POOL RULES AND AREA INJECTION ORDER STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION ~) t) -) ~.) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION NORTHSTAR POOL RULES AND AREA INJECTION ORDER AU2ust 16" 2001 9:00 AM NAME - AFFILIATION ADDRESS/PHONE NUMBER TESTIFY (Yes or No) (PLEASE PRINT) A ~~LV~ ('Jwrk ~f=+bt\f ~tAi ~t..'-,I())q -,-(~é .:è Arxvcc ~1;~c-:.ii~ \ < C\ f'€ '"""A 'v. v G r Q ~ ß ,- d c..... '( l o 0~G-v:.I yv4- '76a.. ' f '17 ç. Dòr2-r4-r 2.b7-JO't.) }Ju Nt.> ÅJ'-u Nu -' 2 ) ) ALASKA OIL AND GAS CONSERVATION COMMISSION 1 PUBLIC HEARING 3 In Re: 5 4 NORTHSTAR OIL POOL, NORTHSTAR FIELD POOL RULES AND AREA INJECTION ORDER. 6 7 8 10 11 12 13 '. J' 14 15 16 17 18 19 20 21 22 23 24 25 :. TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska August 16, 2001 9:00 o'clock a.m. 9 APPEARANCES: Commissioners: MS. CAMMY OECHSLI TAYLOR, CHAIRPERSON MR. DAN SEAMOUNT, JR. MS. JULIE HEUSSER Attorney General's Office: MR. ROBERT MINTZ * * * * * * RECEIVED AUG 2 8 2001 Alaska Oil & Gas Cons. Commission Anchorage MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ORIGINAL ) ) · TABLE OF CONTENTS 1 Witnesses: 2 FOR THE APPLICANT: DIRECT 3 Peter Flones 9 4 Kenneth Lemley 16 5 Terry Wilcox 31 6 7 8 9 10 11 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . . . ) ) PRO C E E DIN G S 1 (On record - 9:05 a.m.) 2 THE CHAIRPERSON: I would like to call this 3 hearing to order. Today is Thursday, August 16th, and the time 4 is approximately 9:05. We are at the AOGCC offices at 333 West 5 Seventh, Suite 100. The subject of today's hearing is BP's 6 application for pool'rules and area injection order for the 7 Northstar Oil Pool. I'd like to introduce here at the head 8 table the three commissioners. To my right is Dan Seamount. 9 To my very far left is Commissioner Julie Heusser. My name is 10 Cammi Taylor. To my very far right is Laura Ferro from Metro 11 Court Reporting. These proceedings are being recorded and 12 transcribed, and arrangements for copies of the transcripts can 13 be made directly with Metro Court Reporting. To my immediate 14 left is Rob Mintz. He's an assistant attorney general who is 15 here to advise the Commission on procedural and legal 16 questions. 17 A notice of public hearing was published in the 18 Anchorage Daily News on July 5, 2001. These proceedings will 19 be conducted in accordance with 20 AAC 25.540. We ask that the 20 Applicant present testimony first, and all persons wishing to 21 testify will be sworn. Each witness shall be asked to state 22 their name and who they represent. If they wish to give expert 23 testimony, we ask that you state your qualifications, and the 24 Commission will then rule on whether you qualify as an expert. 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 II . 15 16 17 18 19 20 21 22 23 24 25 . ') ) All others wishing to present testimony will be heard next. A 1 person wishing to make an oral statement will be allowed to do 2 so after the conclusion of all the testimony. We ask that a 3 person not ask questions of the witness directly, but if they 4 have questions in the audience that they would like to have 5 directed to a witness, that we ask that you provide that 6 question in writing along with your name and the name of the 7 witness that you would like the question directed to, and have 8 you provide that to one of the designated Commission staff 9 members. And we have several Commission staff here. In the 10 back of the room are Jack Hartz and Bob Crandall, and Jane 11 Williamson seated here in the middle. So if you have a written 12 question from the audience that you would like to have directed 13 to the head table, you could provide it to them and then pass 14 it up to us. Before the end of the hearing, the Commission will review the questions, and ask those it believes will be helpful in eliciting needed information. We would like to invite the Applicant to introduce themselves, and then we can proceed. MR. FLONES: My name's Pete Flones. I'm the program manager for Northstar. THE CHAIRPERSON: And who will you be having testify today? MR. FLONES: Ken Lemley. MR. LEMLEY: I'm Ken Lemley. I'm the geologist MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 4 5 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. it replaced with what we give today. I think it had claims of MS. DICKEY: No, the first draft we would like the draft testimony, is all of that then public testimony? THE CHAIRPERSON: Okay. And with respect to first filed. the confidential portion -- the confidential version that was claim of confidentiality, and we would ask to have it replaced, MS. DICKEY: The last one that was filed has no application. Do you have copy of that? It's on page 21. confidentiality except for one portion of the initial was filed on August 13th, there are no longer claims for confidentiality. As I. understand it, the last document that what would be -- whether there would be a request for subsequent discussion between our staff and your staff about requests for confidentiality held on that. We noticed some was filed on August 13th. Some of those initial documents had testimony on August 3rd, and then a subsequent document that came in two forms on June 25th, followed by a proposed draft of submitted. We have initially filed was an application that ask a clarification on some of the documents that have been Before we actually start taking testimony, perhaps if we could THE CHAIRPERSON: Good morning. Thank you. engineer for Northstar. MR. WILCOX: I'm Terry Wilcox, the reservoir for Northstar. ) ') 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 . . e 6 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. THE CHAIRPERSON: Okay. I think that takes MS. DICKEY: Withdrawn, the first one. Yeah. the testimony will also be withdrawn. THE CHAIRPERSON: Okay. We will do that. And MS. DICKEY: Yes. in the August 13th? applications that have the confidential portion and substitute minute. Would you like to withdraw then the first two THE CHAIRPERSON: Okay. If I could have just a MS. DICKEY: No. confidential? need a hearing -- any portion of the hearing to be THE CHAIRPERSON: So you don't plan today to which there are no claims of confidentiality. confidentiality have been replaced by the subsequent draft, for are confidential. But the first drafts that claimed Unless you ask questions that, you know, come up that 4 5 today? 6 7 today has 8 public. 9 removed all the confidential claims. It's all MS. DICKEY: The testimony we're submitting .... . testimony submitted THE CHAIRPERSON: MS. DICKEY: Yeah. new. . . . . THE CHAIRPERSON: Okay. And there will be confidentiality, too. ) ) 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 3 2 1 . . . e . . ) ) care of it. Thank you very much. We're ready proceed. Who's 1 going to start? 2 MR. FLONES: I'll start. My name is Pete 3 Flones. I am the Northstar Program Manager for BP Exploration 4 Alaska, Inc.. BP is the operator of the Northstar Unit on 5 behalf of itself and Murphy Exploration, Inc.. 6 This hearing has been scheduled in accordance with 20 7 AAC 25.520 and 20 AAC 25.540 in order to consider evidence 8 relevant to the establishment of pool rules and an area 9 injection order for the development of the Northstar Pool. 10 BP previously filed an application with numerous 11 exhibits and technical data. We would like to incorporate that 12 application into the record. 13 BP is requesting an order from AOGCC defining the 14 geographic area of the Northstar Pool, the stratigraphic 15 description of the NorthStar Pool, and the spacing rules for 16 development drilling in the Northstar Pool. In our 17 application, we have defined the Northstar Pool as the 18 accumulation of hydrocarbons in the Ivishak, Shublik, and Sag 19 River Formations common to and correlating with the interval 20 between the measured depths of 12,418 feet and 13,044 feet in 21 the Seal A-Ol well. 22 With regard to spacing, we seek to establish 40 acre 23 drilling units with authorization to drill into and produce 24 from any bottom hole location within the Northstar Pool without 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 7 . . . ) ) regard to section lines or lease boundaries within the unit. 1 We are also requesting an exemption from the standard 2 requirements for gas/oil ratios in order to conduct enhanced 3 oil recovery using miscible injectant. 4 BP also requested that the United States Mineral 5 Management Service approve gas reinjection and enhanced oil 6 recovery under its regulations. BP has coordinated its 7 submissions to AOGCC and MMS so that each agency receives the 8 same information and is cross copied on any request or 9 application to the other agency. Where there are any 10 difference between the requirements imposed by AOGCC and MMS, 11 BP will comply with the more stringent regulat~9n or statute. 12 We are not aware at this time of any instance where complying 13 with the regulatory requirements of anyone agency would 14 violate the requirements imposed by the other. 15 We also submit an application to the State of Alaska, 16 Department of Natural Resources, and the MMS requesting the 17 formation of the Northstar initial participating area. The 18 participating area application includes proposed tract 19 allocation factors. 20 The testimony we are presenting today is divided into 21 three parts. I will provide an overview of the project 22 facilities and the well operations. Ken Lemley will testify 23 about the geology of the Northstar Pool, and Terry Wilcox will 24 testify about the reservoir. We are asking that each witness 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Foul1h Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 8 9 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 A 17 18 19 20 21 22 23 24 25 . MET ROC 0 U R T R E P 0 R TIN G, INC. development and operation of Alaskan arctic oil fields. almost my entire career at BP working on the manager and field operations manager. I've spent BP since February of 1975 as an engineer project State of California since 1979. I've been employed by and have been a licensed mechanical engineer in the metallurgy from Washington State University in 1969, name is Pete Flones. I received a degree in physical Okay. My name is Peter Flones, F-l-o-n-e-s. Okay. My 16 qualifications? 15 name and spell it for the record, and then proceed with your 14 . THE CHAIRPERSON: Would you state your full 13 DIRECT EXAMINATION '~i" 12 on examination: 11 having been first duly sworn under Oath, testified as follows 10 PETER FLONES 9 MR. FLONES: I do. 8 (Oath administered) ',".f(.. 7 right hand, please? 6 THE CHAIRPERSON: Okay. Would you raise your 5 witness. 4 I'd now like to be sworn and qualified as an expert 3 exhibits. 2 respond to questions concerning our testimony and related 1 II be qualified as an expert, and each of us is prepared to ) ) 10 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 the Ivishak outline. 19 A 20 21 22 23 24 25 e MET ROC 0 U R T R E P 0 R TIN G, INC. discovered in 1983 by Shell during the drilling of project and facilities. The Northstar Oil Field was I now will provide an overview of the Northstar Northstar Unit. This map shows the Northstar unit with Okay, thank you. We have a outline here of the as an expert. Right. e A 14 15 16 17 18 THE CHAIRPERSON: We'll consider your testimony COMMISSIONER HEUSSER: No. THE CHAIRPERSON: Any objections? COMMISSIONER SEAMOUNT: I have no questions. 13 That's the area of your expertise? 12 THE CHAIRPERSON: As the program manager. 11 Northstar. . . . . 10 A No, I'm the program manager with -- for the 9 expertise for your testimony today is as a project manager? 8 THE CHAIRPERSON: And the subject of your 7 COMMISSIONER HEUSSER: No. 6 questions? 5 THE CHAIRPERSON: Do either of you have any 4 program manager for Northstar since 1998. 3 the development of the Badami field. I've been the 2 for the Endicott oil field, and the program manager for 1 . I was the project manager and field operations manager ') ') · tit tit ) ) the Seal A-01 well. The Ivishak Formation contains a 1 volatile sweet crude with oil gravities ranging from 43 2 to 45 api. Initial gas/oil ratios were -- were 3 approximately 2,200 standard cubic feet per stock tank 4 barrel. 5 The Northstar project is a self-contained 6 production facility on Seal Island. It is located six 7 miles offshore in the Beaufort Sea north of the Prudhoe 8 Bay Unit. Seal Island is a five-acre gravel island 9 constructed over the remains of an exploration island 10 built by Shell. The island and pipelines were 11 constructed in early 2000, and the permanent camp was 12 installed in the summer of 2000. The processing and 13 compression modules were recently moved from Anchorage 14 to Seal Island, and are being installed during August 15 and September of this year. We anticipate starting 16 production in October. 17 The Northstar project includes two pipelines 18 buried in a single trench from Seal Island to existing 19 onshore facilities. The Northstar oil pipeline is a 10 20 inch common carrier pipeline for the export of oil from 21 Seal Island to Pump Station 1 of the Trans-Alaska 22 Pipeline System'. The Northstar gas pipeline is a 10 23 inch pipeline for importing up to 100 million standard 24 cubic feet a day of gas from the central compressor 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 11 . . . ') ) plant at Prudhoe Bay Unit. The gas will be used to 1 fuel a processing facility and for enhanced oil 2 recovery. 3 This exhibit is a process flow diagram of the 4 production facilities. Exhibit 20 is the process flow 5 diagram showing the major components of the production 6 facility. The production facility will be capable of 7 handling 65,000 barrels of oil, 30,000 barrels a day of 8 produced water, and 600 million cubic feet per day of 9 injected gas. The processing facilities consist of 10 three primary modules. The first module constructed in 11 two halves contains the separation, gas dehydration, 12 and power generation equipment. The second module 13 contains the low and high pressure gas compression 14 equipment, and the third module contains the water 15 storage and disposal systems. 16 Exhibit 21 shows the general layout of the 17 island. A permanent camp of -- for up to 70 people has 18 been installed on the island. The camp facilities 19 includes emergency power generation, seawater 20 treatment, sewage facilities, and tanks for diesel fuel 21 and water storage. 22 The island is designed for 37 well slots. The 23 initial development consists of 16 production wells, 5 24 gas injection wells, and a Class I waste disposal well. 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 12 · · · ) ) Drilling began in December 2000, and to date, we have 1 drilled a disposal well, one gas injection well, and 2 two pre-produced gas injection wells. All the wells 3 drilled to date comply with the standard spacing 4 requirements imposed by AOGCC regulations. After the 5 facilities start up in October, development drilling 6 will resume and will continue into 2003. We will 7 access the island by ice road in winter. During the 8 summer open water period, we will use barges or supply 9 boats to access the island. We'll use -- we will use 10 helicopters to supplement seasonal access, and also as 11 primary access during thin and broken ice periods. 12 Production will be allocated based on 13 individual well tests and actual plant oil sales 14 volume. All production wells are individually 15 connected to test header. Each producing well will be 16 tested monthly to ensure accurate allocation of 17 produced fluids. We will continuously gather operating 18 data from the plant, wells, and test separator. 19 The Northstar project will follow BP's 20 corporate policy of minimizing flaring. The gas 21 injection plant and the gas injection well was planned 22 to be commissioned before the initial start of oil 23 production using gas imported from Prudhoe -- the 24 Prudhoe Bay Unit. We will reduce the amount of flared 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 13 14 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. COMMISSIONER SEAMOUNT: Mr. Flones, do you have COMMISSIONER HEUSSER: Okay. Thank you. A No. the reservoir? COMMISSIONER HEUSSER: But no gas injection in A Right. COMMISSIONER HEUSSER: For fuel gas, okay. A We'll be using it for fuel. actually going to start prior to oil production? hear you say that gas injection with gas from Prudhoe Bay is COMMISSIONER HEUSSER: I do. Mr. Flones, did I THE CHAIRPERSON: Do any of you have questions? testifies about geology? Are there any questions before Ken Lemley initial value at field start up. Bay. We will maintain reservoir pressure close to its from the Northstar pool and gas imported from Prudhoe miscible gas will be a blended mixture of gas produced leaner chase gas until the end of the field life. The approximately four years. After that, we will inject gas into the oil column of the Ivishak Formation for will inject a large slug of miscible enriched natural displacement to enhance oil recovery at Northstar. We new production facilities. We will use miscible fluid gas that is traditionally associated with start up of ) } 18 19 20 21 22 23 24 25 . 17 16 15 14 It 13 12 11 10 9 8 7 6 5 4 3 2 1 . 15 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 up oil production. e A 14 15 16 17 18 19 20 21 22 23 24 25 e MET ROC 0 U R T R E P 0 R TIN G, INC. THE CHAIRPERSON: Any other questions? I'm COMMISSIONER SEAMOUNT: Thank you. compression pre-commissioned and ready to go at start we're trying to sequence it where we can get our gas first, and then follow with your gas compression. And start up a field, and start the oil production section commissioning the compression unit. Oftentimes, you'll what we -- in our start up sequence, we'll be pre- go before we start oil production, so that's -- that's the compression trained, pre-commissioned, and ready to Yeah, we do that. We -- yeah, we -- we start up to get 13 that? 12 start up flare gas down. Do you have any special ways to do 11 you were going to do your best to keep the amount of flared -- I -- I think I'd have to get think it's -- I hate A 3 4 5 6 7 8 9 plans of 10 mitigation to try to keep -- you know, you said that off the top of my head. COMMISSIONER SEAMOUNT: Okay. And do you have can give you that number later. I -- I don't have it number, but do you folks remember what it is. I -.;.. we consult with some of my colleagues here to get the Yeah, we do have an estimate of that, and I'm -- I 2 start up flaring gas you're going to have to deal with? 1 II any estimate of what -- of how much you're going to -- how much ) 16 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 A 16 17 18 19 20 21 22 23 24 25 . MET ROC 0 U R T R E P 0 R TIN G, INC. business in 1995 from the University of Houston. I've Technology in 1984. I also received an MBA degree in geology from the New Mexico Institute of Mining and Sacramento in 1982, and a master of science degree in degree in geology from California State University at Northstar Field. I received a bachelor of science Kenneth Lemley. I'm the development geologist for the as an expert, in geology. Let's see. My name is geologist, and that's the area I'd like to be qualified Okay. My name is Kenneth Lemley, L-e-m-l-e-y. I'm a 15 expertise you wish to be considered an expert? 14 . proceed to describe your qualifications and in what area of 13 record your full name and spell your last name, and then 12 THE CHAIRPERSON: If you would state for the 11 DIRECT EXAMINATION 10 on examination: 9 having been first duly sworn under Oath, testified as follows 8 KENNETH LEMLEY 7 MR. LEMLEY: Yes, I do. 6 (Oath administered) 5 MR. LEMLEY: You bet. 4 your right hand, please? 3 THE CHAIRPERSON: Mr. Lemley, would you raise 2 MR. FLONES: Ken Lemley. 1 . sorry, who did you want to have testify next? ') '} 17 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 15 A 16 17 18 19 20 21 22 23 24 25 . MET ROC 0 U R T R E P 0 R TIN G, INC. TVDrkb in the Seal A-Ol type log. The base of the Sag River formation occurs at a depth of 10,650 feet the Northstar Pool which coincides with the top of the shale serves as the underlying bottom seal. The top of shale serves as the overlying top seal, and the Kavik Northstar Pool on the Seal A-Ol type log. The Kingak periods. Exhibit 4 illustrates the stratigraphy of the deposited during the Permian and Triassic geologic time Sag River, Shublik, and Ivishak Formations, and was Thank you. The Northstar Pool is contained within the THE CHAIRPERSON: Okay. Why don't you proceed? 14 . COMMISSIONER HEUSSER: None. 13 considered an expert? 12 THE CHAIRPERSON: Any objection to him being 11 COMMISSIONER SEAMOUNT: I have no questions. 10 COMMISSIONER HEUSSER: No. 9 commissions have any questions? 8 THE CHAIRPERSON: Do any of the other 7 Northstar Field and its geology. 6 Fields. My testimony will include an overview of the 5 years concentrating primarily on Badami and Northstar 4 the subsurface of the North Slope for the past four 3 the Texas Gulf Coast and Alaska. I have been working 2 Oil and Chemical for 15 years as a geologist working 1 e been with BP for one year. Previously, I was with Fina ) I:~ ../ . . . ) ) 1 Northstar pool which coincides with the base of the Ivishak occurs at a depth of 11,160 feet TVDrkb in the Seal A-Ol type log, with the interpreted oil-water 2 3 contact at 11,100 feet TVD subsea. 4 The Northstar Field consists of a faulted four 5 way structure. Our reservoir description of the 6 Northstar Pool is based on the 3-D seismic survey, 7 whole core, and well log data from the Seal A-I, Seal 8 A-2A, Seal A-3, Seal A-4, and Northstar 1 wells. A 9 total of 1,196.3 feet of Ivishak core was acquired from 10 these four wells. 11 Exhibit 6. Exhibit 6 is a structure map at the 12 top of the Ivishak, and illustrates the trapping 13 configuration. The structure consists of a faulted 14 anticline defined by three way dip closure to the east, 15 west, and south, with fault seal and/or dip closure to 16 the north. 17 Exhibit 7. Exhibit 7 shows two structural 18 cross sections. Cross section AA prime is a cross 19 section running from the southwest to the northeast 20 across the Northstar Pool. Cross section BB prime is a 21 cross section running from the northwest to the 22 southeast. These two cross sections also serve to 23 illustrate the trapping configuration of the Northstar 24 Pool. 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 18 e . . ) I will now discuss the Sag River Formation in 1 more detail. The Sag River Formation lies immediately 2 below the Kingak Formation and above the Shublik 3 Formation. The Sag River formation consists of a 4 series of transgressive marine sands, silts, and 5 shales, and is continuous throughout the area. The 6 sands within the Sag River represent a mineralogically 7 mature sandstone composed of quartz with minor amounts 8' of feldspar and authigenic clays. Calcite, silica, and 9 siderite are the primary cementing agents. 10 The Sag River is approximately 100 feet thick 11 in the vicinity of the Northstar Field. The core plug 12 permeability values range from .01 to 28 millidarcies, 13 with a mean value of .86 mean millidarcies. The mean 14 core porosity is 13 percent with a minimum and maximum 15 range of 6.8 to 22.8 percent, respectfully. We 16 generated the average log derived porosity from the 17 density log using an average grain density of 2.73 18 grams per cubic centimeter. The log porosity results 19 averaged 16 to 18 percent in the pay interval. We 20 estimated permeability from a core drive porosity and 21 permeability relationship. We estimate the likely 22 permeability range to be from 1 to 4 millidarcies in 23 the pay intervals. No well or production tests are 24 available for comparison with the core data. We 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 19 It . . ) ) consider porosities greater than 16 percent and 1 permeabilities greater than 1 millidarcy to be pay. The 2 net to gross ratio varies from 15 to 20 percent 3 utilizing these cut offs. Water saturations within the 4 Sag River Formation range from 50 to 65 percent, and 5 the Archie parameters that were used in calculating 6 water saturations were m=2.071 and n=2.0. We estimate 7 the original oil in place for the Sag River to be 37.7 8 million barrels and 52.1 BCF. 9 We created isopack maps for the Sag River and 10 Shublik using existing well control. We determined 11 porosity, water saturation, and net to gross ratios for 12 the Sag River from well log and core data analysis. We 13 then combined these data to determine the original oil 14 in place for the Sag River. We observed oil and gas 15 shows from the Sag River in the mud logs in the Seal A- 16 I, Seal A-2A, and Seal A-3 wells. No oil or gas shows 17 were present in the Seal A-4. We estimated water 18 saturation calculations within the Sag River from well 19 logs. We obtained Archie water saturation parameters 20 from analog Sag River data available in the Milne Point 21 area located approximately 10 miles to the southwest. 22 At present, we do not have any capillary pressure 23 measurements in the Sag River Formation to confirm the 24 log derived saturation model. Currently, there is no 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 20 It . . ) well test in the Sag River Formation to demonstrate its 1 producibility. 2 Next, I will discuss the Shublik Formation. 3 The Shublik Formation lies immediately below the Sag 4 River Formation of Triassic age, and uncomformably 5 overlies the Ivishak Formation of Permian and Triassic 6 age. The Shublik Formation consists of marine silts, 7 shales, sands, and phosphatic limestones, and is 8 continuous throughout the Northstar Pool area. The 9 Shublik Formation is divided into four lithologic 10 units. Marine silts and shales in the Shublik A unit 11 grade downward into phosphatic limestones in the 12 Shublik B, and then into interbedded silts and shales 13 in the Shublik C, and finally into fine and very fine 14 grain sands in the Shublik D units. Calcites, silica, 15 siderite, and pyrite are the primary cementing agents 16 within the Shublik Formation. 17 The Shublik 'Formation is approximately 85 feet 18 thick in the vicinity of the Northstar Pool area. The 19 Shublik A unit is approximately 35 feet thick. The 20 Shublik B unit is approximately 10 feet thick. The 21 Shublik C unit is approximately 30 feet thick, and the 22 Shublik D unit is approximately 10 feet thick. The 23 whole core porosity and permeability data suggests that 24 most of the Shublik is tight and non-reservoir with the 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 21 . . . ) ) exception of the Shublik D unit. Permeability is 1 generally less than one millidarcy and porosity less 2 than 10 percent. However, porosity and permeability 3 measurements as high as 16.3 percent and 100 4 millidarcies occur in a few instances in thin 5 discontinuous intervals of less than three inches. 6 These thin intervals are not resolvable on well logs, 7 and usually add up to less than two feet. The Shublik 8 D unit was combined with the Ivishak reservoir in a 9 static reservoir model. 10 Core data across the Shublik Formation exists 11 in the Northstar 1 and the Seal A-2A wells. Core 12 porosity and permeability data suggest that most of the 13 section is tight and non-reservoir with the exception 14 of zone D. It is difficult to determine water 15 saturation within this section using conventional 16 analysis and well logs due to the presence of pyrite, 17 which suppresses the induction log and gives 18 anomalously high water saturation estimates. A well 19 test and core fluorescence in Northstar 1 suggests that 20 the Shublik may be gas bearing at that location. 21 Finally, I will discuss the Ivishak. The 22 Ivishak Formation lies unconformably below the Shublik 23 D unit of Triassic age, and conformably above the Kavik 24 Formation of Permian age. The Ivishak is continuous 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 22 .' . . ) throughout the Northstar Pool area. The Ivishak 1 consists of delta front sands and shales grading upward 2 to fluvial sands, and finally, into medium to course 3 grain pebbly conglomerates. The Ivishak is 4 approximately 325 feet thick in the vicinity of the 5 Northstar Pool. The Ivishak reservoir is divided into 6 an upper conglomeratic unit, and a lower sandy unit. 7 The upper conglomeratic unit is approximately 8 225 feet thick, and is characterized by a bimodal grain 9 sized distribution consisting of mostly chert and 10 quartz class, with minor amounts of silt and quartz 11 grains comprising the matrix material. The 12 conglomeratic unit has varying amounts of microporous 13 chert grains as part of the framework. Calcite, 14 silica, and siderite are the primary cementing agents. 15 The lower sand unit is approximately 100 feet thick, 16 and consists of medium to course grain sand with minor 17 amounts of silt and shale. This lower unit is present 18 below the oil-water contact throughout most of the 19 field area. Calcite, silica, and siderite are also the 20 primary cementing agents present within the lower sand 21 unit. The Ivishak reservoir at Northstar is more 22 proximal, courser grained, more deeply buried, and 23 cemented than the Ivishak reservoir in Prudhoe Bay, 24 leading to lower average porosities and permeabilities. 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 23 It . . ) )- Extensive routine porosity and permeability 1 measurements were available from four wells. Seal A- 2 01, Seal A-2A, Seal A-3, and Northstar 1. 3 Permeabilities established from drill stem 4 tests are higher than average permeability values from 5 core. This may be a result of rubble sections existing 6 in the reservoir that were not representatively sampled 7 from the cores that were obtained. The two dominant 8 facies, conglomerates and sandstones, have different 9 reservoir properties, and subsequently, different 10 porosity and permeability trend relationships. The 11 conglomerate facies studied by Shell in core 12 laboratories, have an average porosity of nearly 14 13 percent, while the sandstones have an average porosity 14 of nearly 18 percent. These studies also indicated 15 that the volume fraction of microporosity increases as 16 one moves downward in the reservoir section. 17 Our analysis of pressure and production data 18 indicates an absence of vertical permeability barriers 19 within the Ivishak. The kV/kH ratio is nearly 1, and 20 the presence of cemented intervals does not appear to 21 be laterally extensive. A sensitivity study of the 22 impact of the insitu confining stress on porosity and 23 permeability indicates that porosity loss was minimal, 24 3 percent loss, whereas the reduction of permeability 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 24 . . . ) ) was more significant, 14 to 21 percent loss. The mean 1 stress corrected core porosity for the Ivishak 2 Formation above the oil-water contact is approximately 3 15 percent. Core permeability ranges from 0.01 to 808 4 millidarcies, with the mean stress corrected value of 5 53 millidarcies. 6 We made net to gross estimates using a combined 7 Y shale cutoff of 50 percent, and 10 percent porosity 8 cutoff for sandstones, and an 8 percent porosity cutoff 9 for conglomerates, which equates to a1 millidarcy 10 permeability cut off. The reservoir has a very high 11 net to gross ratio of 93 to 95 percent. We determined 12 that the average oil saturation was 42 percent for the 13 reservoir at the reservoir volumetric centroid of the 14 field. The volumetric centroid of the reservoir is 80 15 feet above the oil-water contact at 11,100 foot TVD 16 subsea at 11,020 foot subsea. We estimate that the 17 maximum oil column ranges from 270 to 300 feet. We 18 derived the equation for the reservoir water saturation 19 used in the static geologic model from the regression 20 analysis of the porous plate, mercury air, and 21 centrifuge capillary pressure data, from the core in 22 the Seal A-2A well. We determined the Archie water 23 saturation parameters from electrical property 24 measurements on 35 core samples. 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 25 . . . ') ) The average M value for the conglomerate was 1 2 2.06. The average M value for the sandstones was 1.92. The average N value for the conglomerates was 2.90. The average N value for the sandstones was 2.68. We 3 4 determined that water resistivity was 0.10 ohm meters 5 at 247 degrees Fahrenheit based on a formation water 6 sample of 19,340 parts per million sodium chloride from 7 the Seal A-1 well. 8 My next topic is faulting at Northstar. 9 Evidence for faulting, fracturing, and deformation from 10 the whole core at Northstar was very minor. There were 11 less than 30 total observations of fracturing, 12 faulting, or other styles of deformation in nearly 13 1,200 feet of whole core. Pressure build up analysis 14 from several wells found no evidence of production 15 barriers surrounding existing appraisal wells even 16 though they are relatively close to mapped faults. RFT 17 and pressure data from the Seal A-2 and Seal A-1 18 indicate that these wells are in pressure communication 19 within the Ivishak Formation. 20 Maximum vertical displacements along faults 21 within the field area as interpreted from the 3D 22 seismic data are less than 200 feet, which is 23 significantly less than the average reservoir thickness 24 of 325 feet. We interpreted faults at Northstar to be 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 26 . . . ,) neutral with respect to reservoir performance given the 1 high net to gross ratios observed, the lack of 2 deformation observed in the core data, and the 3 inability to determine reservoir boundaries from build 4 up data. 5 A testing and reservoir surveillance program, 6 including pressure measurement from RFT or MDT, 7 injection gas tracer analysis, and geochemical analysis 8 will be implemented to address the relative importance 9 of faulting and reservoir compartmentalization more 10 completely during development. 11 My next topic is fluid contacts. We estimated 12 the Northstar oil-water contact at 11,100 feet TVD 13 subsea, primarily from Seal A-I and Seal A-2 core oil 14 stains, RFT and MDT pressure analysis, and a well test 15 directly above the oil-water contact in the Seal A-I. 16 A test below 11,100 feet TVD subsea in Seal A-3 and 17 Seal A-2A indicated water production. No oil-water 18 contact was observed in the Seal A-4 well. Oil-water 19 contact is not obvious on any of the Seal well logs, 20 with the exception of Northstar 1, as the well log 21 calculated water saturation numbers are in general 22 quite high near the oil-water contact. This is because 23 of the significant amount of bound water in the 24 microporosity. Additionally, the pressure gradient 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 27 . . . 'I ) analysis of the RFTs run in Northstar 1, NS 27, and NS 1 31, also indicates an oil-water contact' at 11,100 feet 2 TVD subsea. 3 I will now discuss the confining intervals. 4 The Northstar pools confined below by the Kavik 5 Formation and above by the Kingak Formation. The Kavik 6 formation is continuous throughout the area. It is 7 interpreted to be a marine shell sequence of Permian 8 age. The Kavik rests unconformably on the 9 carboniferous aged Lisburne group. The Kavik Formation 10 is extremely impermeable, with a thickness of 11 approximately 100 feet in this area, and serves as a 12 lower confining zone. 13 The Kingak Formation is continuous throughout 14 the area, and conformably overlies the Sag River 15 Formation. The Kingak Formation was deposited as 16 marine shales and silts during the Jurassic period, and 17 is extremely impermeable. The Kingak Formation is 18 approximately 1,000 feet thick in the area, and serves 19 as the upper confining zone. 20 We used the geological information I just 21 described to construct the static geologic model. For 22 our model, we divide -- we subdivided the upper 23 conglomeratic unit of the Ivishak into five subunits, 24 and included the Shublik D within the upper 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 28 · e e ì ) conglomeratic unit in the Ivishak. We subdivided the 1 lower sandy unit of the Ivishak into three subunits. We 2 then constructed isopack maps, porosity maps, net to 3 gross ratio maps, and permeability maps for each of 4 these subunits within the Ivishak horizon. We created 5 the structure map for the top of the static model by 6 adding the structure map derived from the 3D seismic 7 interpretation at the top of the Sag River to the inner 8 isopack between the Sag River and the top of the 9 Shublik D. We then sequentially added together 10 subsequent interval isopack maps to create the 11 structural model. We then back interpolated each of 12 these reservoir maps to generate a series of grids at 13 100 foot increments. We calibrated all map grids, and 14 the structure and reservoir properties to existing well 15 control. 16 The core water saturation measurements were not 17 suitable for calibrating to well log derived water 18 saturation results because the cores from the Seal and 19 Northstar wells were not acquired with low invasion oil 20 based mud. Traditional well log derived saturation 21 methods were complicated by the presence of significant 22 amounts of microporous chert. Given the problems 23 associated with well log derived saturation model, we 24 generated an equation representing the water saturation 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 29 30 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. COMMISSIONER HEUSSER: Not at this time. Thanks. have any questions? THE CHAIRPERSON: Commissioner Heusser, do you questions at this time. Thank you. COMMISSIONER SEAMOUNT: I don't have any provides testimony about the reservoir? testimony. Are there any questions before Terry Wilcox That concludes the geologic part of our simulator. for the construction of the dynamic reservoir the structure of the Northstar pool, and are the basis The static geologic models were used to define agreement. pressure derived water saturation model are in close derived water saturation model and the capillary sample taken from Seal A-1. In general, the log shows the chemical composition of the formation water sodium chloride from the Seal A-1 well. Exhibit 13 formation water sample of 19,340 parts per million We determined water resistivity, Rw, based on a pressure measurements. using a multiple regression analysis of 131 capillary free water level for both conglomerates and sandstones for the reservoir as a function of height above the J ) 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 e e . 31 745 West Fourth Avenue, SuÏJe 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. engineer for the Northstar field. I received a A 19 20 21 22 23 24 25 petroleum engineering from LSU in 1982. I have worked for BP as a reservoir engineer on North Slope reservoirs for the last 13 years. Previously, I worked University in 1979, and a master of science degree in bachelor of science in civil engineering from Auburn My name is Terry Wilcox, W-i-l-c-o-x. I am a reservoir 18 for the record, and then give us your qualifications? 17 ahead? Why don't you state your full name and spell your name 16 Okay. Why don't you go In what area? 12 A Yes. 13 . THE CHAIRPERSON: 14 A Reservoir engineer. 15 THE CHAIRPERSON: as an expert? 11 THE CHAIRPERSON: And you wish to be qualified 10 DIRECT EXAMINATION 9 on examination: 8 having been first duly sworn under Oath, testified as follows 7 TERRY WILCOX 6 MR. WILCOX: Yes. 5 (Oath administered) 4 please. 3 THE CHAIRPERSON: Raise your right hand, 2 MR. WILCOX: Yes. I'd like to be..... 1 . THE CHAIRPERSON: Thank you. You'll be next? ) · · 14 15 16 17 18 19 20 21 22 23 24 25 · ') ) 7 years for Exxon as a reservoir engineer on Gulf Coast 1 oil and gas condensate reservoirs. I'm a licensed 2 petroleum engineer with the State of Florida since 3 1985. I have worked on Northstar since May of 2000. 4 THE CHAIRPERSON: Are there any other questions 5 about his qualifications? 6 COMMISSIONER SEAMOUNT: I have no questions. 7 And I don't have an objection. 8 COMMISSIONER HEUSSER: I have no questions. 9 And no objection. 10 THE CHAIRPERSON: We'll accept you as an 11 expert. 12 A Thank you. First, I'd like to discuss our estimates of 13 hydrocarbons in place. Our geological model incorporates well control, stratigraphic and structural interpretation, and rock and fluid properties. Our model results indicate original oil in place of 247 million stock tank barrels. A seven billion cubic foot inferred gas cap occupying one percent of the hydrocarbon pore volume, and 480 billion cubic feet total gas including solution gas. We believe that structural interpretation has the greatest impact on uncertainty in original oil in place. There is also uncertainty in determining the volume of oil field intergranular porosity versus water filled MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 32 . . . ') ) microporosity, and in the fluid PVT properties. 1 Now, I'll talk about the reservoir pressure and 2 temperature. The initial pressure of the Northstar 3 pool at 11,100 feet TVD subsea, which is the oil-water 4 contact, was 5,305 pounds per square inch gauge. We 5 estimate average reservoir temperature to be 254 6 degrees Fahrenheit at the oil column centroid. 7 Reservoir pressure appears to have declined by 8 about 125 psi since the exploration wells were drilled 9 in 1984 through 1986. Average reservoir pressure at 10 the oil-water contact is now 5,180 psig based on RFT 11 and MDT pressure measurements in NS 27 and NS 31, the 12 development wells drilled earlier this year. Our 13 current interpretation is that this pressure drop is a 14 consequence of the pressure decline in the Prudhoe Bay 15 Ivishak reservoir, which we believe is in hydraulic 16 communication with the Northstar Ivishak reservoir 17 through the aquifer. Right now, the reservoir pressure 18 appears to be about 80 psi above the bubble point 19 pressure at the centroid of the oil column. The lower 20 150 to 225 feet of the reservoir appear to be at 21 pressures exceeding bubble point pressure, while the 22 upper portion of the reservoir may have dropped below 23 bubble point pressure. A small amount of gas in the 24 region below bubble point pressure may have formed a 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 33 e . . ) ) critical gas saturation or migrated to the structurally 1 higher areas of the reservoir. 2 I'll now address our fluid PVT data. PVT 3 analysis was performed on recombined surface samples 4 from Seal A-I, Seal A-2A, Seal A-3, and the Northstar 1 5 wells. Our analysis indicates a slight oil 6 compositional gradient with oil density increasing with 7 depth. Oil gravity averages 44 degrees api. The 8 solution gas/oil ratio averages 2,200 standard cubic 9 feet per barrel. The oil formation volume factor 10 averages 2.2 reservoir barrels per stock tank barrel. 11 The oil viscosity averages .14 centipoise. 12 Our analysis of the bubble point pressure 13 versus depth from the Seal A-I well indicates the 14 reservoir maybe saturated near the crest of the 15 structure with a gas-oil contact inferred to be located 16 at 10,839 feet TVD subsea. This inferred GOC has not 17 been verified by drill wells. Several feet of gas were 18 present in the top of the reservoir in the Shublik D 19 zone in the Northstar 1 well. The gas elevated the GaR 20 to 5,300 SCF per stock tank barrel in the well test in 21 which the upper 30 feet of the well was perforated. 22 These perforations include the Shublik D in addition to 23 the upper Ivishak E. This gas appears to be isolated 24 from other upstructure Ivishak wells in which free gas 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 34 e e e ) ) was not present. There is no evidence of a heavy oil 1 tar zone in the Northstar Ivishak reservoir. We have 2 run one slim tube experiment with oil from the 3 Northstar 1 well to verify miscibility. This 4 experiment achieved a 98.7 percent recovery efficiency 5 at 1.2 pour volume gas injection. 6 PVT quality bottom hole fluid samples were 7 taken in late May 2001, with the MDT tool from the 8 Northstar 31 well. The oil samples taken near the oil 9 column centroid will be used in PVT studies to 10 determine bubble point pressures and compositions, and 11 for further slim tube experiments to verify 12 miscibility. Slim tube simulations indicate the oil 13 compositional gradient has a negligible impact on 14 minimum miscibility pressure. 15 I will now describe our reservoir models in 16 more detail. We constructed reservoir models of the 17 Northstar pool to evaluate development plans, and 18 options to investigate reservoir management practices, 19 and to generate rate profiles for facility design. We 20 constructed a three dimensional full field model and a 21 finer grid mechanistic models. The models are 22 compositional, utilizing either a 10 or 15 component of 23 equation of state. The 3D compositional full field 24 model covers the entire Ivishak reservoir and the 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Founh Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 35 · · · ì\ -' ') surrounding aquifer. The Sag and Shublik Formations 1 except for the Shublik B sand were not included in the 2 reservoir simulation. The full field model has 400 3 foot or a 3.78 acre grid box over the oil column with 4 2,000 feet or 92 acre grid blocks over the surrounding 5 aquifer. 6 There are 18 vertical layers with grid block 7 thickness averaging 15 to 30 feet. We included faults 8 in the model through corner point geometry, and 9 considered them to be neutral with respect to flow. We 10 used a capillary pressure equation relating porosity 11 and height above the oil-water contact to predict 12 initial water saturation. We obtained grid block 13 values for porosity, permeability, net to gross, and 14 isopack layer thickness by back interpolating grid 15 block coordinates against the static model. 16 We used very finely gridded mechanistic one 17 dimensional models to study miscible displacement 18 aspects of the flood. We have run one slim tube 19 experiment with oil from Northstar 1 to verify 20 miscibility. The experiment was used to validate the 21 equation of state by history matching the slim tube 22 results. We have additional slim tube experiments 23 under way using oil samples taken from a recent 24 development well. 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourlh Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 36 · · · ') We also developed mechanistic finer grid 3D 1 partial field models. These studies are being used to 2 investigate water coning, 4orizontal versus vertical 3 well performance, and to validate the courser grid full 4 field model. The full field model is in the process of 5 being updated to incorporate the revised geological 6 model which is being modified to include the results of 7 the development wells drilled to date. 8 I will now describe the process we used to 9 select the enhanced oil recovery program. We evaluated 10 miscible gas injection along with waterflood, gas 11 cycling, and primary depletion scenarios. All of the 12 cases run on our model use the same number of wells and 13 locations. We controlled injection to maintain 14 reservoir pressure near original for the miscible gas 15 and waterflood cases, with pressure declining in the 16 gas cycling and primary depletion cases. Total 17 hydrocarbon liquid recovery for the miscible gas 18 injection case was 176 million barrels. The waterflood 19 case produced 135 million barrels. The gas cycling 20 case, 136 million barrels, and primary depletion 21 produced 94 million barrels. We also evaluated water 22 alternating with gas injection but the model runs 23 indicated no additional recovery. 24 We selected miscible gas injection because it 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 37 . . . ) resulted in significantly higher recovery efficiency. 1 We forecast that recovery with miscible gas injection 2 is 12 to 14 percent OOIP higher than either gas cycling 3 or waterflood. We are implementing miscible gas 4 injection concurrent with drill start up in order to 5 get maximum benefit. 6 We evaluated three field production rate 7 scenarios with average oil off takes rates of 65, 72, 8 and 90 thousand stock tank barrels per day. The 9 ultimate oil recoveries determined from these model 10 runs were not sensitive to field production rate. The 11 higher offtake cases did slightly better due to 12 producing and injecting greater volumes of gas to the 13 reservoir early in field life before gas handling 14 facility limits were reached. 15 We also have options for additional reserves 16 within the Northstar unit. We are currently limited to 17 drilling extended reach wells with bottom hole 18 locations, no more than approximately 17,500 feet from 19 the production island. Because of this limit, 20 21 approximately seven to eight million barrels of oil remain in the northwest portion of the reservoir at the end of field life if no further development drilling is 22 23 carried out. We expect that with the experience from 24 our initial program, and with advances in drilling 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 38 e e . ) ) technology, we will be able to tap the seven to eight 1 million barrel potential at the end of the current 2 drilling program. 3 We also recognize that satellite oil 4 accumulations may exist within expected drilling reach 5 6 from the island. These targets will be the subject of additional appraisal. 7 I will now discuss current development plans. 8 The Northstar current development provides for drilling 9 21 new wells on an average well spacing of about 400 10 acres. Five of the wells are planned as miscible gas 11 injectors with 16 oil producers. The injectors are 12 located in the central thicker oil column portion of 13 the reservoir to maximize miscible sweep efficiency in 14 areas that contain the greatest OOIP. Two of the 15 injectors will be pre-produced to help load the 16 production facility at startup. The current 17 development plan calls for drilling the peripheral 18 producers as high angle wells which allows e-line or 19 slick-line access for routine surveillance. 20 Miscible injectant is made by blending gas 21 imported from Prudhoe Bay Unit with gas produced at 22 Northstar. NGLs are left in the produced gas during 23 the miscible injection phase of the project by not 24 running the refrigeration unit of the NGL plant. The 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, SuÏ1e 425 Anchorage, Alaska 99501 (907) 276-3876 39 · · · ) ) make up gas from PBU acts to maintain reservoir 1 pressure which maintains miscibility. We currently 2 anticipate that NGLs will be left in the produced gas 3 for the first four years of the project. The miscible 4 gas injectant phase will be followed up by leaner chase 5 gas injection for the remainder of the oil production 6 phase of field life. I need to add that one of the 7 objectives of the slim tube studies currently under way 8 is to determine if miscibility can be achieved if the 9 NGLs, which are mostly C5s and heavier, are removed 10 from the -- from the miscible injectant. Let me 11 clarify that. We're looking to see if we can leave 12 remove the C5 and heaviers from the miscible injectant, 13 and put -- put them into the -- into the oil export 14 line. Our current ID simulation studies indicate that 15 the NGLs can be removed while still maintaining 16 miscibility. 17 Water coning at Northstar is an area of 18 uncertainty due to the apparent absence of barriers to 19 vertical flow. We are currently evaluating horizontal 20 peripheral wells as a possible option. To help 21 evaluate water coning issues, we plan to take RFT 22 pressure data and the wells drilled after field start 23 up to determine if there are vertical cement barriers 24 present in the reservoir which may act to reduce water 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 40 . . . 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 \ ) coning. Recent model runs indicate that with sufficient stand off from the oil-water contact, water production should remain below the 30,000 barrels of water per day facility limit. My next topic is our reservoir management strategy. The objective of the reservoir management strategy is to maximize ultimate recovery of oil consistent with sound engineering practice. We will manage reservoir pressure at Northstar in order to insure miscibility, to minimize oil losses due to shrinkage from producing below bubble point pressure, and to achieve some aquifer influx to sweep the periphery and structurally low areas. To monitor reservoir pressure, we propose to measure it in at least half the available wells each year. We are currently planning to run real time bottom hole fiber optic pressure gauges in our producing wells. If the application of this new technology is successful, we may be able to monitor the reservoir pressure even more frequently. During the miscible phase of the project, which is expected to last the first four years of field life, we plan to voidage replace 100 percent of total production to maintain the initial reservoir pressure at field start up. However, during the first year of MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 41 · · · ) ) the project, we would like to maintain the option of 1 exceeding 100 percent voidage replacement to ensure 2 miscibility and compensate for some of the prior and 3 anticipated pressure declines. To maintain operational 4 flexibility during the miscible phase, we plan to 5 operate within a 50 psi average reservoir pressure 6 range around the pressure found at flood start. Even 7 with 100 percent voidage replacement, reservoir 8 pressure may decline assuming continued pressure 9 depletion through Ivishak aquifer. 10 To prevent hydrocarbons from being displaced 11 into the aquifer, we will not increase the average 12 reservoir pressure appreciably above its initial value. 13 Most of the reservoir is underlain by bottom water, and 14 15 there is also a large oil water contact periphery. Locating the injection wells in the thick oil column areas of the reservoir which have low oil water 16 17 contacts will help to minimize oil pushed into the 18 aquifer beneath injectors due to local pressure 19 gradients. 20 After the miscible phase of the project, there 21 may be benefit from dropping reservoir pressure below 22 the initial value to achieve natural water influx 23 around the periphery of the reservoir and low in the 24 oil column. The lower portion of the reservoir is not 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 42 43 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 A 21 22 23 24 25 · MET ROC 0 U R T R E P 0 R TIN G, INC. figure out how to spike them into your oil line, that's miscibility without the presence of NGLs, that once you correctly hear you say that you could maintain COMMISSIONER HEUSSER: Okay. And did I They -- they could potentially be the Kuparuk interval. 20 pools from Northstar. What might those be? 19 Mr. Wilcox, you mentioned the possible development of satellite 18 COMMISSIONER HEUSSER: I have several. Okay. 17 commissioners have questions for Mr. Wilcox? 16 THE CHAIRPERSON: Do either of the 15 there any questions for me or the other witnesses? 14 · This concludes our formal presentation. Are 13 ratio requirements. 12 flexibility, and an exemption from the standard gas-oil 11 we are requesting 40 acre spacing for maximum 10 provided in our application and -- and at this hearing, 9 volume from blow down. Based on the information 8 injected gas. We have not yet determined gas recovery 7 reduce reservoir pressure to maximize recovery of the 6 Late in field life during blow down, we will 5 by the miscible flood. 4 influx to sweep areas that are less efficiently swept 3 Allowing a decline in reservoir pressure allows water 2 gravity segregation of the gas within the oil column. 1 · as sufficiently swept by the injected gas due to ) 44 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 minimum miscibility pressure. . A 14 15 16 17 18 19 20 21 22 23 24 25 e METRO COURT REPORTING, INC. COMMISSIONER HEUSSER: Okay. I heard you talk tube studies are looking at are exactly what is the was to start with. Again, this is -- what the slim planning to operate within 50 psi of what -- what it the early part of this project, so we -- but we're we're wanting to build pressure slightly during the planning to maintain pressure. If anything, we're -- why we're not planning to let the pressure drop. We're we're fairly close to bubble point pressure, and that's fairly close to the bubble point pressure, and we think The minimum miscibility pressure is -- we think it's 13 miscibility pressure be? 12 COMMISSIONER HEUSSER: What would the minimum 11 right on that point. what you intend to do? . 1 A 2 3 4 5 6 7 8 9 10 with some experimental data just to make sure we're project. But before we do that, we want to verify that NGLs out, and therefore, we think we can get maximize recovery by taking the NGLs out and selling them rather than injecting them for the miscible enough that it would be miscible even if we take these The gas appears -- the -- the oil appears to be light can extract these NGLs and still maintain miscibility. Well, we're running a slim tube test to verify that we ) tit 5 6 7 8 9 10 11 12 13 tit 14 15 16 17 18 19 20 21 22 23 24 25 tit ') ) that or say that later in the field life, you anticipate 1 reducing injection and reducing the reservoir pressure and 2 allowing the aquifer to kind of come on in and potentially move 3 some hydrocarbons that way. 4 A Yes. COMMISSIONER HEUSSER: How does the -- your understanding of the North Slope aquifer compare to that of the Prudhoe Bay aquifer, which I think I heard you say these were - - they were basically in communication with each other? Northstar aquifer rather, excuse me. A We think the -- the Ivishak aquifer at Northstar does connect up to the Ivishak aquifer at Prudhoe Bay, and although they are some large faults between Prudhoe Bay and Northstar, we think they do pressure communicate, and the first part of your question about dropping pressure later in field life, the miscible project because you're injecting gas and it intends to go towards the upper part of your reservoir due to the density difference between the oil and gas, we would get some benefit by allowing aquifer to come in slightly around the edges and sweep those lower portions of the reservoir that the gas tended to miss. And we also plan to, assuming we have a gas market, you know, at the end of the -- the field life of the oil phase of the project, we'd like to drop reservoir MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 45 e 1 2 3 4 that is 5 ) ) pressure and blow down the reservoir and recover that gas. If there is no gas market for it though, that option may not be available to us. COMMISSIONER HEUSSER: Question about the water 6 appears to be substantial. There was a table in here. How do expected to be produced from this reservoir. It you intend to handle that produced water? 7 A The produced waters, we have a 30,000 barrel a day water handling facility, and it's going to be disposed 8 9 10 11 12 13 . 14 15 16 of, and -- and the -- we have a disposal well that has been drilled that can handle that amount of water. Ken, the -- Ken can tell you what interval the disposal well was completed in. MR. LEMLEY: Yeah. The disposal well is completed in the Schrader Bluff Formation. COMMISSIONER HEUSSER: Okay. So you don't intend to put any water back into the reservoir sands? 17 A 18 19 20 21 22 23 24 25 . Not at this point in time. We - - we did look at a water alternating with gas flood similar to Prudhoe Bay and Kuparuk, but the water injection did not really add anything to reserves. I think that's based on our current geologic description. It's a -- essentially, a big pile of gravel with no -- no vertical barriers. Now if it turns out we're wrong and there are significant vertical barriers and there's thieves (ph) in the MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 46 . 1 2 3 4 5 6 7 8 9 10 11 12 . A 17 18 19 20 21 22 23 24 25 . ) reservoir, then the water could act to reduce gas channeling through the thieves, and and so we're going to keep our eyes open and as we bring this reservoir on and learn as much as we can, and perhaps there could be some benefit to water injection. We currently don't think there are benefits. But we're open to letting the reservoir talk to us and confirm that. COMMISSIONER HEUSSER: Back to the Northstar aquifer being in communication with the Prudhoe Bay field aquifer, and I believe I heard you say that since the Seal Island wells were drilled in the mid '80s, there's been a -- somewhat of a pressure decline. And so that begs the question 13 of how do you intend to evaluate the effect of Prudhoe Bay 14 pressure decline both before and after major gas sales should 15 that occur on the performance of the Northstar reservoir? 16 The -- the pressure decline, you know, it hasn't been extensive. It's been about 125 psi where as Prudhoe Bay has declined over 1,000 psi. So the connection between the two fields is not extremely good, or we'd have had extensive pressure decline at Northstar. As Prudhoe Bay continues to decline, you know, we might see continued pressure decline here at Northstar, but it's not going to be as much as at Prudhoe Bay. So, you know, they had over 1,000 psi pressure decline, and MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 47 48 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. What we would like to do at this time is take about a any questions from the public? Have any of our designated commission staff received wish to make a statement at this time? Are there any members of the public who are here that present today that wish to provide testimony? haven't seen the sign ~n sheet. Are there any other people THE CHAIRPERSON: Let me check at this time. I questions have been answered. Thank you. COMMISSIONER SEAMOUNT: I think all my more questions. COMMISSIONER HEUSSER: Thank you. I have no periphery where the producers are producing. and pressure will be down a little bit out on the build pressure in the central part of the reservoir, producers are out on the periphery. So we'd like to interior, thick part of the reservoir, and the pattern is set up, the injectors are in the central reservoir where most of our reserves are. The way the build some pressure in the central area of our on in this project to over-inject just a little bit to And, you know, again, that's why we're planning early point on our oil, and that we're miscible with our gas. still think for the most part we're above our bubble we've only experienced 125 psi pressure decline. We ) ") · 25 24 23 22 21 20 19 18 17 16 15 14 · 13 · 1 2 3 4 5 6 7 8 9 10 11 12 49 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. options, did you consider aquifer injection? When you were evaluating your various pressure maintenance COMMISSIONER HEUSSER: I have just a couple. THE CHAIRPERSON: Okay. Commissioner Heusser? questions. Thank you. COMMISSIONER SEAMOUNT: I have no further A Up to 100 million a day. COMMISSIONER SEAMOUNT: At what rate? A It's about 400 billion cubic feet. for this project? quick ones. What's the total amount of gas you plan to import COMMISSIONER SEAMOUNT: I just have a couple of would like to begin? few additional questions from the Commission. Which one of you questions submitted to us to pass on, but I believe there are a here to testify or to make statements. There were no written We have no additional members of the audience who are thought we would on our estimate of time off. I apologize. time is approximately 10:40. We're not doing as well as we THE CHAIRPERSON: We're back on record. The (On record - 10:40 A.M.) (Off record - 10:15 a.m.) good on our timing for 15 minutes. Off record. remaining questions that we have, and we'll see if we can be 15 minute break, and then we can regroup and corne back with any ) 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 e e e e . . ) ) A 1 2 A 3 4 5 6 7 8 9 10 11 12 A 13 14 15 16 Injecting water down in the aquifer. COMMISSIONER HEUSSER: Uh-hum. We actually didn't do that. We did not run a case where we looked at injecting into the aquifer, but I think it would be very similar to just a waterflood up in the -- you know, with a -- with the pattern that we have. The miscible project is going to recover so much more than the waterflood just due to leaving much lower residual oil saturations. I don't think any waterflood could ever compete with a miscible project in terms of recovering reserves. COMMISSIONER HEUSSER: Okay. The aquifer also appears to be lower permeability from some of the data that we have. It could be more heavily cemented up than -- than the actual reservoir. COMMISSIONER HEUSSER: Now, I believe you are describing this as a tertiary development. So does this mean 17 that BP intends to qualify this project for EOR credits? 18 A We have filed a EOR certification with the Internal 19 20 Revenue Service, a self-certification, and, yes, we do - - we are - - we have qualified it as a - - a qualified enhanced oil recovery project for the EOR tax 21 22 credits. 23 COMMISSIONER HEUSSER: And I believe I heard 24 you say, Mr. wilcox, that -- and the plan is to do gas 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 50 51 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 A 20 21 22 23 24 25 . MET ROC 0 U R T R E P 0 R TIN G, INC. blend of associated reservoir gas and imported PBU gas. III of this document. Injection fluid will comprise a process and development schemes as included in Section injection fluids, it says a description of the recovery this is -- in the area injection order where it says I think so, yes. Let's see. Let me just see where 19 though was permitted by the EFA a Class I injection well. 18 THE CHAIRPERSON: I understand that that well 17 A The Schrader Bluff. 16 .. ...Formation? COMMISSIONER HEUSSER: 15 A Yes. 14 . well, which is the Schrader Bluff..... 13 COMMISSIONER HEUSSER: Okay. Just the disposal 12 A Just the water injection into the disposal well. 11 authorization for any water injection? 10 COMMISSIONER HEUSSER: Are you requesting 9 that. 8 - if Mr. Turnbull (ph) could look at that and verify 7 reservoir. That wasn't my understanding but maybe if - 6 requesting injection of water into the Ivishak 5 I don't think we're confused. You know, we're 4 into the shallower sands. I'm -- I may be a little 3 A The water injection I think is into the disposal well 2 an area injection order, you request both gas and water. 1 . injection only at this time. I think in your application for ) ) 52 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. replace the oil voidage. And so therefore the A 15 16 17 18 19 20 21 22 23 24 25 maintain miscibility, we must have a -- an additional a lot less recovery benefit. So we -- we -- to miscible oil saturation residual, so therefore you get with the oil and leave higher residuals, leave a declines, the injected gas is going to lose miscibility pressure's going to go decline, and as the pressure and so we're not bringing in any additional gas to that minus what we need for fuel to run the facilities, gas produced from the Northstar reservoir and reinject The gas cycling option is we're only going to take the 14 . option that you've considered? 13 between the gas cycling option and the miscible injection 12 you in just very general terms explain to us the difference 11 COMMISSIONER HEUSSER: And, Mr. Wilcox, would 10 our question. That'll -- that takes care of that I think. 9 water and miscible fluid injection, so I think you've answered 8 the application for area injection order, it says to cover 7 was some confusion was because in the actual introduction to 6 THE CHAIRPERSON: The only reason I think there 5 reservoir. 4 A I don't think we mention injecting water into this 3 COMMISSIONER HEUSSER: Okay. 2 Exhibit 27. 1 . The composition of the injected fluids is listed in ) ) 53 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 17 A 18 19 20 21 22 23 24 25 . MET ROC 0 U R T R E P 0 R TIN G, INC. instance. So the density difference between the gas, much less than something like Prudhoe Bay, for lightest oil on the Slope, so its -- its density is column. Now, this oil is very light. It's the And we're going to be injecting through the entire reservoir to where the water contacts are real low. are located in the central thicker portion of the Well, the way our project works is the gas injectors 400 acre spacing. 16 gravity overriding going on with just five gas injectors and 15 the majority of your oil reservoir if you've got kind of 14 . just not clear to me how your gas is actually going to contact 13 your gas, and you talk about this gravity segregation, it's 12 no barriers, you know, to fluids. When you go and you inject 11 COMMISSIONER HEUSSER: And so there is really 10 A Yes. 9 to gross ratio within the Ivishak? 8 information that you have right now, there's a fairly high net 7 COMMISSIONER HEUSSER: And that with the 6 A Yes. 5 that you're going to have 16 producers and 5 gas injectors? 4 question about your gas injector spacing. I believe I read 3 COMMISSIONER HEUSSER: Thank you. I've got a 2 going to be taking out of the reservoir. 1 . source of gas to make up for the oil voidage that we're ,) . . . ) ) and -- and I might almost say the gas is -- the 1 produced gas is richer than normal produced gas out of 2 Prudhoe Bay. It's not going to be as rich as the 3 miscible injectant that Prudhoe Bay's using, but the 4 density difference between the gas and the oil is not 5 as great as at Prudhoe Bay or Kuparuk where their oils 6 are heavier. So you do see gravity segregation, but 7 it's not as severe as you might think it could be. The 8 other thing is the injection rates that were putting 9 10 this gas in, they're going to be very high. They're going to go up to - - we're going to be injecting 600 million a day into five wells. And so that would 11 12 average 125 million if all five wells were on. If one 13 of the wells was off for any reason, then you've got 14 150 million. So the faster you inject the gas, the 15 less severe the gravity segregation is. And the more 16 you can sweep out of the reservoir, the simulation 17 studies show that you -- you do sweep the reservoir 18 fairly -- fairly effectively, leaving just a little bit 19 down towards the bottom part. The permeability 20 distribution also kind of enters into the equation. The 21 22 permeability looks like it may be better towards the lower part of the conglomerate than perhaps the upper part, so that - - that may also have an impact. 23 24 COMMISSIONER HEUSSER: Thank you. I have no 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 54 . . . 'J ) further questions. 1 THE CHAIRPERSON: Do you have other questions? 2 COMMISSIONER SEAMOUNT: No. 3 THE CHAIRPERSON: Well, I think that will do 4 it. 5 MR. FLONES: You -- I think Dan asked about the 6 flare volumes, and we just wanted to mention that one of our 7 people on the project, Tom Armstrong, is working on those 8 volumes, and he's been working with Wendy Mahan and hopefully 9 by Monday we should be able to transmit you those volumes. 10 COMMISSIONER SEAMOUNT: Okay. That would be 11 good to know. 12 THE CHAIRPERSON: Well, then perhaps on that 13 representation, why don't we keep the record open until, say, 14 Tuesday afternoon at 4:30 to receive that information. 15 MR. FLONES: Okay. 16 THE CHAIRPERSON: Well, thank you very much for 17 an excellent presentation, and thank you also for working with 18 us on the issues of confidentiality. We appreciate it. 19 MR. FLONES: Okay. Thank you. 20 COMMISSIONER SEAMOUNT: Thanks. 21 THE CHAIRPERSON: We're off record. 22 (Off record - 10:55 a.m.) 23 END OF PROCEEDINGS 24 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 55 . . e ) ) C E R T I FIe ATE 1 UNITED STATES OF AMERICA) 2 ) ss . STATE OF ALASKA ) 3 4 I, (}¡:¡IV /fA./.u K5~A21Notary Publ ic in and for the and Reporter for Metro Court Reporting, do State of Alaska, 5 hereby certify: 6 That the 7 foregoing Alaska Oil & Gas Conservation Public Commission Public Hearing was taken before Laura C. Ferro on 8 the 16th day of August 2001, commencing at the hour of 9:05 9 o'clock a.m., at the offices of the Alaska Oil & Gas 10 Conservation Commission, 333 West Seventh Avenue, Suite 100, 11 Anchorage, Alaska; 12 That the public hearing was transcribed by Laura C. 13 Ferro to the best of her knowledge and ability. 14 IN WITNESS WHEREOF, I have hereto set my hand and 15 affixed my seal this 27th day of August 2001. /J //~. ~ (~¿~-&A-. ~ Notary Public in nd for A~a My commission pires: 7-79-01 16 17 18 \',' \IIillllll"I11. ,!\,\\' .-r,. E Ri.. :fIlII; 'Jt.'\~~- \ I~i ~ ~... ~.. .... 'Vr.\ ~ * ~ . .. ~. ~ ~. . ~ ~~. ð.....'. ~ ~....... ~". ~ S~: ~ ~ .. ~ :-. 0% · = - . . ~ i ~: ~ ,0 : ~æ - O· ~v. ;Jè;:: ~ . . \) . I"^ ~ ~ · ð · ~"" ~ ~ · t"" · ~~ ~ ... ... ~~ ~ ......(j~~ ~ _~ l\" ¡fIlII" ~ I Ä TE \\\\\'Iò 1'""",,",,\\,\~ 19 20 21 22 23 24 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 #4 bp ~ I ~ BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 August 13, 2001 Robert P. Crandall Senior Petroleum Geologist Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501-3539 Dear Mr. Crandall, Per our phone calls of the 8th and 9th of August, please find enclosed copies of the new public version of the Northstar Pool Rules and Area Injection Order application with the confidential restrictions removed as discussed. Figure 5 has been re-titled "Ivishak Isopach Map". Also as requested please find attached the following exhibits for entry into the public record for the August 16th public hearing for the Northstar Pool Rules and Area Injection Order: Three each of the following maps: t ~ Initial Oil in Place ...~ End of Run Oil in Place (after 15 years of production) .. ~ Oil in Place Difference (OIIP less end of run OIP) Sincerely, \ RECEIVED '. Bill Turnbull Northstar Subsurface Team Leader AUG 1 3 2001 Alaska Oil & Gas Cons. Commission Anchorage cc: Krissell Crandall Jeanne Dickey File: AOGCC ~ ¡ ~ .. UBLIC INFORMATION Northstar Unit, Beaufort Sea, Alaska Application To AOGCC For Approval Of Pool Rules And Area Injection Order BP Exploration (Alaska) Inc. August 10, 2001 RECEIVED AUG 1 3 2001 Alaska Oil & Gas Cons. Commission Anchorage ..- ) ., ...JUBLIC INFORMATION Northstar Unit, Beaufort Sea, Alaska Application To AOGCC For Approval Of Pool Rules And Area Injection Order Table of Contents 1. Project Overview. .................................. .......................................... ......................... 2 2. Geology.................. .................................... ........................ .....................................4 3. Reservoir Description and Development Planning ...................................................8 4. Facilities................................................................................................................. 22 5. Well Operations..................................................................................................... 26 6. Area Injection Order Application ... ......... .......... .:................ ......................... ........... 32 7. Proposed Area Injection Order Rules... .......... ...... .............. ..... ..... ............. ......... .... 36 8. Proposed Pool Rules..... ......................... ....... ........ ............ ....................... .............38 ~ ~UBLIC INFORMATION List of Exhibits Exhibit 1. Northstar Pool Location Map Exhibit 2. Northstar Injection Area Map Exhibit 3. Northstar Injection Area Description Exhibit 4. Northstar Type Log - Seal A-01 Exhibit 5. Ivishak Isopach Map (Rev 1) Exhibit 6. Northstar Reservoir Structure and Development Well Location Map Exhibit 7. Northstar Cross Sections Exhibit 8. Type Log - Northstar 1 Exhibit 9. Type Log - Seal A-01 Exhibit 10. Type Log - Seal A-02A Exhibit 11. Type Log - Seal A-03 Exhibit 12. Type Log - Seal A-04 Exhibit 13. Chemical composition of Seal A-01 Formation Water Sample Exhibit 14. Northstar Miscible Gas Flood 65 mbd Plateau Rate Exhibit 15. Northstar Waterflood Exhibit 16. Northstar Gas Cycling Exhibit 17. Northstar Primary Depletion Exhibit 18. Northstar Miscible Gas Flood 72 mbd Plateau Rate Exhibit 19. Northstar Miscible Gas Flood 90 mbd Plateau Rate Exhibit 20. Northstar Simplified Process Flow Diagram Exhibit 21. Northstar Facilities Seal Island General Layout Exhibit 22. Slimhole Producer Wellbore Diagram Exhibit 23. Bigbore Producer Wellbore Diagram Exhibit 24. 7" Injector Wellbore Diagram Exhibit 25. 5-1/2" Injector Wellbore Diagram Exhibit 26. Pre-produced Injector Wellbore Diagram Exhibit 27. Northstar Injection Fluid Compositions Exhibit 28. Affadavit of Notice to Surface Owners Exhibit 29. Northstar Pressure Gradients Exhibit 30. Northstar Oil and Gas Composition ~ ~UBUC INFORMATION Northstar Unit, Beaufort Sea, Alaska Application To AOGCC For Approval Of Pool Rules And Area Injection Order BP Exploration (Alaska) Inc. ("BPXA"), in its capacity as Northstar Unit Operator, requests that the Alaska Oil and Gas Conservation Commission (the "Commission") adopt the Area Injection Order ("AIO") set out in Section 7 of this application and the Northstar Pool Rules set out in Section 8. For purposes of this application, the Northstar Pool is defined as the accumulation of hydrocarbons in the Ivishak, Shublik and Sag river formations common to and correlating with the interval between the measured depths of 12,418 feet and 13,044 feet in the Seal A-01 well. The boundary of the Northstar Pool is illustrated in the map attached as Exhibit 1. The boundary of the lands subject to the Northstar Area Injection Order (the "Northstar Injection Area") and the Northstar Pool Rules is shown in the map attached as Exhibit 2, and is described in Exhibit 3. Shortly after submitting this application, BPXA will request that the United States Department of the Interior, Minerals Management Service ("MMS") approve gas reinjection pursuant to 30 CFR 250.114 and enhanced oil reco~ery pursuant to 30 CFR 250.1107. BPXA will coordinate its submissions to AOGCC and MMS such that both agencies receive the same information and are cross-copied on any request or application to the other agency. Where there are differences between the requirements imposed by AOGCC and MMS, BPXA will comply with the more stringent regulation or statute or, if necessary, request a waiver of mutually inconsistent regulations. BPXA is not aware at this time of any instance where complying with the regulatory requirements of one agency would violate the requirements . imposed by the other. Page 1 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ~'" ) ,. ) PUBLIC INFORMATION 1. Project Overview The Northstar Pool is a discovery in the Ivishak formation, and is located approximately 6 miles offshore in the Beaufort Sea, north of the Prudhoe Bay Unit, as illustrated in Exhibit 1. The Northstar Pool crosses from State waters into Federal waters, and lies beyond the barrier islands. The Northstar Pool was discovered in 1983 by Shell during the drilling of the Seal A-01 well and was well appraised by Shell and Amerada Hess who drilled a total of 5 wells to the target horizon. Shell and Amerada Hess carried out extensive coring and well testing, and obtained a dense grid of two-dimensional seismic data. The exploration and appraisal wells were drilled from two gravel islands in approximately 40 feet of water. Amerada's Northstar Island was located over the northwest portion of the Northstar Pool, and Shell's Seal Island was located over the main· southeast part of the Northstar Pool. Both islands were abandoned and were washed away by winter storms. In 1996, BPXA shot and processed an Ocean Bottom Cable ("OBC") 3-D seismic survey over the field. The Northstar Pool contains a volatile, sweet crude. Oil gravities, as measured from several collected fluid samples, range from 43-450 API. Initial gas oil ratios ("GaR") were approximately 2200 scf/stb (standard cubic feet per stock tank barre!) and the viscosity was measured to be about 0.14 cp (centipoise). The Northstar project is a stand-aloneisla~d based development on Seal Island, providing full process and export facilities for 65,000 barrels per day (bpd) oil, 600 million standard cubic feet per day (scfd) of gas injection, and 30,000 bpd of produced water handling capacity. The pipeline system consists of a 10-inch crude export line that ties in to the Trans-Alaska Pipeline System ("TAPS") at Pump Station 1, and a 10-inch gas line for providing the import of make-up gas and fuel gas from Prudhoe Bay Unit for enhanced oil recovery ("EaR") at the Northstar project. Construction of the island and installation of the pipelines were completed early in 2000. The island includes slots for 37 wells, and the initial phase of development at the Northstar project calls for 16 production wells, 5 gas injection wells, and one Class I waste disposal well. Drilling began in December 2000. To date, BPXA has drilled the disposal well, one gas injection well, and two pre-produced gas injection wells. Development drilling will resume following the facility startup in November 2001 and will continue into 2003. Page 2 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ..) ,.) PUBLIC INFORMATION The Northstar Pool will be developed as a tertiary recovery project using the EOR technique of miscible fluid displacement to increase recoverable oil reserves. The EOR project involves the initial injection of a large slug of miscible enriched natural gas into the oil column of the Ivishak formation. This period of miscible gas injection will last approximately four years, and will be followed by the injection of leaner chase gas through to the end of field life. The miscible gas will be a blended mixture of reservoir gas (produced with the oil), and the gas imported from Prudhoe Bay Unit ("make-up" gas). During the miscible fluid injection phase, the gas processing plant on the island will be operated such that the associated reservoir gas is maintained as rich as possible. This will ensure that the injected gas stream is miscible with the reservoir fluids. The volume of make-up gas will be controlled such that the reservoir pressure will be maintained near to its initial value at field startup, and above the miscibility pressure determined from slim-tube experiments. Page 3 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ., ) ~ ~jUBLIC INFORMATION 2. Geology STRATIGRAPHY The Northstar Pool is contained within the Sag River, Shublik and Ivishak formations and was deposited during the Permian and Triassic geologic time periods. Exhibit 4 illustrates the stratigraphy of the Northstar Pool on the Seal A-01 type log. This log is scaled in true vertical depth from the rotary kelly bushing ("TVDrkb"). The top of the Northstar Pool occurs at a depth of 10,650 feet TVDrkb. The base of the Northstar reservoir occurs at a depth of 11,500 feet TVDrkb. The oil ,water contact exists at 11,100 feet true vertical depth sub-sea ("TVDss"). Sag River The Sag River formation lies immediately below the Kingak formation of Jurassic age and above the Shublik formation of Triassic age. The Sag River formation consists of a series of transgressive marine sands, silts, and shales and is approximately 1 00 feet thick in the vicinity of the Northstar pool area. Shublik The Shublik formation lies immediately below the Sag River formatIon of Triassic age and unconformably overlies the Ivishak Formation of Permian and Triassic age. The Shublik formation consists of marine silts, shales, sands and phosphatic limestones and is approximately 85 feet thick in the vicinity qf the Northstar pool area. The Shublik formation is subdivided into four lithologic units. The upper unit called the Shublik A consists of marine silts and shales and is approximately 35 feet thick. The Shublik B lies below the Shublik A and consists of phosphatic limestones and is approximately 10 feet thick. The Shublik C lies below the Shublik B and consists of limestones grading downward into interbedded shales and siltstones and is approximately 30 feet thick. The Shublik D lies below the Shublik C and unconformably overlies the Ivishak formation. The Shublik D is approximately 10 feet thick. Ivishak The Ivishak formation lies unconformably below the Shublik D unit of Triassic age and conformably above the Kavik formation of Permian age. The Ivishak is approximately 325 feet thick in the vicinity of the Northstar pool area. The Ivishak consists of delta front sands and shales grading upward to fluvial sands and finally into medium to coarse grained pebbly conglomerates. Page 4 Northstar Pool Rules and Area Injection Order Application 8/10/2001 -) .'/ la, )UBLIC INFORMATION LITHOLOGY Sag River The sands within the Sag River represent a mineralogically mature sandstone composed of quartz with minor amounts of feldspar and authigenic clays. Calcite, silica and siderite are the primary cementing agents. Shublik The Shublik formation consists of marine silts and shales in the Shublik A unit grading downward into phosphatic limestones in the Shublik B and then into interbedded silts and shales in the Shublik C and finally into fine and very fine grained sands in the Shublik 0 unit. Calcite, silica, siderite and pyrite are the primary cementing agents within the Shublik formation. Ivishak The Ivishak reservoir consists of an upper conglomeratic unit and a lower sand unit. The upper conglomeratic unit is characterized by a bimodal grain size distribution consisting of mostly chert and quartz clasts with minor amounts of silt and quartz grains comprising the matrix material. The conglomeratic unit has varying amounts of microporous chert grains as part of the framework. Calcite, silica and siderite are the primary cementing agents. The lower sand unit consists of medium to coarse-grained sand with minor amounts of silt and shale. This lower unit is approximately 100 feet thick and is present below the oil / water contact throughout most of the field area. Calcite, silica arid siderite are also the primary cementing agents present within the lower sand unit. The Ivishak reservoir at Northstar is more proximal, coarser grained, more deeply buried and cemented than the Ivishak reservoir in Prudhoe Bay, leading to lower average porosities and permeabilities. Analysis of pressure and production data indicates an absence of vertical permeability barriers within the Ivishak. The kV / kH ratio is nearly 1.0 and the presence of cemented intervals does not appear to be laterally extensive. An isopach map of the Ivishak reservoir is shown as Exhibit 5. The isopach map illustrates the continuous nature of the Ivishak formation over the Northstar Pool area. STRUCTURE The structure of the Northstar Pool consists of a faulted anticline defined by three-way dip closure on the east, west and south, with fault seal and dip closure to the north. Exhibit 6 is a structure map at the top of the Ivishak and illustrates the trapping configuration. Exhibit 7 Page 5 Northstar Pool Rules and Area Injection Order Application 8/10/2001 . , ) . )UBLIC INFORMATION shows two structural cross-sections. Cross-section A-A feet is a strike oriented cross-section running from the SW to the NE across the Northstar Pool. Cross-section B-B feet is a dip oriented cross-section running from the NW to the SE. These two cross-sections also serve to illustrate the trapping configuration at the Northstar Pool. FAULTING Evidence for faulting, fracturing and deformation from the whole core at Northstar was very minor. There were less than 30 total observations of fracturing, faulting or other style of deformation in nearly 1200 feet of whole core. Pressure buildup analysis from several wells found no evidence of production barriers surrounding the existing appraisal wells even though they are relatively close to mapped faults. RFT and pressure data from the Seal A-02 and Seal A-01 indicate that these wells are in pressure communication within the Ivishak formation. Maximum vertical displacements along faults within the field area as interpreted from the 3D seismic data are less than 200 feet, which is significantly less that the average reservoir thickness of 325 feet. Faults at Northstar are interpreted to be neutral with respect to reservoir performance given the high net to gross ratios observed (90 to 98%), the lack of deformation observed in core data, and the inability to determine reservoir boundarìes from buildup data. A testing and reservoir surveillance program, including pressure measurement from RFT or MDT, injection gas tracer analysis and geochemical analysis, will be implemented to address this issue more completely during development. CONFINING INTERVALS The Northstar Pool is confined below by the Kavik formation and above by the Kingak formation. The Kavik formation is continuous throughout the area. It is interpreted to be a marine shale sequence of Permian age. The Kavik rests unconformably on the carboniferous aged Lisburne group. The Kavik formation is extremely impermeable with a thickness of approximately 100 feet in this area and serves as the lower confining zone. The Kingak formation is continuous throughout the area and conformably overlies the Sag River formation. The Kingak formation was deposited as marine shales and silts during the Jurassic period and is extremely impermeable. The Kingak formation is approximately 1,000 feet thick in the area and serves as the upper confining zone. Page 6 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ~ ¡ ") PUBLIC INFORMATION FLUID CONTACTS The Northstar oil water contact ("OWC") of 11,100 ft. TVDss was determined primarily from Seal A-01 and Seal A-02A core oil stains and a well test directly above the OWC. A test below 11,100 ft. in Seal A-03 indicated water production. No oil water contact was observed in the Seal A-04 well. The oil water contact is not obvious on any of the Seal well logs, with the exception of Northstar-1, as the water saturation numbers are in general quite high near the OWC. This is because of the significant amount of bound water in the microporosity. Additionally, the pressure gradient analysis of the RFT's run in Northstar-1, NS27 and NS31 also indicates an OWC at 11,100 ft. TVDss. Page 7 Northstar Pool Rules and Area Injection Order Application 8/10/2001 #A) fI"') PUBLIC INFORMATION 3. Reservoir Description and Development Planning ROCK AND FLUID PROPERTIES The reservoir description of the Northstar Pool is based on core and well log data from the Seal A-01, Seal A-02A, Seal A-03 and Northstar-1 wells. A total of 1196.3 f1. of Ivishak core was acquired from these four wells. The core data were used to calibrate the porosity portion of the petrophysical log model. The type logs for the reservoir intervals in Northstar-1, Seal A-01, Seal A-02A, Seal A-03 and Seal A-04 are shown in Exhibits 8 through 12. POROSITY AND PERMEABILITY Sag River Formation Routine porosity and permeability measurements are available from two wells (Seal A-02A, and Northstar-1). No significant core was obtained in what would be described as the best reservoir section of the Sag River formation with the exception of the upper part of Core 1 in the Seal A-02A well. The core plug permeability values range from 0.01 to 28.0 md with a mean value of 0.86 md. The mean core porosity is 13% with a minimum and maximum range of 6.80/0 to 22.8%, respectively. The average log derived porosity was generated from the density log using an average grain density of 2.73 g/cc. The log porosity results ,average 16-180/0 for the 10 to 30 f1. section that is considered pay. Permeability was estimated from a core poro-perm relationship. The likely permeability range is estimated to be from 1 to 4 md. No tests are available for comparison with the core data., Shublik Formation Core data across the Shublik formation exists on the Northstar-1 and Seal A-02A wells only. The Shublik formation is considered a source rock and not in general a reservoir rock. What core poro-perm data does exist suggest that most of the section is tight and non-reservoir with the exception of Zone D. Permeability is generally less than 1 md and porosity less than 10%. However, porosity and permeability measurements can get up to 16.3% porosity and 100 md in a few instances in thin « 3 inches) discontinuous intervals. These thin intervals are not observed on well log data and usually add up to less than 2 feet cumulatively in vertical extent and do not appear to correlate between wells. Page 8 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ~ 1 #') PUBLIC INFORMATION Ivishak Formation Extensive routine porosity and permeability measurements were available from four wells (Seal A-01, Seal A-02A, Seal A-03 and Northstar-1). Core was also obtained from Seal A-04 but was insignificant and outside the oil column. In addition, porosity and permeability data at in-situ confining pressures were available from Seal A-02A and Northstar-1. A sensitivity study of the impact of in-situ confining stress on porosity and permeability indicate that porosity loss was minimal (3% loss) whereas reduction of permeability is more significant (14-21 % loss). The mean stress corrected core porosity for the Ivishak Formation above the oil water contact is approximately 150/0. Core permeability ranges from 0.01 to 808 md with a mean stress corrected value of approximately 53 md. Permeability established from drill stem tests are higher than average permeability values from core. This may be a result of rubble sections existing in the reservoir that were not representatively sampled from the cores that were obtained. The two dominant facies, conglomerates and sandstones, have different reservoir properties and subsequently different poro-perm trend relationships. The correlation of porosity to permeability is better for the sandstones than for the conglomerates. Two significant studies were undertaken on the Ivishak reservoir to define the percent of effective porosity and non-effective micro-porosity. Shell and Core laboratories performed a study on these two porosity distributions. Within the Ivishak reservoir there are two dominant reservoir facies, which have been characterized as conglomerates and sandstones. The conglomerate facies as defined by Shell and Core laboratories have an average porosity of 13.5% and 13.9%, respectively, while the sandstones have an average porosity of 17.70/0 and 17.5%, respectively. Additionally, Shell and Core laboratories reported that within the conglomerate facies 47.40/0 and 53.2% respectively of the total porosity is micro-porosity. They determined that within the sandstone facies 37.9% and 42.30/0 respectively of the total porosity is micro-porosity. This study indicates that the volume fraction of micro-porosity increases as one moves down in the reservoir section. NET PAY Sag River Formation The reservoir gross thickness ranges from a minimum of 55 feet in the Northstar-1 well to a Page 9 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ~ f) PUBLIC INFORMATION maximum of 123 feet in the Seal A-03 well. Net pay was determined from gamma ray cutoffs and porosity cutoffs that were established from poro-perm relationships. Permeability above 1 md or porosity above 160/0 was considered as pay. This estimate has not been verified by test. Currently, no test exists in the Sag River formation to demonstrate producibility. The net to gross for the interval was determined to range from 15-250/0 based on the above cutoffs. There is considerable uncertainty in this estimate as log coverage of the Gamma Ray and porosity is not generally complete across the Sag River section. Shublik Formation Core was obtained only on the Northstar-1 and Seal A-02A well across the Shublik formation. While mudlog shows exist, this section is in general non-reservoir. The permeability that does exist from core from the Northstar-1 and Seal A-02A wells is generally less than 1 md. There are a few thin intervals of reservoir quality rock in the Shublik that have permeabilities as high as 100 md but are not considered significant with the possible exception of the Shublik D unit. The gross thickness of the Shublik D is about 5-10 feet with about half of that-being net pay. Ivishak Formation The reservoir has a very high net to gross average of 93-950/0. Non-p"ay intervals include rare silty/shaley intervals recognized on the gamma ray log (V-shale) and low porosity cemented conglomerates and sandstones. Thicker and more continuous shales are only present in the very lowest portions of the reservoir and" are present largely in the aquifer. Net to gross estimates were made using a combined V-shale cut off of 50% and a 100/0 porosity cutoff for sandstones and a 80/0 porosity cutoff for conglomerates. Porosity cutoffs were established from poro-perm relationships for the conglomerates and sandstones. STATIC MODEL CONSTRUCTION Sag River and Shublik Formations Isopach maps for the Sag River and Shublik were created using the existing well control. Porosity, water saturation and net to gross ratios were determined for the Sag River from well log and core data analysis. These data were then combined to determine the 001 P for the Sag River which was estimated to be 37.7 mmbbls and 52.1 BCF. The following table summarizes the input parameters for determining the OOIP for the Sag River: Page 10 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ,.) ,-..) PUBLIC INFORMATION Property I Units Sag River Oil I Sag River Gas Bulk rock volume ft3 34.2 x 10^9 15.3 x 10^9 N/G ratio 0/0 20 20 Sw % 60 60 Porosity 0/0 17 17 1/Formation volume factor stb/rb 0.455 1/Formation volume factor Bbl/mcf 0.71 Hydrocarbon pore volume in reservoir ft3 211 x 10^6 208 x 10^6 OOIP MMbbls 37.7 OGIP BCF 52.1 Ivishak Formation Isopach maps, porosity maps, net to gross ratio maps and permeability maps were constructed for each unit within the Ivishak horizon. The upper conglomeratic unit was subdivided into five subunits with reservoir maps generated for each subunit. The Shublik D unit was included within the upper conglomeratic unit in the Ivishak. The lower sandy. unit of the Ivishak was subdivided into three subunits and the same reservoir maps were created for each of these subunits. The structure for the top of the static model was created by taking the structure map at the top of the Sag River and then adding the interval isopach between the Sag River and the top of the Shublik D. Subsequent interval isopach maps were then sequentially added together to create the structural model. Each of these reservoir maps were then back interpolated to generate a series of grids at 100 foot increments. These grids were then compared to existing well control for consistency. WATER SATURATION Sag River Formation Oil and gas shows from the Sag are seen in mudlogs in the Seal A-01, Seal A-02A, and Seal A-03 wells. No oil or gas shows were present in the Seal A-04 well though part of the Sag River section is above the 11,100 ft. TVDss oil water contact that was observed in the Ivishak formation. Additionally, the Northstar-1 well has questionable gas and/or oil shows in the Sag Page 11 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ..) fI) PUBLIC INFORMATION River formation even though it is also above the 11,100 foot oil water contact. Log derived saturations would suggest that the Sag River formation in the Northstar-1 well is wet as well. Water saturations within the Sag River Formation range from 50-65% in the Seal A-01, Seal A-02A and Seal A-03 wells. Presently no electrical property data measurements exist for the Sag River formation in the Northstar wells. Archie parameters were obtained from analog Sag River formation in the Milne Point area. The Archie. parameters that were used in determining water saturation are "m" (cementation exponent) of 2.071 and on "n" (saturation exponent) of 2.0. At present no capillary pressure measurement are available in the Sag River formation to confirm the log derived saturation model. Shublik Formation The only horizon containing possible moveable hydrocarbons in the Shublik formation is the Shublik D unit. Determining water saturation within this section is difficult using a conventional analysis and logs due to the presence or abundance of pyrite, which suppresses the induction log and gives anomalously high water saturation. Test and core fluorescence in Northstar-1 suggest that the Shublik may be gas bearing at that location. Ivishak Formation Since the cores from the Seal and Northstar wells were not acquired with low invasion oil based mud, the· core water saturation measurements were not suitable for calibrating to log derived water saturation results. Traditional log derived saturation methods were also complicated by the various mud systems used and presence of significant amounts of microporous chert. Given the problems associated with the log derived saturation model, the average water saturation for the reservoir was generated from a multiple regression analysis of the available capillary pressure data to generate a capillary pressure model from samples representing conglomerates and sandstone. This average oil saturation was determined to be 420/0 for the reservoir at the reservoir volumetric centroid of the field. The volumetric centroid of the reservoir is 80 feet above the oil water contact (11,100 ft. TVDss) at 11,080 ft. TVDss. The maximum oil column is estimated to be between 270-300 feet thick. The generic form of the equation for the reservoir water saturation was derived primarily from the porous plate, mercury air and centrifuge capillary pressure data from the core in Seal A-02A: Page 12 Northstar Pool Rules and Area Injection Order Application 8/10/2001 fA, ) ,., J PUBLIC INFORMATION Conglomerates: Sw = 1.3049-2.607*0-0.076255*LN(HAOWC) Sandstones: Sw = 1.3549-3.607*0-0.056255*LN(HAOWC) Where: Sw = Water saturation (v/v) 0= Porosity (v/v) HAOWC = Height above oil water contact (feet) A total of 131 capillary pressure curve measurements were obtained from the Seal A-01, Seal A-02A, Seal A-03 and Northstar-1 wells. Of these, 101 were mercury injection, 24 were porous plate and 8 were centrifuge capillary pressure measurements. Of these, 26 were conglomerates, 94 were sandstones and 13 were cherts. This data was used to define the amount of effective porosity, micro-porosity, pore size distribution and oil saturation as a function of height above a free water level for both the conglomerate and sandstone facies. A significant amount of special core analysis measurements were obtained from the Northstar cores. Electrical property measurements were conducted on 35 core såmples in order to define "m" (cementation exponent) and on 24 core samples to define "n" (saturation exponent) for use in the Archie equation to calculate water saturation from log data. The average "m" and "n" value for the Northstar Pool is 2.03 and 2.73, respectively. These electrical property measurements were also broken out by conglomerates and sandstones facies. The average "m" value for the conglomerates and sandstones were 2.06 and 1.92, respectively. The average "n" value for the conglomerates and sandstones were 2.90 and 2.68, respectively. Water resistivity was determined to be 0.10 ohm-m at 2470 F based on a formation water sample of 19,340 ppm NaCI from the Seal A-01 well. The chemical composition of the formation water sample taken from Seal A-01 is shown in Exhibit 13. Comparing core porosity measurements to the wireline log curves indicates that the sonic log provides the best correlation to core porosity followed by the density log and then finally the neutron log. The average grain density of the Ivishak reservoir rock is 2.71 g/cc. Page 13 Northstar Pool Rules and Area Injection Order Application 8/10/2001 fJt.) ~) PUBLIC INFORMATION PRESSURE & TEMPERATURE The initial pressure of the Northstar Pool at 11,100 ft. TVDss, the oil water contact, was 5305 psig (pounds per square inch gauge) based on RFT and bottom hole pressures measured in the Seal A-02 and Seal A-01 wells. For reference, this equates to 5245 psig at 10,839 ft. TVDss, which is near the crest of the structure. Average reservoir temperature is estimated to be 2540 F at the oil column centroid. RFT and MDT pressure measurements in NS27 and NS31 indicate that Northstar Ivishak reservoir pressure has declined by about 125 psi since drilling the exploration wells in 1984 through 1986. Average reservoir pressure at the owe is currently 5180 psig. It is our current interpretation that this pressure drop is a consequence of the pressure decline in the Prudhoe Bay Ivishak reservoir which is believed to be in hydraulic communication with the Northstar Ivishak reservoir through the aquifer. Current Northstar reservoir pressure appears to be about 80 psi above the bubble point pressure at the centroid of the oil column. The lower 150-225 feet of the reservoir appear to be at pressures currently exceeding bubble point pressure, while the pressure in the upper portion of the reservoir may have dropped below bubble point pressure~ A small amount of gas in this region below the bubble point may have formed a critical gas saturation or migrated to the structurally higher areas of the reservoir. FLUID PVT DATA PVT analysis was carried out on recombined surface samples from Seal A-01, Seal A-02A, Seal A-03 and the Northstar-1 wells. A compositional analysis from Seal A-01 Test #2 is included as Exhibit 30 to typify the Northstar oil and gas. One bottom hole sample was obtained from the Seal A-01 well allowing comparison to the surface samples. Analysis of the PVT fluid samples indicates a slight oil compositional gradient, with oil density increasing with depth. The ranges of fluid properties at initial reservoir conditions are listed below. Page 14 Northstar Pool Rules and Area Injection Order Application 8/10/2001 fA) ,-., J PUBLIC INFORMATION Fluid Property Oil API Gravity (Degrees API) Solution GaR (SCF/STB) Oil Formation Volume Factor (RB/STF) Oil Density at Bubble Point Pressure (gm/cc) Oil Viscosity (cp) Gas Viscosity Estimated (cp) Water Viscosity Estimated (cp) Near Water-Oil Contact 43 1900 2.1 0.54 0.15 0.06 0.25 Near Gas-Oil Contact 45 2400 2.3 .51 0.13 0.07 0.26 Analysis of the bubble point pressure versus depth from the Seal A-01 well indicates the reservoir may be saturated near the crest of the structure with a gas-oil contact ("GOC") inferred to be located at 1 0,839 ft. TVDss. Below the inferred GOC, the oil is undersaturated. Bubble point pressures from the PVT data range from 4936 psig at 11068 ft. TVDss in Seal A-02 to 5216 psig at 10864 ft. TVDss in Seal A-01. Several feet of gas were present in the top of the reservoir in the Shublik 0 zone in the Northstar-1 well. The gas elevated the GaR to 5300 SCF/STB in the well test in which the upper 30 feet of the well was perforated. These perforations included the Shublik 0 in addition to the upper Ivishak (Ivishak E). This gas appears to be isolated from other upstructure Ivishak wells in which free gas is not present. There is no evidence of a Heavy Oil Tar zone in the Northstar Ivishak reservoir. Results from the PVT data were used to generate both a 10 and a 15 component equation of state ("EOS"). The EOS along with the oil compositional gradient were used in the reservoir simulation studies. One slim tube experiment has been run with oil from the Northstar-1 well to verify miscibility. This experiment, which achieved a 98.7% recovery efficiency at 1.2 PV gas injection, was used to validate the EOS by history matching the slim tube results. PVT quality bottom hole fluid samples were taken in late May 2001 with the MDT tool from NS31. Oil samples (450 cc) were taken throughout the oil column with larger samples taken near the oil column centroid. The oil samples will be used in PVT studies to determine bubble point pressures and compositions, and for slim tube experiments to verify miscibility. Most of Page 15 Northstar Pool Rules and Area Injection Order Application 8/10/2001 fA) ') PUBLIC INFORMATION the slim tube experiments will be conducted with the oil samples taken near the oil column centroid. Slim tube simulations indicate the oil compositional gradient has a negligible impact on minimum miscibility pressure ("MMP"). The benefit of lighter oil towards the top of the structure is offset by its higher methane content. HYDROCARBONS IN PLACE Estimates of hydrocarbons in place for the Northstar Pool reflect well control, stratigraphic and structural interpretation, and rock and fluid properties. These data were integrated into a geologic model that provides the basis for the estimation of the original fluids in place. The results indicate an Original Oil in Place ("OOIP") of 247 million stock tank barrels ("MMSTB"), a 7 BCF inferred gas cap occupying 1 percent of the hydrocarbon pore volume, and 480 BCF total gas including solution gas. Structural interpretation is believed to have the greatest impact on uncertainty in OOIP, although there is also large uncertainty in determining the volume of oil filled intergranular porosity versus water filled microporosity. DEVELOPMENT PLANS Reservoir models of the Northstar Pool were constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles for facility design. This section of the application describes the reservoir models, recovery process selection, and the current development plans. Reservoir Model Description To evaluate the performance of the Northstar reservoir, both 3-D (three dimensional) full field models ("FFM") and finer grid mechanistic models were constructed. The models are compositional utilizing either a 10 or 15 component equation of state. The 3-D compositional full field model covers the entire Ivishak reservoir and the surrounding aquifer. The Sag and Shublik formations were not included in the reservoir simulation. The FFM has 400 foot (3.7 acre) grid blocks over the oil column with 2000 foot (92 acre) grid blocks over the surrounding aquifer. There are 18 vertical layers with grid block thickness averaging 15 to 30 feet. Faults are included in the model through corner point geometry and are considered to be neutral with respect to fluid flow. A capillary pressure equation (as defined earlier) relating porosity and height above the oil water contact was used to predict initial water Page 16 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .' ) ,..) PUBLIC INFORMATION saturations. Grid block values for porosity, permeability, net to gross, and isopach layer thickness were obtained by back interpolating grid block coordinates against the static model. Grid block values for top Ivishak were derived from maps of top Sag River and isopach maps of the Sag and Shublik. Very finely gridded mechanistic 1-D (one dimensional) models were used to study miscible displacement aspects of the flood. One slim tube experiment has been run with oil from the Northstar-1 well to verify miscibility. This experiment was used to validate the EOS by history matching the slim tube results. Mechanistic finer gridded 3-D partial field models were also developed. These ongoing model studies are being used to study water coning, horizontal versus vertical well performance, and to validate the coarser grid FFM. The full field model is in the process of being updated to incorporate the revised geological model which is being modified to include the results of the development wells drilled to date. Recovery Process Selection A miscible gas injection project, along with waterflood, gas cycling, and primary depletion scenarios, were evaluated. All of the cases used the same number of wells and locations. Injection was controlled to maintain reservoir pressure near the original 5305 psig for the miscible gas and waterflood cases, with pressure declining in the gas cycling and primary depletion cases. Oil and natural gas liquids ("NGL") recovery for these cases are given below with production plots shown in Exhibits 14 through 17. Oil NGL Total Liquid RF 0/0 OOIP (Oil) Miscible Gas Injection 159.3 16.9 176.2 64.5 Waterflood 128.3 6.6 134.9 52.0 Gas Cycling 123.6 12.1 135.7 50.0 Primary Depletion 89.1 5.1 94.2 36.1 Miscible gas injection was the recovery method selected due to its significantly higher recovery efficiency. Oil recovery with miscible gas injection is forecast to be 12-140/0 OOIP higher than Page 17 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .- ) p- ) PUBLIC INFORMATION either gas cycling or waterflood. The project is being implemented concurrent with field startup to deliver maximum benefit. Water alternating with gas ("W AG") injection was also evaluated. The model runs indicated essentially no additional recovery from WAG injection. However, if the reservoir turns out to be highly stratified, WAG injection could mitigate gas channeling through high permeability intervals. Miscible injectant is made by blending "make-up" gas from Prudhoe Bay Unit ("PBU") with Northstar produced gas. NGLs are left in the produced gas during the miscible injection phase of the project by not running the refrigeration unit of the NGL plant. The "make-up" gas from PBU acts to maintain reservoir pressure which maintains miscibility. It is currently anticipated that NGLs will be left in the produced gas for the first four years of the project resulting in injection of up to 60% hydrocarbon pore volume of miscible enriched natural gas into the oil column. The miscible gas injection phase will be followed by leaner chase gas injection for the remainder of the oil production phase of field life. Current Development Plans The current Northstar development provides for drilling 21 new wells on an average well spacing of about 400 acres. Five of the wells are planned as miscible gas injectors, with sixteen oil producers. The injectors are located in the central thicker oil column portion of the reservoir to maximize miscible sweep efficiency in areas that contain the greatest OOIP. Two of the injectors will be pre-produced to help load the production facility at startup. The wells in the thicker oil column portion of the reservoir are scheduled earlier in the drilling schedule. The current development plan calls for drilling the peripheral producers as high angle wells which allows e-line or slick-line access for routine surveillance. Water coning at Northstar is an area of uncertainty due to the apparent absence of barriers to vertical flow, and horizontal peripheral wells are currently being evaluated as a possible option. To help evaluate water coning issues, we plan to take RFT pressure data in wells drilled after field startup to determine if there are vertical cement barriers present in the reservoir that might act to reduce water Page 18 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .) ,., ) PUBLIC INFORMATION coning. Recent model runs indicate that with sufficient standoff from the OWC, water production should remain below the 30,000 BWPD facility limit. Future Development Plans Additional reserve options exist within the Northstar unit beyond the scope of the initial development described in this document. Our ability to drill extended reach wells presently limits us to wells with bottom hole locations no more than approximately 17,500 ft. from the production island. As a consequence, approximately 7 to 8 million barrels of oil remain in the North West portion of the reservoir at the end of field life if no further development drilling were carried out after the initial 22 well drilling program. We expect that with the experience that the initial well schedule will gain us, and with advances in drilling technology, that additional wells that will tap this remaining 7 to 8 million barrel potential will be possible at the end of the current drilling program. The reserves in the North West portion of the reservoir will remain essentially untouched by the initial development program as a consequence of maintaining the reservoir pressure close to original pressure. We also recognize the possibility that satellite oil accumulations may exist within expected drilling reach from the island. These targets will be the subject of additional appraisal. RESERVOIR MANAGEMENT STRATEGY The objective of the reservoir management strategy is to maximize ultimate recovery consistent with sound engineering practice. Reservoir pressure strategy and field oil production rate are addressed in the reservoir management strategy. Reservoir Pressure Strategy Reservoir pressure in the Northstar reservoir will need to be managed in order to: ensure miscibility; minimize oil loss due to shrinkage from producing below bubble point pressure; minimize oil loss due to pushing oil into the aquifer by over pressuring the reservoir; and achieve some aquifer influx to sweep the periphery and structurally low areas. Our current reservoir management strategy during the miscible phase of the project, which is expected to last the first four years of field life, is to voidage replace 1000/0 of total production to maintain reservoir pressure at the initial value found at field startup. However, during the first Page 19 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .) .) P(JBLIC INFORMATION year of the project we would like to maintain the option of exceeding 100°,10 voidage replacement to ensure miscibility and compensate for some of the prior and anticipated pressure declines. To maintain operational flexibility during the miscible phase we plan to operate within a 50 psi average reservoir pressure range around the pressure found at flood start. Even with 1000/0 voidage replacement, reservoir pressure may decline at about 6-10 psi/year assuming continued pressure depletion through the Ivishak aquifer. After the miscible phase of the project, it is yet to be determined how much reservoir pressure should be allowed to drop to stimulate water influx around the periphery of the field. To prevent hydrocarbons from being displaced into the aquifer, the average reservoir pressure will not be increased appreciably above its initial value. Most of the reservoir is underlain by bottom water and there is also a large oil water contact periphery. Locating the injection wells in the thick oil column areas of the reservoir which have low OWC's will help to minimize oil pushed into the aquifer beneath injectors due to local pressure gradients. After the miscible phase of the project, there may be benefit from dropping reservoir pressure below the initial value to achieve natural water influx around the periphery of the reservoir and low in the oil column. The lower portion of the reservoir is not as efficiently swept by the injected gas due to gravity segregation of the gas within the oil column. Allowing a decline in reservoir pressure allows water influx to sweep areas that are less efficiently swept by the miscible flood. Late in field life (approximately 16 years after field start up) during blow down, reservoir pressure will be reduced to maximize recovery of the injected gas. Gas recovery volumes from blow down have not as yet been estimated. Impact Of Field Production Rate Three field production rate scenarios have been evaluated. These cases were run prior to obtaining the pressure data from new wells. Average oil off take rates of 65, 72, and 90 MSTB/D were evaluated in the full field simulation model with the results shown below and production plots shown in Exhibits 14, 18 and 19. Page 20 Northstar Pool Rules and Area Injection Order Application 8/10/2001 -) ..) rUBLIC INFORMATION Total Liquid Produced Produced Injected Gas Water Gas Plateau Rate (MMSTB) (MMBW) (TCF) (TCF) 65 MBOPD 176.2 151.2 2.485 2.757 72 MBOPD 176.5 153.5 2.542 2.805 90 MBOPD 178.2 157.6 2.581 2.855 Water coning in the peripheral wells caused the runs to come off plateau due to water handling constraints. The 90 MBOPD case came off plateau in about two years, while the 65 MBOPD case remained on plateau for about four years. However, subsequent mechanistic and FFM model runs indicate water coning may not be as severe as observed in these cases and could be managed through the petioration strategy with sufficient standoff from the OWC. The 30,000 BWPD facility water handling limit currently appears to be more than adequate. Makeup gas imported from PBU was limited to 100 MCF/D for each of the cases. Reservoir pressure declines during the high fluid off take plateau periods ranged from 75 psi for the 65 MBOPD scenario to 150 psi for the 90 MBOPD plateau case. The ultimate oil recoveries determined from these model runs were not sensitive to field production rate. The higher off take cases did slightly better due to producing and injecting greater volumes of gas through the reservoir early in field life before gas handling facility limits were reached. Page 21 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .-- ì ~) rUBLIC INFORMATION 4. Facilities INTRODUCTION The Northstar project consists of a self-contained production facility on Seal Island, located 6 miles offshore of the Point Storkerson area in the Alaskan Beaufort Sea. Seal Island is a gravel island of approximately 5 acres constructed over the remains of the island built by Shell Oil Company to conduct exploratory activities during the 1980's. Two pipelines have been buried in a single trench from Seal Island to existing onshore facilities to transport hydrocarbons to and from the Northstar Unit. The pipelines include one 10-inch common carrier pipeline from Seal Island to Pump Station No. 1 to transport the sales oil to TAPS. The second 10-inch pipeline facilitates the import of up to 100 mmscfd hydrocarbon gas from the Central Compressor Plant in the Prudhoe Bay Unit to Seal Island to assist with the gas cycling process used to produce the Northstar Pool. The plant design allows the imported gas to be used for fuel. The production facility will be capable of handling 65 mbd of oil, 30 mbd of produced water, and 600 mmscfd of total injected gas. The processing facilities consist of, three primary modules. The first, a three level module, will contain the separation, gas dehydration and power generation equipment. The second module will contain the low and high pressure gas compression equipment. The third module will contain the water storage and disposal systems. These three modules are being assembled in Anchorage and will be sea-lifted to Seal Island in the summer of 2001. A simplified process flow diagram is shown in Exhibit 20. Options to allow an increase in the facility handling capacities are currently being evaluated. A permanent camp facility for up to 74 production and drilling personnel will be installed on the island. Emergency power generation, seawater treatment and sewage facilities will be provided for the camp. Tankage for diesel fuel and water storage will also be included. Exhibit 21 shows the general layout of the island. While drilling operations are underway, access to the island in the winter months will be by ice road. During the summer open water period, routine access will be barge or supply boat. At all other times, helicopters will be used to travel to and from the island. Page 22 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .) ..) rUBLIC INFORMATION INFRASTRUCTURE Seal Island will be the first offshore production island in the Beaufort Sea. The critical infrastructure installed to support operating and essential maintenance of the production facility include: 1. A 74 bed permanent camp with kitchen, dining room, fitness equipment and critical medical care facility; 2. Utilities, including potable water generation, waste water treating, solids incineration, communication gear, and firewater systems; 3. Warehouse I Shop for onsite repairs and critical materials storage; 4. Helideck and dockface; and 5. Class 1 disposal well. Well Row Facilities The island layout is designed for 37 well slots. Sixteen producers, five gas injectors and one disposal well are planned for the base development. The piperack· along the well row has headers for well testing, single train production, gas injection and .water disposal. A hydraulic well system and individual well safety panels are included in the piperack, as are utility water, fuel gas, highline electric connections, and vacuum / fluid exchange headers to support drill rig operations. Main Process Module The main process module, which will be sealifted in two halves and reconnected onsite, will house production separators, gas coolers and dehydration facilities, a Natural Gas Liquids ("NGL") stabilization system, turbine driven generators, a waste heat recovery system for process and utility heat, gas relief collection headers / scrubbers, fuel gas letdown skid, and plant air and nitrogen systems. The south end of the process module will house the oil custody transfer LACT unit, shipping pumps, the oil pipeline pig launcher and the gas import line pig receiver. Compressor Module The compressor module will support the flare boom, and will include a single low pressure, multi-section motor driven compressor, two turbine driven injection gas compressors, and Page 23 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .-." ) ~) ,/ PUBLIC INFORMATION coolers, piping and scrubbers for the three compressors. Pumphouse Module A small pump-house module will have tankage for produced water and well cleanup fluids, centrifugal produced water pumps, and a positive displacement water disposal pump. Production Allocation Production will be allocated to producing wells based on individual well tests and actual plant oil sales volume. All production wells are individually connected to the test header. Each producing well will be tested monthly to ensure accurate allocation of the produced fluids. The Programmable Logic Control ("PLC") system (Plantscape) and Plant Historical Database (Uniformance Historian) will continuously gather operating data from the plant, wells, and test separator. The following points will be honored as part of the production allocation procedure: 1. All wells will be tested monthly. 2. The stabilization and duration of each test will be optimized by the operator to obtain a representative test. 3. Well and field operating condition information required for the construction of a field production history will be maintained. 4. Test separator meters and major gas system meters will be installed and maintained according to industry recommended practices or standards. 5. The Operator will maintain records that permit verification of the satisfactory execution of the production allocation methodologies. Flaring Philosophy Northstar flaring will be aligned with the BPXA corporate policy to "minimize flaring." Flaring will be governed by these principles: 1. Gas injection will be started prior to opening production chokes. This will minimize flaring of primary stage separation off gas during plant startup. 2. Gas will be flared from low pressure separators only long enough for gas flows to stabilize at a rate sufficient for startup of the multistage LP Compressor. Page 24 Northstar Pool Rules and Area Injection Order Application 8/10/2001 tþ" ! ,.\ J PUBLIC INFORMATION 3. Maintenance flaring will continue only during limited periods of problem solving or equipment I compressor testing. In no event will maintenance flaring exceed 48 hours without notification and approval from the MMS as required by 30 CFR 250.11 05(a)(2)(i). 4. The control system will be configured to initiate an automatic shutdown of operator selected wells in the event of partial loss of Injection Gas Compression capacity (shutdown of one of two IG compressors). In the event of a compressor emergency shutdown, this will limit flaring to equipment depressurization volumes only. 5. Depressurized plant shutdown will be the automatic response to gas detected in environmentally controlled spaces of the process module. The gas injection plant and the gas injection well will be commissioned prior to the initial start of oil production at Northstar in November using Prudhoe Bay Unit make up gas. This will reduce the amount of flared gas that traditionally is associated with the start up of new production facilities. Page 25 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .) ,... J rUBLIC INFORMATION 5. Well Operations DRilliNG The Northstar Pool will be accessed by wells directionally drilled from the newly constructed Seal Island. These wells have been designed in accordance with standard practices and operations across the North Slope. Current island layout results in these wells being drilled on 10 foot nominal centers. Below is a brief summary outlining the proposed drilling and completion plans for both the production and injection wells. Well construction will be initiated on 20 inch structural casing which has already been driven to approximately 160 ft. below ground level for all of the wells. The structural casing will provide an adequate anchor for the diverter system. and support any shallow unconsolidated strata. A diverter system compliant with 20 AAC 25.035(c) and 30 CFR 250.409 will be nippled up during surface hole drilling operations for the first five wells, during which the required data for a diverter waiver application will be collected. A diverter will not be rigged up for the remainder of the wells drilled at Northstar, assuming that BPXA, the Commission and MMS reach mutual agreement concerning the interpretation of the data. BPXA will request Field Drilling Rules from MMS at a later date in order to waive the MMS diverter requirements of 30 CFR 250.409. Conductor casing requirements as outlined in 20 AAC 25.030(c)(2) have been waived for the Northstar development as per the memo entitled "Dispensation for 20 AAC 25.030(c)(2)" dated March 1, 2000. The structural casing provides an adequate anchor to allowing drilling to the surface casing point at which point the blow-out preventer ("BOP") stack will be nippled up. Surface hole sections for all wells will be drilled to a depth of approximately 3160 ft. TVDss (150 ft. TVO below the SV6 marker). Intermediate hole sections for the gas injection wells will be directionally drilled to top set the Sag River formation at approximately 10,645 ft. TVDss, while intermediate hole sections for the production wells will be directionally drilled to top set the Miluveach formation at approximately 9264' TVDss. For production wells only, a second intermediate hole section will be required and will be directionally drilled to top set the Sag River formation at approximately 10,645 ft. TVDs. Both production and injection hole sections will be drilled through the Sag River, Shublik, and Ivishak formations to a TO in the Ivishak or the adjacent Kavik formation. f>age 26 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ..) ..) PÚBLIC INFORMATION All casing strings will be run and cemented in accordance with 20 ACC 25.030 and 30 CFR 250.404. Injection wells will have a cement evaluation log run to confirm isolation of the injection fluids to the approved injection intervals (Sag River and Ivishak Formations) as required per 20 AAC 25.030(d)(7). Such logs will also satisfy the requirements of 30 CFR 250.404(a)(5). The casing and tubing heads will be nippled· up with the BOP stack and tested according to Commission and MMS regulations. Leak-Off-Test ("LOT') and Formation Integrity Test ("FIT") will be performed on all casing strings after drilling 20-50 feet in accordance with 20 AAC 25.030(f) and 30 CFR 250.404(a)(6) or as approved by the drilling permit. In addition to lined, cemented, and perforated completions, it is proposed that the Pool Rules authorize the following alternative completions: 1. Horizontal or "high angle" completions with slotted or perforated liners. 2. Open hole and/or slotted / pre-perforated completions. 3. Multi-lateral completions in which more than one reservoir penetration is completed from a single well. Tubing will be run in all wells with a packet. Injection well design will place the packer within 200 f1. of the targeted injection zones, the Sag River and Ivishak, in accordance with 20 AAC 25.412(b). Although this packer placement may result in a packer to perforation distance greater than 200 ft., it retains the option of perforating the Sag Riverin the future and it does not compromise zonal isolation given the depth and thickness of the overlying confining zone (Kingak formation). The drilling schedule for Northstar should follow a drill and complete scenario based on current planning. Batch drilling of surface and/or intermediate holes may be initiated dependent on broken ice restrictions and logistical constraints. BLOWOUT PREVENTION EQUIPMENT Blowout prevention equipment ("BOPE") will be rigged up and tested in accordance with Page 27 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .' ) ., rOBLIC INFORMATION 20 AAC 25.035 and 30 CFR 250.406, .407, .515 and 516, as applicable. Any modifications to previously submitted BOPE diagrams will be updated and submitted with the appropriate Application for Permit to Drill ("APD"). A diverter waiver request will be submitted if the above referenced shallow gas hazard identification indicates that no shallow gas hazard exists at Northstar. DRilliNG FLUIDS The drilling fluid program designed for Northstar will be prepared and implemented in full compliance with 20 AAC 25.033 and 30 CFR 250.410. Formation pressures for all horizons to be penetrated are known based on the Seal Island appraisal wells. DIRECTIONAL DRilliNG Conventional MWD surveys will be used at Northstar. BPXA requests that the detailed reporting and plotting for directionally drilled wells required by 20 AAC 25.050(b) be waived for the Northstar Pool. Current regulations require extensive data packages with the APD on all wells located within 200 ft. of a directionally drilled well. All drilling at Northstar will be confined to the Northstar Pool and Northstar Unit boundaries with established working and royalty ownership. Instead, the Operator requests that the following information be included in each APD: 1. Plan view; 2. Vertical section; 3. Close approach data; and 4. Directional data. WEll DESIGN Current development plans for Northstar include five gas injectors, sixteen oil producers and one Class I disposal well. Three of the gas injectors will be completed with 7 -inch tubing and liners. Two of these wells will be pre-produced for a period of between 3 and 6 months, and will be completed with 13 Chrome tubing and liners. The remaining 7 -inch gas injector will be placed on dedicated gas injection service from the start of operations and will be completed with L-80 grade tubulars. The other two gas injectors will be completed with 5Y2-inch L-80 Page 28 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ., ) .-~ ..bBLIC INFORMATION tubing and liners. The sixteen production wells will be completed with 4Y2-inch 13 Chrome tubing and liners. Exhibits 22 through 26 show wellbore schematics for the completion designs. The detailed casing program will be included with the APD for each well and documented with the Commission or MMS, as applicable, in the completion record. API injection casing specifications must be submitted with each APD. All injection casing will be cemented, tested and its mechanical integrity verified in accordance with 20 AAC 25.030, 20 AAC 25.412, 30 CFR 250.404 and 30 CFR 250.405. The detailed well casing and cement program will be submitted with the APD for each injection well. Injection well tubing I casing annulus pressures will be monitored and recorded on a regular basis. BPXA, as Operator, will be responsible for the mechanical integrity of injection wells and for ensuring compliance with monitoring and reporting requirements. The tubing I casing annulus pressure of each injection well will be monitored weekly to ensure that there is no leakage and that the pressure does not subject the casing to a hoop stress greater than 70 percent of the casing's minimum yield strength. However, if an injection well is deemed to have anomalous annulus pressure, it will be investigated for tubing lannulus communication using a variety of diagnostic techniques and a mechanical integrity test. If a subsequent investigation proves hydraulic communication between the tubing I casing exists, then a plan for remedial action will be formulated and scheduled. In addition, a variance will be obtained from the Commission or MMS, as applicable, to continue safe operations, if technically feasible, until the remedial solution is implemented. Tubing I casing pressure variations between consecutive observations need not be reported to the Commission or MMS. A schedule will be developed and coordinated with the Commission which ensures that the casing I annulus for each injection well is pressure tested prior to initiating injection. A pressure test will consist of subjecting the injection well to a test surface pressure of at least 1,400 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70 percent of the casing's minimum yield strength. The test pressure must be held for 30 minutes with no more than a 10 percent decline. The Commission will be notified at least 24 hours in advance to enable a representative to witness Page 29 Northstar Pool Rules and Area Injection Order Application 8/10/2001 eq, J .) J. tlBLIC INFORMATION the pressure test. Alternative EP A approved methods may also be used, with Commission approval, including, but not necessarily limited to: timed-run radioactive tracer surveys ("RTS"); oxygen activation logs ("OAL"); temperature logs ("TL") and noise logs ("NL"). An injection well located within the area subject to the AIO will not be plugged or abandoned unless approved by the Commission or MMS, as applicable, in accordance with 20 AAC 25.105 and 30 CFR 250.701. SURFACE AND SUBSURFACE SAFETY VALVES All Northstar wells, with the exception of the Class I disposal well, will be equipped with a fail safe automatic surface safety valve ("SSV") and a fail safe· automatic surface controlled subsurface safety valve ("SSSV"). The SSSV's in both the producers and injectors will be wire line retrievable. The SSSV's will comply with the requirements of 30 CFR 250.801 and .806. RESERVOIR SURVEILLANCE PROGRAM Northstar reservoir data will be collected to monitor reservoir performance and to define reservoir properties. In lieu of the requirements of 20 AAC 25.071 (a), BPXA requests that a complete electrical or complete radioactivity log be required from below the structural casing to TO for only one well drilled from Seal Island. RESERVOIR PRESSURE MEASUREMENTS Initial static reservoir pressure will be measured in each new well prior to long term production or injection. Additionally, a reservoir pressure will be recorded in at least half of the available active wells annually. These will consist of stabilized static pressure measurements at bottom- hole conditions, or, in the case of the gas injectors where a single phase fluid occupies the well bore, extrapolations from shut in surface pressures, The reservoir pressures will be reported at the common datum elevation of 11,100 ft. TVOss. It is the intention to run surface read out real time fiber optic temperature and pressure gauges in the producing wells at Northstar. These gauges will provide additional static and dynamic pressure information above that normally available in traditional North Slope wells. SURVEILLANCE LOGS Additional surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir Page 30 Northstar Pool Rules and Area Injection Order Application 8/10/2001 performance. ..- ) p-- ) PUBLIC INFORMATION Additionally, injected gas tracers are being evaluated as a means of further evaluating the sweep efficiency of the flood. The program as envisaged would involve a separate tracer being injected into each gas injector, followed by a program of sampling and analysis of produced gas at each producer. Page 31 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ~, ) ,.~ ) PUBLIC INFORMATION 6. Area Injection Order Application BPXA, as Northstar Unit Operator, hereby applies for an Area Injection Order ("AIO") to cover water and miscible fluid injection operations in the Northstar Pool as proposed herein. This section addresses the specific requirements of 20 AAC 25.402(c). PLAT OF PROJECT AREA- 20 AAC 25.402(c)(1) Exhibit 6 is a plat showing the location of existing and proposed injection and production wells, and the original Northstar exploration and appraisal wells. Exhibit 3 contains the legal description of the lands subject to the NorthstarArea Injection Order (the "Northstar Injection Area"), and these are presented on a map in Exhibit 2. OPERATORS/SURFACE OWNERS - 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) The surface owners and operators within a one-quarter mile radius of the Northstar Injection Area are: Operators: BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Surface Owners: Department of Natural Resources State of Alaska 550 W. ¡th Avenue, Suite 800 Anchorage, AK 99501 Minerals Management Service 949 East 36th Avenue, Room 308 Anchorage, AK 99508-4363 Oil & Gas Lessees: BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Murphy Exploration (Alaska) Inc. 550 Westlake Park Blvd., Suite 1000 Houston, TX 77079 Page 32 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ,.) ~ PUBLIC INFORMATION Phillips Alaska, Inc. 700 G Street P.O. Box 100360 Anchorage, AK 99510-0360 A VCG LLC 225 North Market Wichita, KS 67202 Note: AVCG LLC has purchased Phillips Alaska, Inc.'s interest in ADLs 385198 and 385202. Assignments have been submitted to the State of Alaska, Department of Natural Resources, Division of Oil & Gas for approval. Exhibit 28 is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the Northstar Injection Area have been provided a copy of this application, as required by 20 AAC 25.402(c)(3). Lessees have also been provided a copy. DESCRIPTION OF OPERATION - 20 AAC 25.402(c)(4) Development plans for the Northstar Pool are described in Section 3· of this application. Island facilities and operations are described in Sections 4 and 5. POOL INFORMATION - 20 AAC 25.402(c)(5) The proposed Northstar Injection Area encompasses the Northstar Pool. The Northstar Pool is defined as the accumulation of hydrocarbons in the Ivishak, Shublik and Sag River formations common to and correlating with the interval between the measured depths of 12,418 feet and 13,044 feet in the Seal A-01 well. GEOLOGIC INFORMATION - 20 AAC 25.402(c)(6) The geology of the Northstar Pool is described in Section 2 of this application. WELL LOGS - 20 AAC 25.402(c)(7) Copies of all open hole logs from Northstar wells are sent to the Commission as the wells are completed. Exhibit 4 is the type log for the proposed Northstar Injection Area with stratigraphic and marker horizons annotated. Page 33 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ~ ) ~ PUBLIC INFORMATION INJECTION WELL CASING INFORMATION - 20 AAC 25.402(c)(8) The injection well casing design and additional information is described in Section 5 of this application. INJECTION FLUIDS - 20 AAC 25.402(c)(9) A description of the recovery process and development scheme is included in Section 3 of this document. Injection fluid will comprise a blend of associated reservoir gas and imported PBU gas. The composition of the injected fluids is listed in Exhibit 27. Maximum daily injection rates are presented in Exhibit 14. Fluid incompatibility problems, including asphaltene deposition, are not anticipated with the miscible gas flood. INJECTION PRESSURES - 20 AAC 25.402(c)(10) The maximum injection pressure at the wellhead is estimated to be 5300 psig. The average injection pressure at the wellhead is estimated to be 5000 psig. FRACTURE INFORMATION - 20 AAC 25.402(c)(11) The expected maximum injection pressure for the gas injection wells, 5300 psi, is insufficient to initiate or propagate fractures through the confining strata, and, therefore, will not allow injection or formation fluid to enter any freshwater strata. Fracture Gradients Exhibit 29 presents a summary of the fracture pressure and reservoir pressures determined from leak off testing, mud weights and drill stem testing in the discovery and appraisal wells in the Northstar Unit. Freshwater Strata EPA has determined that there are no underground sources of drinking water ("USDW") beneath the Northstar Unit, as stated in the Public Notice dated June 24, 2000, and the Fact Sheet for the proposed issuance of UIC Area Permit AK-1 002-A dated June 23, 2000. Page 34 Northstar Pool Rules and Area Injection Order Application 8/10/2001 f/IA-. J ~ PUBLIC INFORMATION The lack of fresh water and USDW's in the Northstar Injection Area eliminates the need for an aquifer· exemption. The presence of hydrocarbons, either live or as residual, causes the Northstar sands to be unsuitable as a source of drinking water FORMATION WATER ANALYSIS - 20 AAC 25.402(c)(12) Exhibit 13 lists the composition of a Northstar area formation water sample. The source of the sample was produced water from a production test on Seal A-01. A production test was performed to confirm the presence of an apparent oil-water contact at approximately 11,110 ft. TVDss. The water analysis was conducted by Chemical & Geological Laboratories of Alaska, Inc. on June 15,1984. AQUIFER EXEMPTION - 20 AAC 25.402(c)(13) As set forth above, the lack of fresh water and USDW's in the Northstar Injection Area eliminates the need for· an· aquifer exemption. The presence of hydrocarbons, either live or as residual, causes the Northstar Pool to be unsuitable as a source of drinking water. HYDROCARBON RECOVERY - 20 AAC 25.402(c)(14) The initial reservoir modeling of the Northstar Pool involving a waterllood only development scheme indicated recoverable reserves of 135 mmbbls of oil. The miscible gas recycle program currently yields 176 mmbbls oil, an increase of 41 mmbbls of ultimate oil recovery. The recoveries for the development options considered for the Northstar Pool are discussed in Section 3 of this document. MECHANICAL CONDITION OF ADJACENT WELLS - 20 AAC 25.402(c)(15) Exhibit 6 shows the location of proposed injection wells and existing wells. None of the proposed injection wells penetrate the injection zone within one-quarter mile radius of an existing well. The information submitted herein establishes that drilling 16 producers and 5 injectors at the Northstar project through 2003 will increase ultimate recovery without increasing the probability that any individual well will suffer an integrity failure. Page 35 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ..) ~ rUBLIC INFORMATION 7. Proposed Area Injection Order Rules BP, in its capacity as Northstar Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Northstar Oil Pool and consider the following rules to govern such activity. The boundary of the lands subject to the Northstar Area Injection Order (the "Northstar Injection Area") and the Northstar Pool Rules is shown in the map attached as Exhibit 2, and is described in Exhibit 3. Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, Class II fluids may be injected for the purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to the formation found in the Seal A-01 well between measured depths of 12,418 - 13,044 feet. Rule 2: Fluid Injection Wells The injection of fluids must be conducted through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 3: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4: Reporting the Tubing-Casing Annulus Pressure Variations Tubing-Casing annulus pressure variations between consecutive observations need not be reported to the Commission. Page 36 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ~-, , , 1'\ ) ~UBLIC INFORMATION Rule 5: Demonstration of Tubing-Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, and following well workovers affecting mechanical integrity. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casings minimum yield strength must be held for at least a 30 minute period with decline no more than or equal to 100/0 of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever injection rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue injection and submit a plan of corrective action on Form 10-403 for Commission approval. Rule 7: Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8: Administrative Action Upon proper application, 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 principles. Page 37 Northstar Pool Rules and Area Injection Order Application 8/10/2001 ~, J ,,) PUBLIC INFORMATION 8. Proposed Pool Rules BPXA, in its capacity as Northstar Operator, requests that the Commission adopt the following Pool Rules for the Northstar Pool: Subject to the rules below and statewide requirements, production from the Northstar reservoir may occur in a manner that will protect freshwater, prevent waste, protect correlative rights, and provide for the maximum ultimate recovery of oil and gas that is prudent. In addition to statewide requirements, the following pool rules are proposed to govern the proposed development and operation of the Northstar Pool. Rule 1: Field and Pool Name and Classification The field is the Northstar Oil Field and the pool is the Northstar Pool. The Northstar Pool is classified as an Oil Pool. Rule 2: Pool Definition The boundary of the lands subject to the Northstar Area Injection Order (the "Northstar Injection Area") and the Northstar Pool Rules is shown in the map attached as Exhibit 2, and is described in Exhibit 3. The Northstar Pool is defined as the accumulation of hydrocarbons in the Ivishak, Shublik and Sag River formations common to and correlating with the interval between measured depths of 12,418 feet and 13,044 feet in the Seal A-01 well.. Rule 3: Spacing Minimum spacing within the pool will be 40 acres. The pool shall not be opened in any well closer than 500 feet to an external unit boundary where ownership changes. Rule 4: Drilling and Completion Practices a) The following alternative completions are authorized: 1) Horizontal or "high angle" completions with slotted or perforated liners. 2) Open hole and/or slotted / pre-perforated completions. 3) Multi-lateral completions in which more than one reservoir penetration is completed from a single well. Page 38 Northstar Pool Rules and Area Injection Order Application 8/10/2001 .) ,. ) PUBLIC INFORMATION b) At a minimum, the following information must be included in each APD: 1) Plan view; 2) Vertical section; 3) Close approach data; and 4) Directional data. c) A complete electrical or complete radioactivity log is required from below the structural casing to TO in only one well drilled from Seal Island. Rule 5: Reservoir Pressure Monitoring a) Bottom hole reservoir pressure will be measured in at least half of the active wells each year. b) The reservoir datum will be 11,100 ft. true vertical depth subsea. c) Pressure surveys may consist of stabilized static pressure measurements at bottom- hole conditions or, in the case of the gas injectors where a single phase fluid occupies the well bore, extrapolation from surface shut in pressure. Initial reservoir pressure may also be determined from open-hole formation tests. d) Data and results from pressure surveys shall be reported annually to the AOGCC (but within 60 days to the MMS). Rule 6: Gas-Oil Ratio Exemption Wells producing from the Northstar Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 7: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering. Page 39 Northstar Pool Rules and Area Injection Order Application 8/10/2001 Exhibit 1 ., ~) '-' T'UN T1þN ¡ ; i f J ~ '-(' I I j ; ¡ J~ T13N . u ~ :¡¡¡ ~ I I ¡ , I ~,':g T i .......... i a:ø: 1IPItI.f'....__1- ~_--......-'- ;¡ I I ! : i I i I ¡ i ! ¡ I i to .-::¡ ~ J \) ~ WEST oøac /"- ~ n c @ ~¿ 1.312809 . ,~...... --. I fa CD IS ;!C 31 \' . 9- - .p i .,.. t ~~¡ £6 ~ (~.' i. tJ· (2 ¿) , ! al1I · ~,!' ~~~oò I ø: ø: , r- i r/ JX?1.~ ¿-'I 8 12 i ~ ~ BAND .. 2S :!G I ¡ i ¡ f I i I ; I ¡ 1 ~ i I i I 3J = :M 12 :!T I< T14N T13N :G :5 Z! 27 Obp NORTHSTAR POOL 1.DCA1ICN IMP ~ .. f , I ~ " J , ~ It 0 ~ I CD NorIhsIar UnI Trad: Number - NorthsIar Unit Boundary (Expansion Apple ~~ Pending) NorthsIar Lease Boundary Northstar Pool Area -28.004 Aøes - Ivishak 0' owe - Sag 0' owe 1 :78.ØOO 0 1 21011es I I I Exhibit 2 NORTHSTAR POOL Obp , - T14N T1r ~ i j i1 j , ; R I .. ¡ '- J'i I ~ / ¡ zr ~ I , S4 ~ ¡~ T14N T13N 10 Ii i J ~ ,¡ 26 u ~ 3> } 23 '2' WiW ""'Ið ã:.ã: 2 ; i ¡ i I'ß - i,. 1IESr ! ¡., DOCI[ i '!1 I I~- :u J3 æ :;s :!G :., i!o! T14N T13N v. T13N T12N 2T '" :.:i ! ~ It 0 ~ I CD Northstar Unit Tract Number - Not1hsIar Unit Boantary (úpansion Applc~ Pending) NorUAdøï Lease Boantary NorIhstar Pool Area. -28,004 Aaes 1 :7B,OIIO 0 1 2 Miles I I I .~. .:~. ~ 1..DCA11ON MAP ~ ·) ~) Exhibit 3 Description of Northstar Injection Area The Northstar Injection Area is shown on the map attached as Exhibit 2. State Leases . The Northstar Injection Area encompasses State oil and gas leases ADLs 312798, 312799, 312808,312809 and 355001 to the extent such leases are located within the lands described below: T. 14 N.. R. 13 E. Umiat Meridian. Alaska Sections 30-35 T. 13 N.. R. 13 E. Umiat Meridian. Alaska Sections 2-18, and 20-24 T. 13 N.. R. 14 E. Umiat Meridian. Alaska Sections 17-20, 29 and 30 ADL 312798 consists of Tract C30-46 (BF-46), a portion of Blocks 470 and 514 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79. ADL 312799 consists of Tract C30-47 (BF-47), a portion of Blocks 471 and 515 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79. ADL 312808 consists of Tract C30-56 (BF-56), a portion of Blocks 514, 515, 558 and 559 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79. ADL 312809 consists of Tract C30-57 (BF-57), a portion of Blocks 516 and 560 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79. ADL 355001 consists of Tract 39-01, more particularly described as: T. 13 N.. R. 13 E. Umiat Meridian. Alaska Section 17, Protracted, All, 640 acres; Section 18, Protracted, All, 631 acres; Section 19, Protracted, All, 633 acres; Section 20, Protracted, All, 640 acres; Section 25, Protracted, All, 640 acres; Section 26, Protracted, All, 640 acres; Section 27, Protracted, All, 640 acres; Section 28, Protracted, All, 640 acres; Section 29, Protracted, All, 640 acres. fÞ") fÞ') Exhibit 3 Description of Northstar Injection Area Federal Leases The Northstar Injection Area encompasses all lands within the following Federal oil and gas leases OGS-Y-1645, OGS-Y-0179 and OGS-Y-0181: ~ OGS- Y -1645 consists of: That portion of Block 6510, OGS Official Protraction Diagram NR06-03, Beechey Point, approved February 1, 1996, shown as Federal 8(g) Area G on OGS Gomposite Block Diagram dated April 24, 1996. OGS- Y -0179 consists of: That area of Block 470 lying east of the line marking the western boundary of Parcel "1", and between the two lines bisecting Block 470, identified as Parcel "1", containing approximately 94.30 hectares, and Parcel "2" , containing approximately 15.27 hectares, as shown on the Supplemental Official OGS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29/75; and That area lying between the two lines bisecting Block 471, containing approximately 611.95 hectares, as shown on the Supplemental Official OGS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29n5; and That area lying northeasterly of the line bisecting Block 515, containing approximately 189.83 hectares, as shown on the Supplemental Official OGS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29/75; OCS-Y-0181 consists of: That area lying northeasterly of the line bisecting Block 516, containing approximately 2076.98 hectares, as shown on the Supplemental Official OGS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29n5; and That area lying northeasterly of the line bisecting Block 560, located in the northeast corner of Block 560, containing approximately 44.65 hectares, as shown on the Supplemental Official OGS Block Diagram, dated 12/9n9, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29/75. Exhibit 4 Stratigraphy ~'J(Hé ..,... 1:' ~ E Q) ::¡¡: >. aI CD Q) 0 .c "'0 2 a.. c: 0 C. :¡::¡ C\' ;::] E e ¡f ø oX: - C\' :2 .c U) () ~ e Q) =a CO en ..,.. ...) t) Northstar Type Log - Seal A-01 GR (API) ~: >. .:,::"j" i [~,~nfinlng z~nei § \~~~'-~i:,::,'-'· _:'.'_)~ ¡ .......;. '. . :, . - ... - ... ... - E '.' : ':".;.;:::,'-,~"._'.~::'~' ~~~~ ¡f ............ L., CDc " ,.':' -", , -'0700- ....... ..... ~ -. . .:,.::,,,',:, .......... ~ .s, :'~'~L ~:~~;;;;i i t ~~I~~~";ëa;~~~~ie~ æ -'J ":"""""~."'I' ,- ;'*,..!;¡J..! r~l1I« ....OMO..¡'iiU: .. -.L -- -10900· ~ <'(pO ,:.:c, '0.. N ,.::ê\: :;,0' '::.;; ":::~: . ' '~.... '..<iC "~. i4iiL:' ',.~....,;,.;, :'~',~:':.' '~/~:{;~:: ".":',' ,.: '","0:.'. 'ø' '. .'.:....:.!, .....'..,~...,., {.'.~.'.:.'."!.""'.:~:,'.''" .. "'~,.':::~~. ~'.,' )(. ..~. '~..::.~~: tn........"...'....'~.,.".'.'..".".. .S:' .;::--..... - . .;~,.:::.. .~:': ~.:/~:.",'.,.. ", ~", .' ... . ....;, .':,::.c' II Echooka ~. Usburne ~-.' Group I : TVD m "'10650"' . . . . . . ............ ;.~~~~-~ E D C3 C2 C1 B . . . . . ,·f~·J1)¡h:·"'6,'t~z:· A2 ..,1100- :.::.::.;;.;; ....... ...... ....... , . . . , . . . . . A1 ·,1::ì.~~,::··~·;-:-:~';'~ .., 1150- '.' . . . ILM-DIL ::? ~I \ 7 ~ ~ :J:--:: 94 Mirrored Sonic 59 59 j ......,., ~ ~ ~ J .. ~ ~ .w ~; ~:!i1~~ :'i,S: '..,1200' ~ Conglomerate ~.",.. nclstone ''''-' ~~andY .~ ." Conglomerate ~,' , '.' ~;':;""'I.i.·:/· ''0:'-"--" J }~~~~~~ ~ ~:,:.~..;$-i~_~ { -.., 1250'~~':::=::::' n.=n,:\~": 11300~ 1 -.' ". .~-,..., .....- ,,, 0::..' .""''W. ..,0950·.. ~ _ .,._1,'_':,. ~:r., .' . -'1000- tï.y- --,.....:1 a··¡·..·~ ~ ... ,.. -.... . .- '.... ~:~~' 'n,. r1_ 1050- ""'''<+CfjC' I :-¡":-:::-:9:.t \,-~.....'" -.- ....;.. è. .;.. è... ~ ~~ ~ ~ ~ . ~~ ; 94 Shales and silts. Transgressive Marine Sands, slits and shales. Low permeability Marine slits and shales. Phosphatic limestones. Limestones, silts and shales. .~'vYYN\I\ Mixed gravel/sand & med cong Massive, pebble I cobble dense congo Medium conglomerate and variably pebbly Medium conglomerate and variably pebbly Medium conglomerate and variably pebbly F-m sand w/occ. pebbles Fine to medium sands. Very fine to fine sands. Prodelta shales. Sand, silt and shale. ~~~ Carbonates Exhibit 5 - Rev 1 Ivishak Isopach Map ~ ~ Exhibi.t 6 Northstar Reservoir Structure and Development Well Location Map ~ . -. nu. mnm: _. . .. ,- - . Planned 011 Production Well #' Planned Gas Inlectlon Wen f '-:.-...., 1 UlIIA1UII _ rv Approximate 011 Water Contact at 11,100 ft subsea oil .. .~ ~ ..-, Exhibit 7 Northstar Cross - Sections sw Seal-A-01 Seal~A-04 NE 10000' A -11000' ~ ,-/ A' l 12000' NW Northstar 1 Seal-Ä-01 Seal-Ä-02 SE 10000' B B' ~ -- ~ Kingak ~ Kavlk ~ Vertical Exaggeration = 10x 12000' " :... ~ ~ ~ g :~ SG04 SGOl TSHU TSHA TSHB --J TSHC TSHD TSAD TZE TZD TZC3 TZC2 _ TZC1 TZB TZA2 _ Exhibit 8 LONG WELL NAME: NORTHSTAR BF-46 #l API NUMBER: 500292134100 COMPANY: AMERADA-HESS CORPORATION SPUD DATE: 12-0ct-1985 WELL STATUS: P RHOG C:C:J SP BIT CALI GR OAP! ,..) (') NORTHSTAR-l MEASUREMENT REF.: KB ELEVATION MEAS. REF.: 58. 5 SURFACE ELEV.: DRILLED DEPTH: 11820 10845.2 ~': :::.:':',: .:',: :'i?; ~:~¡~:~:~{ t¡'~~:¡ KH . LLS LLD ILM ILD ~ ~ ....~ 'L.... ê t f . c ~ ~ N ~ .. = 'õI . 1/1 :5 . .. ~ 0 t " ':I "'.. ~Ë II IIN U U .0 II S!S ~ N 1/1 f4 G 10907.0 11000 . ¡ ~ . . ... 11100 11200 11300 __01',.... 11360.0 -11297.7 PHE::' ?"-'O(Jtb'l . . NPHI ?,1't,l) bll DT 2(11)0 1"1) US:I·' RHOB :'.\11111 1.6~ 0/C3 2.&~ 10900 ~;~ ~~,~H~~¡tj i~~~;~, . iï iiìiiií . .. ;).4 -- .', ;i~ ~~? III ,:':'..::.~.'. ,:;."'!:'~: "; ';~: l_fS~< ~=~::':.:,::::.~..~a !~~i ;',~~:';~,:,~::?:: '::.,:':-':.,:'..:: .~- ~illiit~ . · a -._.~... ~,- > '~'~ .~ -~- ~<- Jrj< ~. ~:::- ) . __þ ~ 1 ¿q2 .¿ ';< · . ==-- 11000 ;~~:~t' 4~ ~~ ~ I ~ ..... ... ^' ". '~ .~~,.~ r 11100 ...... --c-.:.....,.,.... ,. ~ ~~~ ~':'-;-~~ ~': < <,( ", .~~ ;.:~~ K"~J:: ~ ~tt1.~ ,',',~":; ,~:;~ ~ ~~~. f'.....-\;'-;"A . ~ S-;Æ ~'i;;': '"., '.:'~: ~ ~~ ~ ::> .;. ~fill .., :'~;~:-:::;!:. \ · ·'1' .. . 11200 ¡: ;'.~i~~ '-~ ~'t'!w:::;~ ! .,.: ~~-;::;; li~;~ ~rili f -\ ~~ ~,~~; ~~~~. :: -:::: :: ',:: . .......... .. ..: ~:..:.:~:=.) :;, -- ---., -. .. ....... .. i. . .'.. .. ...:.... -,- .. .'...;. .., --- ,.) Exhibit 9 LONG WELL NAME: BF-47 NO API NUMBER: 500292095400 COMPANY: SHELL OIL COMPANY SPUD DATE: 01-Jun-1983 WELL STATUS: P SEAL ISLAND A NO 0 RHOG I!J ""J = SP 5 -) ~~ ~ BIT D III 0 i< CALI GR GAP! no i2419.0 -10668.4 'l'SGR -=;::.. SooM r 'l'SHU 'l'SHA ~ 'l'SHB ~ 'l'SHC ---- - 'l'SHD r' TSAD -'.~ 'l'ZE 'l'ZD TZC3 . . Tzc2 . . TZC1 ç . - . . . . TZB . 'l'ZA2 '~. :;::<:~:'! D,': ~;,,;}};~:~;,;:~; ...-'":"_............ :ti¡:~i~H~ ;¡~~ ~If- ~~,: ,,:,.>, =''''",,"-,,::<'''''~i:'\ " ":',:~,,~,:-\..:' ' ':";~~'" ;',>':':~~.." e~~:-- ~ ::~ T""'·' . ~Ic ;}i.:-· SRAL ~ ., ~ ~ ~ ~ 0 III ., .. . ~ . 1) . 1/ . . > ~ ¡a ., ø.~ . . N . N U H .. . .<: 0 ., = ~ 1>1 ~ I/ u > a oJ. . .:: ~. D ~ = II ~. I!J ~. fl. -10700 " ",;..S; :{~)~~~ ::,:,~".,: 12500 -,10800 12600 12800 12700 -10900 -11000 , " ""'.. .~.... . .~~~ r:;~~ \ ":: :- i: .:' .;"r:....::~.~: . ", ···iit.~« ~~:.!,"'2-;.-;.~ ~ ". :.', :~:-:-::-:. - . - -- -. . . . ............,.., ..... . : :,...,_..ur- _~. ~: ~~.~f~:,?;~ ., ...,.....c,...",.-_ . : -'~ ·~~~:.t;. . 12900 ;.. ~~ . ':J.~l.~.- t:··· " .!il!;-~~. ..... .' ~'M'~~ 4:..r- " ..~~': ~::.~~ . " "---~--- . ~ _' '{{!' 'r~~[; -- .. ' ...... ",.,',.' .... '.....'~.. ... ....' , '. ". ~.,:, .... ....... ..:';',r ...'~- ~.~.. :',~ ,....-,... ',.~:, ,.::.:) ;~;~~~~.., ..~,';" ....'.. .'... l!" ~::,::"~ ::-:<::::. -11100 ~..~ ,,'. ""',., ..,' ., .... ',: ," .........~. .. . ',,' ,..~, .,......... . . " ,., ..' .. ,'.,..... . . -. . .'.. I -11144.0 ~ ..... ...... r) A-Ol MEASUREMENT REF.: KB ELEVATION MEAS. REF.: 56 SURFACE ELEV.: 22 DRILLED DEPTH: 14541 KH LLS PHBL . NPH 1.. DT RHO a~3 2.65 LLD zoo" ? o ILM zooe : ILD 21H)0 ~' ;:000 1.6 J 1 .....---.... =- ~~ 't- ~?< .' ~.~ Jç:::. , ..~ ~'-- r -s-~. ~ . ~ ~ ~ ~f:~' . : ...... · , -.. .. - < _.~..,. - !=..- ~ ~ ~- ..~ 50- . . - . ... ;.- . -- .. - .' . . . . e· . .--. . . :-..~. - -. e_ , . -'- .e . .,. ¡-_III _III # .;;:\ .---............ r'~~,..-...-.....IIIII!III-_··..,.~....-....-~-.... Exhibit 10 fÞ') LONG WELL NAME: OCS Y-0181-01 SEAL ISLAND A NO 0 API NUMBER: 500292107400 COMPANY: SHELL OIL COMPANY SPUD DATE: 04-Feb-1984 WELL STATUS: P RHOG 2.5 QlC:' . ø II: SP 5 -150 ~ BIT II< :~ 0 Ii CALI GR Gl\PI ~ ~ ~ \,,1.' - If L.,. r~ TSHU J ~-1.~~~ TSAD TZE TZD TZC3 TZC2 TZC1 TZB TZA2 .. I . ~) SEAL A-02A 1,5 ~ v. .. I ~ i ~ .d N 0 PI .. V. .. ~ III ~ H " ~ 2 ß '" II . ~ '" ., ~ > :J , .. .. 24 ø.~ ., ~ 0 H ~ ~ H 0 '" v. a E " . .d 8 ., ... '" H 1111:: 111 '" I> = ,. ø 2 o. 2 150 o. 12246.0 -10658.3 1230 10700 o .-..J 1240 o 12784.0 ~qq.o 10800 ··.·..0 :I .~ .. '~i , 1250 o 10900 1260 o 11000 1270 o :} ~~j. ~¡.; ;!: ~<i~ ;~~;I¿~ {i;.~~~¡ ~,,...~"'t~~~.~: :;.::.:. ~i::;..,''!':'...3I : '. . . . :. ':; ,.."..... . :.~~,i~~~-~~~~-~~~. :: .,.~:<:I.: ,:.:':':,:::'.~: r.?: '.':',"~(¿ I.~.~:'~~.~' '. i~,·.:·':: ::<:,:,::",: :: '::~~:: '~~-~'~~;; ....~.-..;..;..:.:.. :~. . " I...·'...· . . ~ ... - . '~;,"""" ·~i~':::... MEASUREMENT REF.: KB ELEVATION MEAS. REF.: 55 SURFACE ELEV.: DRILLED DEPTH: 13078 KH . 2040 LLS 0_ 2000' 5 LLD 0 0_ laoo &: ILM 0 2000 15 ILD 0 20001.6 .,¡ . ., . .. ... ...., .. '. . _..\- ( " , . -...--..- .\ LL . ..,. .. . . , .. .' - . . . . . . .' . " ." . . . .' . . . . . . . " . :.. . . ~ . . . . .. . . · .,'~ . · -'.,...-- . . .. , ..... . . "- . .. · . .. .. ; .' .. ..~ . ." . .. PHI;;:, NPH ..b DT 50 RHO Q~ 2.65 ~ ~ .i.. .~{ ~ ~ J ~ ¿.Js --:= - , ~r- }~ ?-. ? ==- ~ ::::> ~ TSAD TZE 14500 TZD . 14600 TZC3 I!I ~ 0: ~ Po o E< TSGR ~ SGGM TSHU TZCl TZB TZA2 MEASUREMENT REF. : KB ELEVATION MEAS. REF.: 55.6 SURFACE ELEV.: DRILLED DEPTH: 15455 IŒ 0.2 . 20M " LLS PHBL II ., 0.2 nHlÐ! 200(, 60 ØI .: LLD NPHI ., ft 0,2 200('1 61'1 I!I ILM DT 0.2 nHlÐ! ::!MO 130 ILD RHOB (',,:2 :!r,I)O 1.65 Ole) 2.65 . :¡þJIi~:\1 :!¡!:'i;~ ~ .:: ~_._..: -.....:....... _ ...at.·_~~""'·I~~ . ""0 ~ ','".. (~~~~~.. . . -11000 ':¡,:,~ '. ~~ï.¡;~ ": ~~ ~ ",J!l';~'::'= .'!~ ' ~:¡';:-'';¡~~ _ 1~~" ~f;~· ~,,¡ ~l . tì' .~~ ~¡::: " ~",::,(!.':;;ê~.'>¡;"",:" -~ )jl~~ -11100 ~ "~'J:.;F.I;i: ,? . '- If. ~ ·.~Jt'...:Jc:Þ..~r_.. . .- r":'~~?':f: h '. -, t...~.':' .. - .>·:~'f }.,~. - ...:. ~~~. ~~i':} · '~ ;t~.p ." :' ~~~'" - ',';' "o-¡;; .) Exhibit 11 SEAL LONG WELL NAME: BF-57 NO API NUMBER: 500292113000 COMPANY: AMERADA HESS SPUD DATE: 09-Jul-1984 WELL STATUS: P SEAL ISLAND A NO 0 RHOG 2.5 . Q 3.:> t ., .: .; .; ,I 0 Po ., .: c PI ,I +' " H H " <II II . " +' Þ ) ~ ~ M ., 2' 110" " . 0 II 0 " .. PI · ,I 0 II ., . ~ Q: r<1 : ØI U E< :> = SP -150 BIT CALI GR OAPI 150 -14206.0 -10812.' Ii: f~U . . ~ ~ ~ .' - --....,... 14300 -10900 14400 """""-- 14700 :¡:: ç-~ tt ~~ 1~ 14800 -11200 14900 : iE:31ii~ :~·~3:~> ::::;::::: ::-. ~'.:- ~... ~. - 14960.0 -11257.2" .... .... ..) A-03 --ç- ~" .~ ~--!'¿-,"~' ¡ ~ . . . ~ ~ OJ, '--~~ ~. -.;;? -,fa- ~ ~ --, .,. ~. ¡:::-:- ~ -- .. -- ~ $ ~I ~~ ~¿ ~~ . .. , . Exhibit 12 fA, ) LONG WELL NAME: OCS Y-0180-01 SEAL ISLAND A NO 0 API NUMBER: 500292123600 COMPANY: SHELL OIL COMPANY SPUD DATE: 19-Feb-1985 WELL STATUS: P RHOG .. 2,5 Gr':::3 ~ SP ~ -150 .. BIT .. IN 0 .. CALI IN GR GAPI TSGR r ~ (~ 800M ¡ ~~ ---~ ~- ~ ~ ~ '--- -~ TSHD c-. TSAD C' - \ TZE TZD \ f TZC3 TZC2 TZCl TZB TZA2 ) ~ SEAL A-04 MEASUREMENT REF. : KB ELEVATION MEAS. REF. : 54.54 SURFACE ELEV.: DRILLED DEPTH: 16090 KH at 0.2 MD 2QOO ... LLS PHBL .. 0.2 OIU,IM 200ot60 '^ c' 'i LLD NPHI 0.2 OIU,1I{ 2QOO 60 ILM DT 0.2 OHHH 2000 150 US/F 50 ILD RHOB 0..2 Ote'iN 20001.65 G/C3 2.6S " 3.5 ~ ... c .. .. '" 0 .. ... C " ... '" .. ... II .. ~ .. " .. at 24 ~: ~:: 0 N .. .~ '" 0 .... ,,: ..: .. u .. >= 24 150 1 ~960. 0 -11U;:S~. -15000 11100 ~ 15100 11200 -15200 11300 --15300 11400 ~5- 15400 1"5436.0 -11455: I iii I ~~~þ ;; ..~':~:;:.; ~~,~,~.."":""..,~ ':':'.~ ~',',':".. "r'",·,· ,,¡',' '\'\"'.('::" ~,~/.'.:~}:---- \;.~:..,'," '~f'~;i,':':' :;. ;.....),>;~~,... ;~'~t:.:·:i,. ·TY:>:Y;' " "..' -' ....' ... .... .... . ~. I ",_ . '.!' .: " " '. .'... "...:. I""""...· '. '-.' ,.. ....~, ~;.. '. ,.:"., >, ~~;:~:~: .~;:::~ .';' ... ".:.:.,:,.. :tf!K :,.::.l~,w~n ;.; ....,. "¡;"~.,.--. , .::-:!'"~;~-:. . .'. '.... .''; . !~~ ~!~~~ ".' .',' ~ ~. . '. .::.. ,', .,' 0' ~ '. .. ~ .............'.; I..·.....·. .,-~ «f~-- ~ ~ ~ ( ¡-" ~ .~ ---..> ~ ..ç=-~ ~~..~, ~c::: . . 5 ."IIrr._ ~. ] ~-~ > ":'" ., ~ -..- b ....:L. ''t>- ~ . e· '{ -> .' ) fJ-) Exhibit 13 Chemical Composition of Seal #1 Formation Water Sample Component Concentration (mg/l) Ca 575 Mg 12 Na 7540 Fe 115 Sa 1 CI 11800 HC03 1425 sol 130 K 45 Sr 20 Total dissolved solids (TDS) 20804 Measured Resistivity 0.36 @ 68 deg F Resistivity 0.10 @ 245 deg F Source of sample: Produced water from Seal #1 , ~ . ) .~ Exhibit 14 Northstar Miscible Gas Flood 65 mbd Plateau Rate Liquid Production Profile Gas Production and Injection Profiles 70 700 I I I I I I I . . ....- Black Oil (mstbod) I , \ 600 60 -Produced Water (mstbwd) - - . , . . . , î -.- NGL (mstbd) // .§. 50 ~ 500 .! i u III II) ~ 40 E 400 0 .5. ~A tš .s .a 30 - -: It - ::J a :::t:=;- _ -~- /1300 ... £ - . fI) III ~ 20 . -. C) 200 I a' t t ::; . r- t -a-Produced Gas (mmscfd) 10 . ............ 100 / A ~ A .+ ¿ L .1 .:. ..\ -'-Injected Gas (mmscfd) 0 /,J A lI. 0 \ N N N N N N N N N N N N N N N N N I\) I\) I\) I\) I\) I\) I\) N I\) I\) I\) I\) ~ I\) I\) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ~ ~ w ~ en ¡» 0 0 0 0 0 0 0 0 0 0 ~ ~ w ~ en m ~ I\) (3 .>. UI <» """ CD co I\) ~ I\) (0) .>. en CD """ CD co Cumulative Liquid Production Cumulative Gas Production and Injection 180,000 I I I I I I I 3,000,000 I I I I I I I I I I Þ 160,00C -+- Black Oil 159.3 mmstb - . . . '[ 2,500,01 ...... Produced Gas 2.485 TCF I ¡ 14000C -- Produced Water 151.2 mmstb __ - ~ -; , -*-NGL 16.9 mmstb I . . ~ -Injected Gas 2.757 TCF e :8 120.00C - - ~ .s. 2,000.000 u - 11) .a 100,000 - ~ ftI 0 C) 1,500,000 ìi: 80,000 ----- ~ ~ fI 1; ~ 60,000 '3 1,000,000 1ii '3 e 40,000 ::J E CJ 500,000 ::J CJ 20,000 -- A .:. ~ ;& A A A A .:. 0 .:. A 0 - I\) I\) N N I\) N N I\) N I\) N N I\) I\) I\) I\) I\) N I\) N N I\) N N N N I\) N N N N N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ~ 0 0 0 0 0 0 0 0 ~ 0 0 0 0 0 ô ~ ~ w ~ en m 0 0 8 ~ 0 0 0 0 0 0 ~ w ~ en m ~ N (,) en () """ CD co ~ N en () """ CD co Water Cut Gas Oil Ratio 100 80,000 90- 70,000 ~ 80 - ~ 'ii 60,000 ~ 70 - -- ~ oC i 50,000 ~~ ~ 60-- ------.. -. c.- CJ 50--- -~~ ~ .! 40,000 ~-r ... ~ .s 40- ~ 30,000 ~ 30 ~~ _.=-~ ~ 20 - - C) 20,000- ~ 19~ 10,000 --~ 0 r N N N N N N N ~ I\) I\) I\) ~ I\) I\) N N I\) I\) I\) I\) I\) I\) I\) I\) N I\) I\) I\) I\) I\) I\) I\) 0 8 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ~ 0 0 0 0 0 0 0 0 0 0 ~ 0 0 ô ~ ~ w ~ en m 0 IG 0 ~ 0 0 0 0 0 0 ~ w ~ en m ..... I\) (3 .>. UI <» CD co ..... (0) en CD """ CD co ~ ~ 180 140 î ;1 120 1 100 .¡ 0:: c: 80 ~ u CD 60 Š Š 11II 40 3: . 'Ã-O ~ ;» 160 20 Gas Production and Injection Profiles I I I I I I · \ I ......Produced Gas (mmscfd) ~ ""'-Water Injection Rate (mstbwd) L "\ \:' . I\) o m . I\) o ~ Exhibit 15 Northstar Wateñlood 180 160 140 120 100 60 60 40 20 ° :E u CI) E .§. S II 0:: III III (! ------. - I\) o ;» I I I I I .....BIack Oil (mslbod) - Produced Water (mslbwd) -Ir- NGL (mslbd) . I\) o ~ !" I\) o ~ ~ . I\) ~ Liquid Production Profile t .!. I\) o Ô . I\) o o CD . I\) o o c:o . I\) o o --oJ L I\) o o C1I . II.) o o (1J 70 60 '6' !. 50 GI '; 0::40 c: o ~ .g 30 ~ ~ 20 0' ::¡ 10 o ... ,"-J 3 ..c '0 g ]! () G) s s ~ j 1Q "5 E :3 () I\) o ~ CumUlatl, s Production and Water Injection 450,000 I I -..' ~ ~ - 400,000 .",...-.: . . . ~~ :.- -- - - 350,000 " I 300,000 / I _ 250,000 150,000 / _ 200,000 100,000. - 150,000 ......Produced Gas 253.6 BCF - 100,000 50,000 / ......,.;.- W.Is,"'B.9 """"'" ~- BO,OOO I I I I I I . o· I\) I\) I\) I\) I\) I\) I\) I\) I\) I\) I\) I\) II.) II.) I\) o 0 0 0 0 0 0 000 0 0 000 o 0 000 0 0 0 0 ~ ~ ~ ~ ~ ~ ~ I\) ~ ~ (1J C1I --oJ c:o CD 0 ~ I\) ~ (1J C1I I\) o j\) I\) ~ I\) o Ô I\) o o CD I\) o o c:o I\) o o --oJ I\) o o Ø) I\) o o (1J I\) o o ~ I\) o o ~ I\) o ß I\) o ~ 300,000 'ù ~ 250,000 g B 200,000 :3 "'C e a. lJ tV CI ~ 1Q "5 E :3 () o I\) ~ (1J - A I\) o c» . . - I\) o m ""'-BIack Oil 128.3 mslbo -Produced Water 141.7 mmstbw ..... NGL 6.6 mmstb I~I£!~ I\) I\) I\) I\) ~ ~ ~ ~ o .- N W A I\) o :Þ I\) o j\) Cumulative Liquid Production ~ .6 I\) o o CD - I\) o o ~ I\) o o ~ I\) o o I\) I\) o ~ 180,000 ¡- 160,000 1140,000 ~ 120,000 u .g 100,000 I;. 60,000 CD ¡ 60,000 "S ~ 40,000 Co) 20,000 ° I\) o ¡;) I\) o o c:o I\) o o --oJ I\) o o Ø) I\) o ~ 0--0 0--0_ Gas Oil Ratio - "'--"'- ~ ""'Q",... v -0 v r'L \~ -, 2,040 2,020 i 2,000 ;:: ! 1,980 ~ 1,960 (! 1,940 1,920 :::J COO c Water Cut --- ~~ ---_-/ - -/ --- ~ I\) I\) ~ ß g ~ I\) ~ 2 ~ 100 60 60 40 20 o ~ :; Co) ... S ~ I\) o c» I\) o ~ I\) ~ ~ I\) o ~ I\) o j\) I\) ~ I\) o Ô I\) o o CD I\) o o c:o I\) o o --oJ ~ o Ø) I\) o o (1J I\) o o ~ I\) o o ~ I\) o o I\) I\) o ~ I\) o c» I\) o m I\) o ~ I\) o ~ I\) o j\) I\) ~ I\) o Ô I\) o o CD I\) o o c:o I\) o !:3 I\) o o C1I ~ -' ~ -.' Exhibit 16 Northstar Gas Cycling Liquid Production Profile Gas Production and Injection Profiles 300 70 I I I I I I ~ -+-Black Oil (mstbod) . 60 \ ---Produced Water (mstbwd) - 250 · î .....NGL (mstbd) - ...... .5. 50 '6" 200 ). ~ -- _ u ~ w ~ 40 ~ ~ ~150 ü S ~30 ~ ~--~~ ~ .. f · ------ !IJ ~ . . Æ 100 I :¡ 20 - ~ ~ I I .....Produced Gas (mmscfd) . . . 50 10 . ... t . . . : I ---Injected Gas (mmscfd) o It"'" .A',:,..- " . . . . . ... ° I I I I N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N ª ß § ~ ~ ~ ~ ~ g ~ ~ ~ ~ ~ * ~ ª ß § ~ ~ ~ ~ ~ g ~ ~ ~ ~ ~ ~ ~ Cumulative Liquid Production Cumulative Gas Production and Inject/on 160,000 I I I I I I I 1,400,000 I I I I I I I I B 140,ooo=j -+-BlackOiI123.6mmstbo I - 1,200,000-1 ....-ProducedGas1.152TCF I CII _Produced Water 137.2 mmstbw ~ ~ .....lnjected Gas 1.094 TCF .5. 120,000 "'-NGL 12.1 mmstb .- ...,..,.... ----"" I/) 1 000000 S' --.ÿ ~" g 100,000 -- , . t ¡ 800,000 "ë 60,000-- -_._~ - --~ ø ~ 60000p- .____ I ~_ .. ~. i 600,000 ¡ '~ ~ 400,000 ::J 40000-- __ ::J E ' f.) a~_ ~ . . . . . --f ...., . A . . I 0' - 0 - g g g g g g g g g ~ ~ ~ ~ ~ ~ ~ g g g g g g g g g ~ ~ ~ ~ ~ ~ ~ ~ N W ~ ~ œ ~ ø ø 0 ~ N W ~ ~ œ ~ N W ~ ~ œ ~ ø ø 0 N W ~ ~ m Water Cut Gas Oil Ratio 100 40,000 ~ E: __~~~-~~-==~.~~__ __~__ ~ 0 ~ 0- i ::: - --c ---lor 1\ ~ 60. _ - ~. ~ 25,000- - ~ ~ 50·--·- -.-'-----v ~ - ! 20,000 ~ .!! ~o--~--- . -- - I\i: 15000 ~ ~ 30----- _________ 0 ' ~ 20..- __.._____ ø 10,000- ~ 10.-- _._ _____ ,_,_" -- 5,000 - .-> o-c:l' ° 0 0 cr- ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ß ß ~ ~ ~ ~ g ~ 0 ~ N W ~ ~ œ ~ ß ß ~ ~ g ~ g g 0 ~ ~ ~ ~ ~ m Exhibit 17 Northstar Primary Depletion ~ ,--' ~ ......Produced Gas (mmscfd) Gas Production Profile I ' I \ j ~ 120 100 20 o 80 60 40 æ u III E g .s ~ III ill (!) Liquid Production Profile I I I I I -.- Black Oil (mslbod) _ Produced Water (mstbwd) ......... NGL (mstbd) ..J . . . . . . :. .1 .. A .:. t-) t-) t-) t-) 000 0 C;; ~ Ui m - . t-) o N . . t-) ~ - . t-) o Ô 70 60 150 ~ 0:: 40 c .2 Q .š 30 e a.. ~ 20 cr ::ï 10 o Cumulative Gas Production 200,000 I I I I I I 180,000 - .....Produced Gas 184.5 BCF I 160,000 --4 140,000 - 120,000 100,000 80,000 60,000 40,000 20,000 ° Cumulative Liquid Production 100,000 I I I I I I 90 000 ~ -+-Black 01189.1 mmstb I ' _Produced Water 61.2 mmstb 80,000 -*- NGL 5.1 mmstb . 70,000 -- --- 60,000 50,000 40,000 30,000 N ~ 0) N o ~ N o ~ t-) o W N o N N ~ N o Ô N o o co N o o co N o o -., t-) o o 0) t-) o o (J\ t-) o o ~ N o o (0) t-) o fa N o ~ . t-) o o N N o ~ ~ ~' ,- ;;ill C" U III E g III ill (!) ell ~ 1\1 'S E :I Q .....---- A N ~ 0> - N o ~ ¿ N o ~ """" Dr A N o N A t-) ~ .. N o Ô .. t-) o o <0 A N o o 0:> - N o o -., .. N o o 01 .. N o o ~ .. N o o (0) .. N o o N 10,000 o f g c o = u ~ a.. ¡ 1\1 'S E :I Q N ~ 01 N o ~ N o ~ N o C;; N o N N ~ N o Ô N o o <D N o o 0:> N o o -., N o o 01 N o o (J\ N o o ~ N o o (0) N o o N N o ~ N o C;; N o o (J\ N o ~ N ~ 0) N o ~ N o ~ N o W N o N c ~ Gas Oil Ratio N o o 0) N o Ô N o o <0 N o o Q) N o o -., ~ t-) o o (J\ -" N o o ~ --0 ~ N o o to) N o o N t-) o ~ 3,500 3,000 i' 2,500 ~ 2,000 III ~ 1,500 g 1,000 500 o -- '!) 0 I\) o m I\) ~ C1I Water Cut 100 90---- ~:~~.~-=~~ 60 - --- ---- :~-'-~-'--~-=~': :/_. ..-.~".-:: < ~~ ~ 10 o - ~ ~ I\) I\) o 0 0 0 I\) I\) ~ I\) ~ 0 g 0 .þ. C1I 0 0) I\) o ~ I\) ~ t.) I\) ~ I\) I\) ~ .... I\) ~ o I\) o o co I\) o o (XI I\) o o ~ ~ '5 Q .. .s ~ .. --" ., -' Exhibit 18 Northstar Miscible Gas Flood 72 mbd Plateau Rate Liquid Production Profile Gas Production and Injection Profiles 700 80 I I I I I I I 70 · , -- -t-Black on (mstbod) - 600 \ -Produced Water (mstbwd) - , . C' , . .; , , , î 60 .......NGL (mstbd) - 0 I · E _ 50 -; ~' ~50~ ~400 c E o ~ ~4O S -5 I}, 300 I ~ 30 ~.. I!' = ...; :::J = = ::.-e--:-..,j- 13 I ,,_ C) ~ -- ~ ~æ I ::; . . t -'-Produced Gas (mmscfd) '.e . 100 - 10 .... A', Y . 'I -+-Injected Gas (mmscfd) ./ ..: 4. A ~ 6 . o & 6 A' - - 0 ,I I I I I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ N ~ ~ ~ ~ ~ ~ ~ N ~ ~ ~ 858 8 8 8 8 8 8 ~ ~ ~ ~ ~ ~ ~ 8 8 8 8 8 8 8 8 8 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ m ~ œ ~ 0 ~ ~ ~ ~ ~ m ~ ~ ~ ~ ~ m ~ œ ~ 0 ~ ~ ~ ~ ~ m Cumulative Liquid Production Cumulative Gas Production and Injection 180,000 I I I I I I I 3,000,000 I I I I I I I I I I I I _ 160 000 j -+-Black Oil 160.0 mmstb I ~ ~ ""-Produced Gas 2.541 TCF I I ........ æ' _Produced Water 153.5 mmstb ~ _~...... ~ 2 500,000 ~ · æ 140,000 ......NGL 16.6 mmstb .. - - -- 'ti' ' _Injected Gas 2.805 TCFI ~, ~ .~ I/> I~' .§ 120,000 ------- -----____=_ , ~2,OOO,Ooo - ...' ~ ü ... - - -; ~ i 100,000 --- - -. tß 1500000 ... - lilt J . a. 80,000----- ~ CD - ~ ~ 1,000,000 -- ~ E ~40000 -- ~ ~ ' 500,000 20,000 - - - . 6 - A A IIr ~ 6 , o ..:., 0- I I g g g g g g g g g ~ ~ ~ ~ ~ ~ ~ g g g g g g g g g ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ m ~ œ ~ 0 ~ ~ ~ ~ ~ m ~ ~ w ~ ~ m ~ œ ~ 0 ~ ~ w ~ ~ m Water Cut Gas Oil Ratio 100 80,000 I 90---------- 70,000 I I .n o 80------·--- _ ~ 0- -60,000 -JoT ë 70---- ---- -. ~ ~ - æ ...J.J 'S 60- -- -.--..---- ~ .0 ---- ~ 50,000 - - .-tV o 50--- -.--~ -- - - III 40000 --+---- ~ ~ 40 - ----- --- --- -- - -- ~ 30'000 - ~ - ~ 30 --- ~~ g 20:000 ~- 20-- ~---_._---- ~ 10 -- .LY'._ - - --- ----- u - 10,000 0() oCr I O~ 0 n on 0 , ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ß ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ w ~ ~ ~ ~ ß ~ 2 ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ m Exhibit 19 Northstar Miscible Gas Flood 90 mbd Plateau Rate , , I , Gas Production and Injection Profiles , & . . ! ~ _____.-I -ll-Produced Gas (mmscfd) ......'njected Gas (mmscfd) I ~ ~ o 0 ~ a¡ 700 600 ~ Liquid Production Profile I I I I -+-Black 0)1 (mstbod) -II- Produced Water (mstbwd) -4r- NGL (mstbd) '\ ¡ ~ o ~ 500 i u III E400 .5. .! 1;.300 CII II ~ 200 100 o ..-.- ~- . ~ ~ en - I. ~ ~ en t N o ~ ...-r N o W t N o ~ ::I . N ~ t N ~ o -' .. ~ L N o o en .. N o o .þ. 100 90 î 80 .5. 70 .s I;. 60 c o :g 50 ::I 'tI 40 ~ ~ 30 0" ::ï 20 10 o ~ -~,... N o ëD ~ o W N o ~ N ~ N o o Cumulative Gas Production and I I I I I I I .....Produced Gas 2.581 TCF ......'njected Gas 2.855 TCF N o o co N o o CD N o o -. N o o en N o o en N o o .þ. N o o (0) N o o N 3,000,000 G:' 2,500,000 u CII E .5. 2,000,000 CII II ~ 1,500,000 ¡ -5 1,000,000 E ::I U o ~- .J. N o ëD N o o co -' ....., N N N ~ ~ ~ o .... N : .1 N o ~ N o o -. Cumulative Liquid Production I I I I -+-BlackOlI161.6 mmstb _Produced Water 157.6 mmstb - -'-NGL16.5mmstb ~ t --------~._--------- ---- ------. - -- -- -r-- ~ --- ~ .. ~ o o (0) N o o CD .. N o o CD N o o en .. N o o 01 N o o (0) .. N o o en - N o o .þ. ~ o N N o ~ 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000 o ~ III .5. c .2 Ü ::I 'ë a.. III > ;:I '" '3 E ::I U N o ëD Gas Oil Ratio I' I , __ 1_ I AT AT L> ~~~ ~ ,---- N o o U1 N o ëD N o ~ N o ~ N o ~ N o ~ N o W ~ o ~ N ~ N o o N o o co N o o CD N o g N o o -. N o o -. N o o 01 N o o 01 N o o U'I N o o .þ. ~~ N N N N o 0 0 0 o 0 0 0 .... N (0) .þ. N o o C,o) ~ ß N o ~ 80,000 70,000 ¡- 60,000 : 50,000 .! 40,000 g 30,000 C) 20,000 10,000 o 0- N o ëD N o ~ ~ N o ~ N o ¡:ñ ..---- ----- --- -- - - -.. - - . - - -------- ------- -=- .- _. -<tÑ --o~ -- --J.T ~ ~~ -- -===---- - - N o W o N o W N o ~ N ~ N ~ o ~ o o co N o o co Water Cut N o o -. N o o CD N o o -. N o o en N o o en N o o N - :~_~____u_ ~ N N ~ g g § ~ N (0) N o ~ 100 90 80 70 60 50 - --- 40 30 20 10 o ~ ::I U ... j Northstar Simplified Process Flow Diagram ~ ~' 97°F -n 11.1. r· !! fii¡ ~a:) r-1 CDIII alAE, 1;1 ua: -M 'l_F ¡ . 100°F 80°F -'~1 ~ 4ÐI ICODIIR.., <==0<::> ~IIÐI 240.1_ 'I:ÐØLER..,- II. _ -n;-_____ <=-=> I. '. -'. <:::><::> ~ 1. " " c:::::.<:>;,,! ilia: ""'( '. ~ CIIIIIEI Iii! 11I11I 13 ~ :nll r ~ 80°F '<:::><::>,-;::: 1 !Ie!! r 2Id 1 Iii. .h., f GLYCOL INLET 1 I ST~ til STAlE I :_ ~ SCRUBBER _: I lit :I_ _ 15 710 psi L-.. _ ... ./ 30°F !I'" "- ~ T r .L \. . U= I In' \- SEPARATOR ) i¡ (~YCOL INlET. ;.: J 685PSIU U " ~;~-yL (,r T ;( I -, Exhibit 20 INCOMING 100 rrTTECfd GAS PIPELINE FUEL 75°F 3D°F - GAS _ 214Ð1 ~_ 6iõ1 ~~ (" ~ ~~~ (-"-+ is f8 wa: S2 U1 Iwa: ... !_ " ell III ~ E.- 1 CD III r- 51ft !leI r-AIh i ·!lel :ST_I:= jmøt:= W 12 ;¡II 12 :¡:Ii , __ 0 ,----,' '-. -.1 600 mmscfd - Tl I I I.=-.I 5 GAS INJECTORS ~ .-' PS1 SO°F 847 psi · 65 mbd Oil GAS WATER NGls DRAlNSlSLOPS GlYCOl . IMPORT GAS TEMPERATURE F PRESSURE psi¡¡ r;è. --, , , :,/~ L .::..J I 164°F ~ (; ( LP '\ III:! \. SEPARATOR I i... )11.;$1. L..- 55 psi fu 0 =+- I" I ' '--- ¿ OIL R Ii mbIJ r------. I WELL MER 3000 psi \ ) I UP TAlK I /~, ~ 3tl mbd r::;;---- ---------- 2950psl ~12 ~ ~\ WATER I-- 2:::::: >--<! SURGE TANK I !:J- I ~ ~ (IØ.&IIIBE) r =~-I~ri~ib?·-r I-U:J) . I~ I ...... · S I, 160°F I{ _"TOR )-( I 735 psI ~ I >. 160 OF TEST SEPARATOR 735 psi I ( TT I ' -:>...J 16 OIL PRODUCERS i...-- i J _ "-1' .. - 1'-1.. I ~,?;.~:1~J.~1- - . ')0," ;0> "'"'\r' .' -....r- GRIND AHD IIIECT FACILITY ~ \ ~ . ---.- f -~~---,r ~ D/sharge ID sea DISPOSAL WELL r ; ; 3- ~ !fjl b._, CLASS 1 ~ fA . ) ¡ N6R~þRAjNAGE S~~fI~l"., '" ,'--_"-" - "\..../. ...... ~ ~, ~==-~..~i.;¡,·.~.·.~~W~,~·,'.\.' 'DRr~~~ ¡. . "",.¡~{·;~1~: ..... ¡~'. . HD1 ~I~/~{;:,{;;·.- SERVI9ffJ PR.OvESS I: :::;."i<:":~'> "'",. .1i..J I ,,-Al' , '-', .... . ,'::,:, :::.:,. ! BUtLOtf'-,¡{::It) ¡ MODULE ""~-..__ ..!CZ'\.:.:':·.~0'-Y\ ",""''' (. . /":.; ,.., ~2;,·~.;:::>...:",,>...·,··· ---- ....- . I .......~:a. C l'~~. " ... .', .. ','.,~ rstORÀGIfPLA,' . TFöR:---~.~...;... i.:....·..,..:...¡.·,..·~,':.:,..·,..·,·.·.:.'..,i.·.;.,.,...........,...... '~'. ..,~ i . -, t \h ~..,'.¡.:.....:..¡.¡.;.'.:,.::',',',.,:'.;.'.,::.'.',':,'.;.'.:.:.:..,.,:.!.:.'....,...... L (40 CON 1'1 EX UNITS) '-'. '"'',''' '-. . ~·.···.I r.~~!l/l?HqÜ~------_. trU ¡" DISPOSAL ., WE.U- " i.; ~ h"_ I~I r~,.,~.~ .""" ...."'"'~ ... I I. ~ ~ :,,\ · .,.................. __.~ : l..---~:..:~-1 ,:.;.,.\ DRILLRU3& ,___ '_ _ ~ -~_.- '___ ~ I ~~ ~; _~ /.' .... . ',. .. SERVICE W~R~Ho.~~E I SHOI~l'--~ .......-. r>:::;:·.:. _ : ~ l ~ ~~J7 " ... .: BUILDINGS IU. TIUTY"MODULE ...._-~:~~;:~i:¡·.:·,;..'K,·"-...· -:- ~. \ ~ lr1"11 -AlP··,';::::.::':'··········:'····::··::·,} " 'r,;~¡;~~¡~i;~~i['.·..":'\ · -- --~-_: ';~~~;~~)~"~" l ÜY~~G..-QU_A~TER~ ]---- ~;.~~.~~;,~~ "'T _ l ~ : ~<.~". , / ~ I ._,. .,_, ' , ."".J I, f j)J., . ,} - -L · - . -,' / /7' : . ¡: 1 I ~ v / / ~ I I " I I' : / ~ _../ , 3! i! ~m . I I IHewp~pl ~-,--- ISEAWATER L . INTAKE r-'---- [ S_ÖlrrH, D~.INAGE SUMP ~.__...- Northstar Facilities Seal Island General Layout Exhibit 21 TREE: WELLHEAD: .- Exhibit 2¿ ) Slimhole Producer .\ IIGINAL KS. ELEV = SF. ELEV = CB. ELEV = SSSV @2000' ~ 4.5" GLM 3.813" ID @ 3000' 6.8PPG DIESEL FREEZE PROTECTION AT +1- 2200 13 3/8", 68#/ft, L-80, BTC @ ~ ~ 4.5", 12.6#/ft, 13-Cr, Vam Ace TUBING ID: 3.958 " CAPACITY: .0152 BSUFT 9-5/8" 47#/ft, L-80, STC-M @ ~ AI , 4.5" X NIPPLE, @ 3.813" ID (OTIS) 4.5" X NIPPLE, @' 3.813" ID (OTIS) 4.5" XN NIPPLE, @ 3.725" ID (OTIS) 4.5" WLEG, @ (OTIS) 3 k- Baker 53 PACKER ;, 3.875" ID @ B 4.5" LINER TOP @ 4.276" ID 7" 26#/ft, L-80, BTC-M @ JI .. PBTD @ TD@ j, ~ 4.5", 12.6#, 13-Cr Vam Ace DATE REV. BY COMMENTS Northstar WE. L: API NO: BP Exploration (Alaska) TREE: WELLHEAD: .' Exhibit2~ )BigBore Producer f/lA,\ }GINAL KB. ELEV = BF. ELEV = CB. ELEV = SSSV @2000' 13 3/8", 68#/ft, L-80, BTC @ ~ 4.5" GLM 10 @2200' 6.8PPG DIESEL FREEZE PROTECTION AT +1- 2200 .... 4.5", 12.6#/ft, 13-Cr, TUBING 10: " CAPACITY: BBLlFT 4.5" X NIPPLE, @ "10 (OTIS) 4.5" X NIPPLE, @ · "10 (OTIS) 4.5" XN NIPPLE, @ "10 (OTIS) 4.5" WLEG, @ "ID (OTIS)- ~ r ~~~ER !J 4.5" LINER TOP @ -:e 95/8", 47#/ft L-80, BTC-M @ ~ ... PBTO @ TD@ i .. 4.5", 12.6#, 13-Cr DATE REV. BY COMMENTS Northstar WELl : API NO: BP Exploration (Alaska) TREE: WELLHEAD: .', Exhib~_ 14 Big Bore Injector .- )GINAL KB. ELEV = BF. ELEV = CB. ELEV = SSSV @2000' 7" HRQ SVLN 5.963" 10 13 3/8", 68#/ft, L-80, BTC @ ~ .... 6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 ~ , 7", 29#/ft, L-80, TUBING 10: 6.184" CAPACITY: 0.037 BBUFT 7" RNIPPLE, @ J 5.963" 10 (OTIS) 7" R NIPPLE, @ , -, Baker SABL-3 PACKER, 5.963" 10 (OTIS) --::I 6.0"10@ 7" RN NIPPLE, @ '8 5.5" 10 (OTIS) 7" WLEG, @ r 7" LINER TOP (OTIS) - 6.188" 10 @ 95/8", 53.5#/ft ... L-80, BTC-M @ PBTO @ TD@ j '- 7", 26#, L-80 DATE REV. BY COMMENTS Northstar WFI I : API NO: BP Exploration (Alaska) TREE: WELLHEAD: .~~ Exhibit ) Slimhole Injector 103/4", 45.5#/ft, L-80, BTC @ 5.5", 17#/ft, L-80, TUBING 10: " CAPACITY: BBLlFT 5.5" X NIPPLE, @ "10 (OTIS) 5.5" X NIPPLE, @ , "10 (OTIS) 5.5" XN NIPPLE, @ "10 (OTIS) 5.5" WLEG, @ "10 (OTIS)- 7 5/8", 29. 7#/ft L-80, BTC-M @ PBTD @ TD@ DATE REV. BY ~ ~ r f' It.. J. ~ COMMENTS .)GINAL KB. ELEV = _'-. ELEV = CB. ELEV = SSSV @2000' ... 6.8PPG DIESEL FREEZE PROTECTION AT +1- 2200 ~ , PACKER ID@ 5.5" LINER TOP @ 5.5", 17#, L-80 Northstar WELL: API NO: BP Exploration (Alaska) TREE: WELLHEAD: E h' ,.-) Pre-Produced Big Bore x Iblt 2", Injector .~, )GINAL KB. ELEV = BF. ELEV ::: CB. ELEV = SSSV @2000' 7" HRQ SVLN 5.963" 10 13 3/8", 68#/ft, L-80, BTC @ ~ ~ 6.8PPG DIESEL FREEZE PROTECTION AT +1- 2200 7", 29#/ft, 13Cr, TUBING 10: 6.184" CAPACITY: 0.037 BBLlFT 7" R NIPPLE, @ 5.963" 10 (OTIS) 7" R NIPPLE, @ , 5.963" 10 (OTIS) 7" RN NIPPLE, @ 5.5" 10 (OTIS) - 7" WLEG, @ "10 (OTIS)- J t- ~~~ER B 7" LINER TOP @ 6.184" 10 95/8", 53.5#/ft L-80, BTC-M @ r ... PBTD @ TD@ j ~ 7", 29#, 13Cr DATE REV. BY COMMENTS Northstar WFI I : API NO: BP Exploration (Alaska) .\ ) .' ) Exhibit 27 Northstar Injection Fluid Compositions Northstar PBU Injection Gas* Makeup Gas mole% mole% CO2 8.29 11.65 N2 0.77 0.60 C1 75.94 80.32 C2 8.00 5.32 C3 4.56 1.75 I-C4 0.59 0.13 N-C4 1.15 0.19 I-C5 0.22 0.02 N-C5 0.27 0.02 C6 0.15 0.00 C7-10 0.05 0.00 H2S (ppm) -10 30 *Injection gas is a blend of reservoir gas and make up gas .) fÞ') Exh i bit 28 Affidavit Of Krissell Crandall Regarding Notice To Surface Owners In The Vicinity Of The Proposed Injection Wells KRISS ELL CRANDALL, on oath, deposes and says: 1. I am employed as a Senior Landman by BP Exploration (Alaska) Inc. BP Exploration (Alaska) Inc. is the Operator of the Northstar Unit, and the applicant for the Northstar Area Injection Order. 2. On Jun~ 2001, I caused copies of the confidential version of the application for the Northstar Pool Rules and Area Injection Order to be hand-delivered to the following persons who represent surface owners and operators within one-quarter mile of the area affected by the proposed Northstar Area Injection Order: Pat Pourchot, Commissioner Department of Natural Resources State of Alaska 550 W. ¡th Avenue, Suite 800 Anchorage, AK 99501 Mark Meyers, Director Division of Oil & Gas Department of Natural Resources State of Alaska 550 W. ¡th Avenue, Suite 800 Anchorage, AK 99501 Jeff Walker Regional Supervisor, Field Operations Minerals Management Service 949 East 36th Avenue, Room 308 Anchorage, AK 99508-4363 3. On Jun~ 2001, I caused a copy of the confidential version of the application for the Northstar Pool Rules and Area Injection Order to be mailed first class to: E. P. Zseleczky, Land Manager BP Exploration (Alaska) Inc. 900 E. Benson Blvd. Anchorage, AK 99508 Buford Bates Murphy Exploration (Alaska) Inc. 550 WestLake Park Blvd., Suite 1000 Houston, TX 77079 Affidavit of K. Crandall Page 1 "') r, ) 4. On June~ 2001, I caused a copy of the public version of the application for the Northstar Pool Rules and Area Injection Order to be mailed first class to: John Jay Darrah, Jr. Jim Ruud, Land Manager Managing Partner Phillips Alaska, Inc. AVCG LLC P.O. Box 100360 225 N. Market, Suite 300 Anchorage, AK 99510-0360 Wichita, KS 67202 5. The attached map shows the record ownership of leases in and adjacent to the Northstar Unit. A VCG LLC has purchased Phillips Alaska, Inc.'s interest in ADLs 377051,385198 and 385202, and ExxonMobil's interest in ADL 377051. Assignments have been submitted to the State of Alaska, Department of Natural Resources, Division of Oil & Gas for approval. ~~ Krissell Crandall STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ~~\\\\\"UIIHIIIØ~ ~~~'td;~~~~ ~ v_.···çp..··_~~('\ ~ i§ ... ~ ~·.~·o~ ifJ!§ ..~. .. ~ :::::: ; ~ 7:0"" \ Z ~ = . ~~~ .(~Y· - ~-tt \. PllB.,. T.C) ~ ~cP...... ~ ~.(~ .. :;::: ~~·.·ó c:... ~.J§ ø -I' ~.. . 06 200".· T~ ~ ' ~ .....~.....~~" ~ ~ OF Al~~~' 1tq11111ll11\\\\"'~ SUBSCRIBED AND SWORN to before me this Notary Public in and for Alaska My Commission Expires: ;;Z /t. ¡O.5" Affidavit of K. Crandall Page 2 =lEA - LEASE STATUS EFFECTIVE MARCH 31 , 2001 Exhibit 28 IPH't 1i1 51 RÞM -GAS . t.UI"H'f . 8IJJ1 : A1'OfIIM : 3I.'U3 lJ li'/f ù. ~O/?? *4 SUFACETO 7,42It IIPX 91.19 AIIOC08Bt 7'" NIO IIEUJW I IIPX 45.ØO HEllBALY 45JIO .mœ a.oo M*]C04..40 o I o 1 :250.000 25,000 I 50.000 Feet I , ;'V0989-1 td.t\,;iz"'P'IRBA,, '11' ,,~,' ~,. ,',:''I088N,' =0Nt'F;~~~, 1t.æ87 ~ 'ID37D-2 BPX 10Cl.DD "'\... IUI-04 "- 'iIt~ Sl?/f I 12.000 Meters ALBERS EQUAL AREAJNAD27 I 6,000 IUI-04 ~œ . 1 BPX 100.00 DPX 1??.oo ~;: pttiJ'S 1??.oo ~ ~ 100JI0 ...Y1668', .: CHEVAÖNIIIJID ,c ADI.3B8609 .,"'~ ,~.;.=.: +:r"c~~~ ::~~c~7'C~} . J 1 HIO," ;WS71' BPX 11111DD BPX 100J10 - "- - - - - - ~~=~mii·~~ -:I~~ '<". BPIf 100.00 BPX 1OOJIO BPX ID1U1O .'~ 5O.ØO ~INtœ '. , 12-31004 c",,"-.Yt878:c~·- Yt880'< .:::... ~ .........~~ =v~ff.;: ""00l» ~ ÐP( 100.00 BPX 1D1U1O 1:Nn-04 IMI-04 BPX 100.00 IMt-04 1~-ð4 12,'f144 ,,:)l7cS1.oL ~ ..~.~75 ·.-:èVt6117 INHM AD.~' ~~'WIA478 ADLaBIM80 BPX 100.00 ~ 1111 if 1=,...= ..= "'f~~ PHI ....uos '0 OI-3I1D ", --·.01-31-03 ~~ ADt385199 ÐPX 1011.OO 1a3HM AI1I~ ,:=0 -- ÐPX ,??.oo II')[ 1??.oo 11&31.(8 AOl vIm 388 .' :. ,; Ø731-ðl ~535' 1M144.:·,· CI14·H'~:. ADL.377054 .~" ADl388538 c··'·· . AIU11Œi1.. PHUK U ". ... ", ',' .:-ï1 ~..IJa-OO ~- TDfWA' ADßáã4&7 . ~ oJ:' . ";;, ",171'.1 571. ~\.:: INI44'.\ . ~.~:~ ~ . ....~ ~"'-nD:l 'II8MI: . ..' ,.... ÐIDÐB" ...-- C". II'X_ _ - ~ oJ:' ~ cJ:' 11).31-Ø! c Y161t . 1NA~ I.8!lfrJ ,~~= 1,000 . 2,000 . 3,000 . 4,000 . 5,000· ' - 6,000 . -= - reservoir .c - 7,000 . c. pressure G) Q gradient 8,000 . Exhibit 29 9,000 - 10,000 - 11,000 - 12,000 - 13,000 ° 1,000 ° Northstar Pressure Gradients Pressure (psi) 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 I Reservoir Pressure from Mud Weight · Seal-A-01 · Seal-A-02 OH · Seal-A-02 RD · Seal-A-03 9S Seal-A-04 · North Star 1 . c_ ~ . . . . H Ittând ·'kup~ruk:1:1"ñ:-- MilLJveaëhFm~ ' -. Equivalent Mud Weight (ppg) Sep. Liq Sep Gas Recombined Mole% Mole% Mole% H2S 0.00 0.00 0.00 CO2 0.54 6.97 5.38 N2 0.03 0.67 0.51 C1 2.31 74.23 56.46 C2 1.69 8.91 7.12 C3 3.65 5.35 4.93 I-C4 1.33 0.85 0.97 N-C4 4.08 1.70 2.29 I-C5 2.37 0.41 0.89 N-C5 3.31 0.44 1.15 C6 7.05 0.26 1.94 C7 7.38 0.14 1.93 C8 10.57 0.05 2.65 C9 7.17 0.01 1.78 C10 5.71 0.01 1.42 C10+ 42.81 0.00 10.58 Northstar Oil and Gas Composition Seal A-01 Test #2 Recombined (RFL 840067) Exhibit 30 ~) f') #3 ') t1 " \ I ¡ ..i ,/" i ~ \ It t. ! .... , ' \" '- ~ Jf\4 (':C~en1~ f\ Of ~on Or:: J\ 9 ~ \'\ S'd.\\o r\ ì r ..;ù (\ r, JuJ1 " ~DOr(l J. ó I 73 I ¡ ') (' f #2 AO.FRM Publisher/Original Copies: Department Fiscal, Department, Receiving 02-902 (Rev. 3/94) Drz=ï~¡~ ~ II, RE~~{J~ 2 3 73540 02140100 01 DIST LIO NMR FY ACCT LC PGM CC Sy AMOUNT FIN PAGE 1 OF TOTAL OF 2 PAGES ALL PAGES$ COMMENTS $,~~,Q.INVOI.ÇE.:!NjT~I.~~l.C~'r~'j, AOGCC, 333 W. 7th Ave., Suite 100 ~,ç"i~~1?::JØ~~H·~7.),~; ,,.:~ :';Tò::~::;;';,!;'~i;":;~,;:jif~/;;', Anchora,æ;e, AK 99501 "REF TYPE NUMBER AMOUNT DATE 1 VEN 2 ARD 02910 3 4 SEE ATTACHED PUBLIC HEARING NOTICE D Other (Specify) D Classified D Display Type of Advertisement :g Legal THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: (907) 793 -1 ?? 1 DATES ADVERTISEMENT REQUIRED: July 5,2001 ~ ,Anchorage Daily News POBox 149001 Anchorage, AK. 99514 July 2~ 2001 PCN Jody Colombie . PHONE F AOGCC R .333 W 7th Ave, Ste 100 o Anchorage, AK. 99501 M , DATE OF A.O. AGENCY CONTACT ':~~E,8F~~:,'F~~f.~~~~l~~~~e~~~';:,::·:", AO-02214001 . ) NOTICE TO PUBLISHER. ) INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., L.ERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE STATE OF ALASKA ADVERTISING ORDER ADVERTISING ORDER NO. c) .) Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Northstar Oil Pool, Northstar Field - Pool Rules and Area Injection Order BP Exploration (Alaska), Inc. by letter dated June 26, 2001, has applied for pool rules and an area injection order under 20 AAC 25.460 and 20 AAC 25.520, respectively, to govern the development of the Northstar Oil Pool from Seal Island, approximately 6 miles north of the Prudhoe Bay Unit, offshore in the Beaufort Sea of Alaska. The commission has set a public hearing on August 16, 2001 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska. In addition, a person may submit written comments regarding· the pool rules or area injection order prior to August 16, ·2001 to the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage AK 99501. For infonnation, interpreter services or other accommodations, call (907) 793- 1221 before August 9, 2001. ~~~ Cammy Oechsli Taylor Chair Published July 5, 2001 ADN AO# 02214001 STATE OF ALASKA ADVERTISING ORDER SEE ,80TTO~ FOR1~V{)J~E. ~~RESS:'. .) NOTICE TO PUBLISHER .. ) INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., v.::RTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-02214001 F AGENCY CONTACT DATE OF A.O; AOGCC 333 West 7th Avenue, Suite 100 o J\nchorage,AJ< 99501 M R T o J\nchorage Daily News POBox 149001 J\nchorage,AJ< 99514 Jon)' Colombie July?,?OOl PHONE pct\! _ (907) 793 -1 ?? 1 DATES ADVERTISEMENT REQUIRED: July 5, 2001 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING QRDER 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 2001, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2001, 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 2001, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER . ) ~ ) Anchorage Dally News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 TOTAL 944182 07/05/2001 STOF0330 $73.15 $0.00 $0.00 $73.15 $0.00 $0.00 $0.00 $73.15 $0.00 $0.00 $73.15 STATE OF ALASKA THIRD JUDICIAL Lorene SoHvan, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspa:per in Anchorage, Alaska, and it is now and durmg all saia time was printed in an office maintained at the aforesaid :place of publication of said newspaper. That the annexeâ is a copy of an advertisement as it was pu5lished in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of saId period. That the full amount of the fee charged for the fore~oing publication is not in excess of the rate charged private indI~idual . I' r / Signed _ __ __ J Subscribed and sworn to me before this date: - - - -- - -- --.- - -11 f-L- - - -- -- -- -- -- Notary Public in ana for the State of Alaska. Third Division. Anchorage, Alaska ^' 1~~4~-- \\\U"((II,,, \\'..\.\£ s. 0-1';1'. \.\: r· ., · · · · .,.~" ~ \.: !:J .. ... .. ~ ~ ~~:~O'AR~·. -;. ~ . ~ .-. .... § : PU8\-\CI : æ § -=- i'· ~ ..- §: ~~ ~~""~C1f~.s::.~~ ~ . . . . .. ')':,,' ;.I..I~ ~ ", 1IJlJiiì)t'" --_.~._- ~-_.....~., . ,,';"," ","'.,:' ::1 NotlC~OfPubhcHeådng ·1 ~TA rE'óFÂkÄSKÄ""" AI(skaOH and Gas c;oh-' i..~::~r~~:~:;;:V~::i',sÞ1J~¡:?1' 'N ,0:F't'h·5't;Ca"i:''''~,F' 'ie:I"cf..~:O'ol.. ~t~~~~~~1¡ .,'.'~~,',l, ~,:'d.s., :.rJ".'J,:~.,~'~, ~i;.:'I2.bO,V.p.·.',{~,':~h,t, :~,··,~,"':'.',:I oppll~d"for"poønrÚt,if Cll1d" ,0 n.areàJnl~'ctl:orf·ì':O~de!r!! Und,er:JlO.::AAC'25'46(hqnd.,20 . ,'AÄC:2$,S~o)lr~~p;~ç,tfiièJ'ÿ;,1 'togovt!rÍ1.'th'e~'.j:tèv,e)ô:p';: I r:nén(ot,t'heNørthsta~,X>I ¡ Pool'lrom'Siflál l.s:.I:a'ri'd, a'p" proj(l.m"qt~,I.;Y :,6"Q;I,J~e-s, northòf-th'ff'~,rùd tioèXBoiy.' Unit,,· .offs ho r,el ¡',the;, Beaufort Sea/of Alaska. í .' .'. the"CQ'~'ri:ii!iSIOnhas' set,a,pu,)tlC'r,h'eadng. on I Aiji;~sf16;\~QtH:âf'9:0Q'aÌT1 : . at,the,~[ask(J':,ö'nbnd'Gasl C,o n $e r vat/onC OI11I11J$·;¡ i~iO ~·..åt·.;33:,West'Úh:·AIi:·: ¡el'!\le. "Su.ifeJ()P'~I1CI'l9r~'· :,,:Clg.e.:~AlaskO~:ln,;g~ditlpn,·· , a "pe ",s:o:(I: m.QY:"$ub.rillt '\N.tl tten."c,orn:mEt\n t ;",:I'é- . f.Slqr:~1 ng,:th:e,tþoo 1:'"",1,.1 lespr·, :¡Qr",a Inlectlol1order,PFior :td'AUg~st:¡I ~,;2001;j() "t~e I ;'A.IO>k'Qi;P:lt~9~C. ,C:;O.SI',(;Qri· :;s,erYQt~,p'!:,S!)",;I1J!'!>S,I¡Þf!:oti', ' ::J,~3"Wes,t:'7~fJ,A've,n u e. 131. ...,~, ! ·preter'servl.cesorother" : a ç ço'r;nrr¡ o'do't, Ion S. co" I (9;O.~J.'79.3~122.1.before .Au~ . . gus,t~~,'~,~ f'\:',; ..:.... '. ': CCJrnmvÖøcl1sl'iTavlor . I Chair ·,'.i,,··' 'I i I r ' , ." ',".' ~ ': p~br;JJ;IY5;'200i ' ~) ~) .. I Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Northstar Oil Pool, Northstar Field - Pool Rules and Area Injection Order BP Exploration (Alaska), Inc. by letter dated June 26, 2001, has applied for pool rules and an area injection order under 20 AAC 25.460 and 20 AAC 25.520, respectively, to govern the development of the Northstar Oil Pool from Seal Island, approximately 6 miles north of the Prudhoe Bay Unit, offshore in the Beaufort Sea of Alaska. The commission has set a public hearing on August 16, 2001 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska. In addition, a person may submit written comments regarding the pool rules or area injection order prior to August 16, 2001 to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage AK 99501. For infonnation, interpreter services or other accommodations, call (907) 793- 1221 before August 9,2001. ~~¥ Cammy Oechsli Taylor Chair Published July 5, 2001 ADN AO# 02214001 , certify that on 7. / ZfJ / 8 copy of the above was faxedlmailed to 8ICh of the following at their addrtl''II of /7 ./ . record: !1J,C¡CjtJr5 0 ~ C t' ~ £V / /'C;? ¿¿/ /P/l/l//x/ ))c:PI·8a/ro~ · 7 . Je.- .) .) Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Northstar Oil Pool, Northstar Field - Pool Rules and Area Injection Order BP Exploration (Alaska), Inc. by letter dated June 26, 2001, has applied for pool rules and an area injection order under 20 AAC 25.460 and 20 AAC 25.520, respectively, to govern the . development of the Northstar Oil Pool from Seal Island, approximately 6 miles north of the Prudhoe Bay Unit, offshore in the Beaufort Sea of Alaska. The commission has set a public hearing on August 16, 2001 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska. In addition, a person may submit written comments regarding the pool rules or area injection order prior to August 16, 2001 to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage AK 99501. For infonnation, interpreter services or other accommodations, call (907) 793- 1221 before August 9, 2001. ~~¥ Cammy Oechsli Taylor Chair Published July 5, 2001 ADN AO# 02214001 I certify that on 7~~ ó 1 a copy of the above was faxedlm-HArOto 88Ch of the following at their. addresses of record: pe7¿ ç /0/7 ¿:'¿ ,~. OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LlBRARYIINFO CTR POBOX 87703 CHICAGO,IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 «) PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT A V NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN,IL 61820 MURPHY E&P CO, ROBERT F SAWYER POBOX 61780 NEW ORLEANS, LA 70161 IOGCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 ~) NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GA THERSBURG, MD 20898 SD DEPT OF ENV & NA TRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPI RAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 ENERGY GRAPHICS, MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON, TX 77002 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 PHILLIPS PETR CO, PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 . , PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 TEXACO INC, R Ewing Clemons POBOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC POBOX 338 AUSTIN, TX 78767 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 ~) RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 WATTY STRICKLAND 2803 SANCTUARY CV KA TY, TX 77450-8510 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE,VVA 98101 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151ST #4 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE. LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 . ) C & R INDUSTRIES, INC." KURT SAL TSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 .) JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN VACTOR PO BOX 683 PORTLAND, OR 97207 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 PRESTON GATES ELLIS llP, LIBRARY 420 l ST STE 400 ANCHORAGE, AK 99501-1937 DEPT OF NATURAL RESOURCES, DIV OF Oil & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES, DIV Oil & GAS WilLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 AK JOURNAL OF COMMERCE, Oil & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR SERVICES, JIM MUNTER 2000 W. INT'l AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 N-I TUBULARS INC. 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADRlll-SCHlUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 lEEPER CIRCLE ANCHORAGE, AK 99504-4209 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 . ) DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE. AK 99501-1994 DEPT OF REVENUE, Oil & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE. AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF Oil & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF Oil & GAS JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE. AK 99501-3560 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT lOOP RD ANCHORAGE. AK 99507 US BlM AK DIST OFC, RESOURCE EVAl GRP ART BONET 6881 ABBOTT lOOP RD ANCHORAGE, AK 99507-2899 .) YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 GAFO,GREENPEACE PAMELA MillER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF Oil & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DNR, DIV OF Oil & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPTOF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BAKER Oil TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE. AK 99503 ALASKA Oil & GAS ASSOC, JUDY BRADY 121 W FIREWEED IN STE 207 ANCHORAGE. AK 99503-2035 ARLEN EHM GEOl CONSl TNT 2420 FOXHAll DR ANCHORAGE, AK 99504-3342 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT lOOP ROAD ANCHORAGE, AK 99507 UOAl ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HUll 3211 PROVIDENCE DR ANCHORAGE, AK 99508 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 GORDONJ.SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, STEVE BENZLER A TO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 AL YESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 DAVIDW. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 . ) ~) VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, JOANN GRUBER A TO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 . ) GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 196168 ANCHORAGE, AK 99519-6168 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA) INC, PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHA VELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 ~) DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 ENSTAR NATURAL GAS CO, BARRETT HATCHES POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 RON DOLCH OK PO BOX 83 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 NANCY LORD PO BOX 558 HOMER, AK 99623 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 VALDEZ PIONEER, POBOX 367 VALDEZ,AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG PO BOX416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 . ) PENNY VADLA POBOX 467 NINILCHIK, AK 99639 PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ,AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 ~) BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR PO BOX 98 VALDEZ, AK· 99686-0098 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 #1 bp t) r) ...., ,\lI.tl" -.....~ ~.~ ~..- ~...~ *..~ ~..... ·'1'·'1\- ". Pete Flones' Northstar Project Manager Alaska New Developments BP Exploration (Alaska) Inc. 900 E. Benson Blvd. Anchorage, AK 99508 P.O. Box 196612 Anchorage, AK 99519-6612 Switchboard: (907) 561-5111 Via Hand Delivery June 25, 2001 RECEIVED JUN 26 2001 Ms. Cammy Oechsli Taylor, Chair Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Alaska Oil & Gas Cons. Commission Anchorage Reference: Northstar - Application forArea Injection Order and Pool Rules Dear Ms. Taylor: BP Exploration (Alaska) Inc. is applying for an Area Injection Order and Pool Rules for acreage within the Northstar Unit. Enclosed please find six copies each of the confidential and public information versions of our application. The confidential version of our application contains proprietary geologic, geophysical and commercial information entitled to confidentiality under 20 AAC 25.537(b), 20 AAC 25.540(c)(1 0) and AS 45.50.940. As stated in the enclosed application, BPXA will also request that the United States Department of the Interior, Minerals Management Service ("MMS") approve gas reinjection pursuant to 30 CFR 250.114 and enhanced oil recovery pursuant to 30 CFR 250.1107. Our request- to MMS will be supported by the enclosed application. It is our understanding that MMS and AOGCC will work together to address any concerns that each agency may have about the approvals issued by the other. We expect that AOGCC will hold a hearing in early to mid-August, and that the following persons will be available to testify to the information contained in the application and to answer any questions raised by the Commission: Pete Flones, Northstar Project Manager Bill Turnbull, Petroleum Engineer Terry Wilcox, Reservoir Engineer Ken Lemley, Geologist Tom Armstrong, Northstar Operations Floyd Hernandez, Drilling Engineer Please be advised that BPXA's target date for starting oil production is October 1, 2001, and that with favourable conditions we may be able to start as early as September 15, 2001 . t) ,.) June 25, 2001 Ms. Cammy Taylor Page 2 of 3 If you have questions concerning the application, please contact Bill Turnbull at 564-4662 or Krissell Crandall at 564-4535. U/ Sincerely. ,.-- , lJ). .~ e~~ Enc: Application (6 copies each of confidential and public information versions) cc: Jeff Walker, MMS (w/3 copies of each enclosure) Pat Pourchout, ON R (wI 1 copy of each enclosure) Mark Meyers, ONR (w/3 copies of each enclosure) Buford Bates, Murphy (wI 1 copy of each enclosure) Bob Gage, Murphy (wI 1 copy of each enclosure) Greg Mattson, BPXA (wI 1 copy of each enclosure) ~4' .~, c) ~) PUBLIC INFORMATION Northstar Unit, Beaufort Sea, Alaska Application To AOGCC For Approval Of Pool Rules And Area Injection Order R fCflVfD JUAj 26 2001 ~OiJ&'~ ::1R$ Cans " 4nchorage LOlllmiBsion BP Exploration (Alaska) Inc. June 25, 2001 8. Proposed Pool Rules............................................................................. ................39 7. Proposed Area I njection Order Rules..................................................................... 37 6. Area I njection Order Application.............................. .............................. .................33 5. Well Operations...................................................... ........................................ ....... 27 4. F acil iti es . . . .. .. .. .... ... . . .. . . .. . . . . . . .. . . . . .. . ......., .. . .. . . .... . ........... . .. .. .. .... . ... .. ... ... ........ .... .. ......23 3. Reservoir Description and Development Planning ...................................................8 2. Geology ................................................................................................................... 4 1. Project Overview................................ ............................................. ...................... ...2 Table of Contents Northstar Unit, Beaufort Sea, Alaska Application To AOGCC For Approval Of Pool Rules And Area Injection Order e) PUBLIC INFORMATION e) . -): .. ) .) .) PUBLIC INFORMATION List of Exhibits Exhibit 1. Northstar Pool Location Map (confidential) Exhibit 2. Northstar Injection Area Map Exhibit 3. Northstar I njection Area Description Exhibit 4. Northstar Type Log - Seal A-01 Exhibit 5. Northstar Isopach Map (confidential) Exhibit 6. Northstar Reservoir Structure and Development Well Location Map (confidential) Exhibit 7. Northstar Cross Sections (confidential) Exhibit 8. Type Log - Northstar 1 (confidential) Exhibit 9. Type Log - Seal A-01 (confidential) Exhibit 10. Type Log - Seal A-02A (confidential) Exhibit 11. Type Log - Seal A-03 (confidential) Exhibit 12. Type Log - Seal A-04 (confidential) Exhibit 13. Chemical composition of Seal A-01 Formation Water Sample Exhibit 14. Northstar Miscible Gas Flood 65 mbd Plateau Rate (confidential) Exhibit 15. Northstar Waterflood (confidential) Exhibit 16. Northstar Gas Cycling (confidential) Exhibit 17. Northstar Primary Depletion (confidential) Exhibit 18. Northstar Miscible Gas Flood 72 mbd Plateau Rate (confidential) Exhibit 19. Northstar Miscible Gas Flood 90 mbd Plateau Rate (confidential) Exhibit 20. Northstar Simplified Process Flow Diagram Exhibit 21. Northstar Facilities Seal Island General Layout Exhibit 22. Slimhole Producer Wellbore Diagram Exhibit 23. Bigbore Producer Wellbore Diagram Exhibit 24. 7" Injector Wellbore Diagram Exhibit 25. 5-1/2" Injector Wellbore Diagram Exhibit 26. Pre-produced Injector Wellbore Diagram Exhibit 27. Northstar Injection Fluid Compositions (confidential) Exhibit 28. Affadavit of Notice to Surface Owners Exhibit 29. Northstar Pressure Gradients (confidential) Exhibit 30. Northstar Oil and Gas Composition (confidential) ). .) C) PUBLIC INFORMATION Northstar Unit, Beaufort Sea, Alaska Application To AOGCC For Approval Of Pool Rules And Area Injection Order BP Exploration (Alaska) Inc. ("BPXA"), in its capacity as Northstar Unit Operator, requests that the Alaska Oil and Gas Conservation Commission (the "Commission") adopt the Area Injection Order ("AIO") set out in Section 7 of this application and the Northstar Pool Rules set out in Section 8. For purposes of this application, the Northstar Pool is defined as the accumulation of hydrocarbons in the Ivishak, Shublik and Sag river formations common to and correlating with the interval between the measured depths of 12,418 feet ànd 13,044 feet in the Seal A-01 well. The boundary of the Northstar Pool is illustrated in the map attached as Exhibit 1. The boundary of the lands subject to the Northstar Area Injection Order (the "Northstar Injection Area") and the Northstar Pool Rules is shown in the map attached as Exhibit 2, and is described in Exhibit 3. Shortly after submitting this application, BPXA will request that the United States Department of the Interior, Minerals Management Service ("MMS") approve gas reinjection pursuant to 30 CFR 250.114 and enhanced oil recovery pursuant to 30 CFR 250.1107. BPXA will coordinate, its submissions to AOGCC and MMS such that both agencies receive the same information and are cross-copied on any request or application to the other agency. Where there are differences between the requirements imposed by AOGCC and MMS, BPXA will comply with the more stringent regulation or statute or, if necessary, request a waiver of mutually inconsistent regulations. BPXA is not aware at this time of any instance where complying with the regulatory requirements of one agency would violate the requirements imposed by the other. Page 1 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ,I ~ ~) PUBLIC INFORMATION 1. Project Overview The Northstar Pool is a discovery in the Ivishak formation, and is located approximately 6 miles offshore in the Beaufort Sea, north of the Prudhoe Bay Unit, as illustrated in Exhibit 1. The Northstar Pool crosses from State waters into Federal waters, and lies beyond the barrier islands. The Northstar Pool was discovered in 1983 by Shell during the drilling of the Seal A-01 well and was well appraised by Shell and Amerada Hess who drilled a total of 5 wells to the target horizon. Shell and Amerada Hess carried out extensive coring and well testing, and obtained a dense grid· of two-dimensional seismic data. The exploration and appraisal wells were drilled from two gravel islands in approximately 40 feet of water. Amerada's Northstar Island was located over the northwest portion of the Northstar Pool, and Shell's Seal Island was located over the main southeast part of the Northstar Pool. Both islands were abandoned and were washed away by winter storms. In 1996, BPXA shot and processed an Ocean Bottom Cable ("OBC") 3-D seismic survey over the field. The Northstar Pool contains a volatile, sweet crude. Oil gravities, as measured from several collected fluid samples, range from 43-45° API. Initial gas oil ratios ("GaR") were approximately 2200 scf/stb (standard cubic feet per stock tank barrel) and the viscosity was measured to be about 0.14 cp (centipoise). The Northstar project is a stand-alone island based development on Seal Island, providing full process and export facilities for 65,000 barrels per day (bpd) oil, 600 million standard cubic feet per day (scfd) of gas injection, and 30,000 bpd of produced water handling capacity. The pipeline system consists of a 10-inch crude export line that ties in to the Trans-Alaska Pipeline System ("TAPS") at Pump Station 1, and a 10-inch gas line for providing the import of make-up gas and fuel gas from Prudhoe Bay Unit for enhanced oil recovery ("EaR") at the Northstar project. Construction of the island and installation of the pipelines were completed early in 2000. The island includes slots for 37 wells, and the initial phase of development at the Northstar project calls for 16 production wells, 5 gas injection wells, and one Class I waste disposal well. Drilling began in December 2000. To date, BPXA has drilled the disposal well, one gas injection well, and two pre-produced gas injection wells. Development drilling will resume following the facility startup in November 2001 and will continue into 2003. Page 2 Northstar Pool Rules and Area Injection Order Application 6/25/2001 C) . -) PUBLIC INFORMATION The Northstar Pool will be developed as a tertiary recovery project using the EOR technique of miscible fluid displacement to increase recoverable oil reserves. The EOR project involves the initial injection of a large slug of miscible enriched natural gas into the oil column of the Ivishak formation. This period of miscible gas injection will last approximately four years, and will be followed by the injection of leaner chase gas through to the end of field life. The miscible gas will be a blended mixture of reservoir gas (produced with the oil), and the gas imported from Prudhoe Bay Unit ("make-up" gas). During the miscible fluid injection phase, the gas processing plant on the island will be operated such that the associated reservoir gas is maintained as rich as possible. This will ensure that the injected gas stream is miscible with the reservoir fluids. The volume of make-up gas will be controlled such that the reservoir pressure will be maintained near to its initial value at field startup, and above the miscibility pressure determined from slim-tube experiments. Page 3 Northstar Pool Rules and Area Injection Order Application 6/25/2001 · .) PUBLIC INFORMATION 2. Geology STRATIGRAPHY The Northstar Pool is contained within the Sag River, Shublik and Ivishak formations and was deposited during the Permian and Triassic geologic time periods. Exhibit 4 illustrates the stratigraphy of the Northstar Pool on the Seal A-01 type log. This log is scaled in true vertical depth from the rotary kelly bushing ("TVDrkb"). The top of the Northstar Pool occurs at a depth of _ feet TVDrkb. The base of the Northstar reserVoir occurs at a depth of _feet TVDrkb. The oil water contact exists at _ feet true vertical depth sub-sea (''TVDss''). Sag River The Sag River formation lies immediately below the Kingak formation of Jurassic age and above the Shublik formation of Triassic age. The Sag River formation consists of a series of transgressive marine sands, silts, and shales and is approximately. feet thick in the vicinity of the Northstar pool area. Shublik The Shublik formation lies immediately below the Sag River formation of Triassic age and unconformably overlies the Ivishak Formation of Permian and Triassic age. The Shublik formation consists of marine silts, shales, sands and phosphatic limestones and is approximately II feet thick in the vicinity of the Northstar pool area. The Shublik formation is subdivided into four lithologic units. The upper unit called the Shublik A consists of marine silts and shales and is approximately II feet thick. The Shublik B lies below the Shublik A and consists of phosphatic limestones and is approximately II feet thick. The Shublik C lies below the Shublik B and consists of limestones grading downward into interbedded shales and siltstones and is approximately II feet thick. The Shublik 0 lies below the Shublik C and unconformably overlies the Ivishak formation. The Shublik 0 is approximately II feet thick. Ivishak The Ivishak formation lies unconformably below the Shublik 0 unit of Triassic age and conformably above the Kavik formation of Permian age. The Ivishak is approximately. feet thick in the vicinity of the Northstar pool area. The Ivishak consists of delta front sands and shales grading upward to fluvial sands and finally into medium to coarse grained pebbly conglomerates. Page 4 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ~) r) PUBLIC INFORMATION LITHOLOGY Sag River The sands within the Sag River represent a mineralogically mature sandstone composed of quartz with minor amounts of feldspar and authigenic clays. Calcite, silica and siderite are the primary cementing agents. Shublik The Shublik formation consists of marine silts and shales in the Shublik A unit grading downward into phosphatic limestones in the Shublik B and then into interbedded silts and shales in the Shublik C and finally into fine and very fine grained sands in the Shublik 0 unit. Calcite, silica, siderite and. pyrite are the primary cementing agents within the Shublik formation. Ivishak The Ivishak reservoir consists of an upper conglomeratic unit and a lower sand unit. The upper conglomeratic unit is characterized by a bimodal grain size distribution consisting of mostly chert and quartz clasts with minor amounts of silt and quartz grains comprising the matrix material. The conglomeratic unit has varying amounts of microporous chert grains as part of the framework. Calcite, silica and siderite are the primary cementing agents. The lower sand unit consists of medium to coarse-grained sand with minor amounts of silt and shale. This lower unit is approximately. feet thick and is present below the oil/water contact throughout most of the field area. Calcite, silica and siderite are also the primary cementing agents present within the lower sand unit. The Ivishak reservoir at Northstar is more proximal, coarser grained, more deeply buried and cemented than the Ivishak reservoir in Prudhoe Bay, leading to lower average porosities and permeabilities. STRUCTURE The structure of the Northstar Pool consists of a faulted anticline defined by three-way dip closure on the east, west and south, with fault seal and dip closure to the north. Exhibit 6 is a structure map at the top of the Ivishak and illustrates the trapping configuration. Exhibit 7 Page 5 Northstar Pool Rules and Area Injection Order Application 6/25/2001 .) .) PUBLIC INFORMATION shows two structural cross-sections. Cross-section A-A feet is a strike oriented .cross-section running from the SW to the NE across the Northstar Pool. Cross-section B-B feet is a dip oriented cross-section running from the NW to the SE. These two cross-sections also serve to illustrate the trapping configuration at the Northstar Pool. FAULTING testing and reservoir surveillance program, including pressure measurement from RFT or MDT, injection gas tracer analysis and geochemical analysis, will be implemented to address this issue more completely during development. CONFINING INTERVALS The Northstar Pool is confined below by the Kavik formation and above by the Kingak formation. The Kavik formation is continuous throughout the area. It is interpreted to be a marine shale sequence of Permian age. The Kavik rests unconformably on the carboniferous aged Lisburne group. The Kavik formation is extremely impermeable with a thickness of approximately 100 feet in this area and serves as the lower confining zone. The Kingak formation is continuous throughout the area and conformably overlies the Sag River formation. The Kingak formation was deposited as marine shales and silts during the Jurassic period and is extremely impermeable. The Kingak formation is approximately 1,000 feet thick in the area and serves as the upper confining zone. Page 6 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ,.. (J () PUBLIC INFORMATION FLUID CONTACTS Page 7 Northstar Pool Rules and Area Injection Order Application 6/25/2001 &) .) PUBLIC INFORMATION 3. Reservoir Description and Development Planning ROCK AND FLUID PROPERTIES The reservoir description of the Northstar Pool is based on core and well log data from the Seal A-01, Seal A-02A, Seal A-03 and Northstar-1 wells. A total of 1196.3 ft. of Ivishak core was acquired from these four wells. The core data were used to calibrate the porosity portion of the petrophysical log model. The type logs for the reservoir intervals in Northstar-1, Seal A-01 , Seal A-02A, Seal A-03 and Seal A-04 are shown in Exhibits â through 12. POROSITY AND PERMEABILITY Sag River Formation Routine porosity and permeability measurements are available from two wells (Seal A-02A, and Northstar-1). No significant core was obtained in what would be described as the best reservoir section of the Sag River formation with the exception of the upper part of Core 1 in the Seal A-02A well. The core plug permeability values range from . The mean core porosity is . The average log derived porosity was generated from the density log using an average grain density of _. The log porosity results average . Permeability was estimated from a core para-perm relationship. The likely permeability range is estimated to be . No tests are available for comparison with the core data. Shublik Formation Core data across the Shublik formation exists on the Northstar-1 and Seal A-02A wells only. The Shublik formation is considered a source rock and not in general a reservoir rock. What core poro-perm data does exist suggest that most of the section is tight and non-reservoir with the exception of Zone D. Permeability is generally and porosity However, porosity and permeability measurements can get up to in a few instances in thin « 3 inches) discontinuous intervals. These thin intervals are not observed on well log data and usually add up to less than 2 feet cumulatively in vertical extent and do not appear to correlate between wells. Page 8 Northstar Pool Rules and Area Injection Order Application 6/25/2001 () () PUBLIC INFORMATION Ivishak Formation Extensive routine porosity and permeability measurements were available from four wells (Seal A-01, Seal A-02A, Seal A-03 and Northstar-1). Core was also obtained from Seal A-04 but was insignificant and outside the oil column. In addition, porosity and permeability data at in-situ confining pressures. were available from Seal A-02A and Northstar-1. A sensitivity study of the impact of in-situ confining stress on porosity and permeability indicate The mean stress corrected core porosity for the Ivishak Formation above the oil water contact is approximately _ Core permeability ranges from with a mean stress corrected value of approximately _. Permeability established from drill stem tests are higher than average permeability values from core. This may be a result of rubble sections existing in the reservoir that were not representatively sampled from the cores that were obtained. The two dominant . facies, conglomerates and sandstones, have different reservoir properties and subsequently different poro-perm trend relationships. The correlation of porosity to permeability is better for the sandstones than for the conglomerates. Two significant studies were undertaken on the Ivishak reservoir to define the percent of effective porosity and non-effective micro-porosity. Shell and Core Laboratories performed a study on these two porosity distributions. Within the Ivishak reservoir there are two dominant reservoir facies, which have been characterized as conglomerates and sandstones. The conglomerate facies as defined by Shell and Core Laboratories have an average porosity of _ and _, respectively, while the sandstones have an average porosity of _ and _, respectively. Additionally, Shell and Core Laboratories reported that within the conglomerate facies _ and _ respectively of the total porosity is micro-porosity. They determined that within the sandstone facies _ and _ respectively of the total porosity is micro-porosity. This study indicates that the volume fraction of micro-porosity increases as one moves down in the reservoir section. NET PAY Sag River Formation The reservoir gross thickness ranges from feet in the _ well to a Page 9 Northstar Pool Rules and Area Injection Order Application 6/25/2001 () () PUBLIC INFORMATION maximum of . feet in the _ well. Net pay was determined from gamma ray cutoffs and porosity cutoffs that were established from poro-perm relationships. Permeability above _ or porosity above _ was considered as pay. This estimate has not been verified by test. Currently, no test exists in the Sag River formation to demonstrate producibility. The net to gross for the interval was determined to range from _ based on the above cutoffs. There is considerable uncertainty in . this estimate as log coverage of the Gamma Ray and porosity is not generally complete across the Sag River section. Shublik Formation Core was obtained only on the Northstar-1 and Seal A-02A well across the Shublik formation. While mudlog shows exist, this section is in general non-reservoir. The permeability that does exist from core from the Northstar-1 and Seal A-02A wells is generally less than _. There are a few thin intervals of reservoir quality rock in the Shublik that have permeabilities as high as _ but are not considered significant with the possible exception of the Shublik D unit. The gross thickness of the Shublik D is about Ivishak Formation Non-pay intervals include rare silty/shaley intervals recognized on the gamma ray log (V-shale) and low porosity cemented conglomerates and sandstones. Thicker and more continuous shales are only present in the very lowest portions of the reservoir and are present largely in the aquifer. Net to gross estimates were made using a combined V-shale cut off porosity cutoff for sandstones and a II porosity cutoff for conglomerates. Porosity cutoffs were established from poro-perm relationships for the conglomerates and sandstones. STATIC MODEL CONSTRUCTION Sag River and Shublik Formations I sopach maps for the Sag River and Shublik were created using the existing well control. Porosity, water saturation and net to gross ratios were determined for the Sag River from well log and core data analysis. These data were then combined to determine the OOIP for the Sag River which was estimated to be . The following table summarizes the input parameters for determining the OOIP for the Sag River: Page 10 Northstar Pool Rules and Area Injection Order Application 6/25/2001 c) Property Bulk rock volume N/G ratio Sw Porosity 1/Formation volume factor 1/Formation volume factor Hydrocarbon pore volume in reservoir OOIP OGIP .) PUBLIC INFORMATION I Units Sag River Oil Sag River Gas ft3 L J~ 0/0 - - 0/0 - - 0/0 - - stb/rb - . Bbl/mcf - . ft3 MMbbls BCF Ivishak Formation Isopach maps, porosity maps, net to gross ratio maps and permeability maps were constructed for each unit within the Ivishak horizon. The upper conglomeratic unit was subdivided into five subunits with reservoir maps generated for each subunit. The Shublik 0 unit was included within the upper conglomeratic unit in the Ivtshak. The lower sandy unit of the Ivishak was subdivided into three subunits and the same reservoir maps were created for each of these subunits. The structure for the top of the static model was created by taking the structure map at the top of the Sag River and then adding the interval isopach between the Sag River and the top of the Shublik D. Subsequent interval isopach maps were then sequentially added together to create the structural model. Each of these reservoir maps were then back interpolated to generate a series of grids at 100 foot increments. These grids were then compared to existing well control for consistency. WATER SATURATION Sag River Formation Oil and gas shows from the Sag are seen in mudlogs in the Seal A-01, Seal A-02A, and Seal A-03 wells. No oil or gas shows were present in the Seal A-04 Page 11 Northstar Pool Rules and Area Injection Order Application 6/25/2001 C) .) PUBLIC INFORMATION Water saturations within the Sag River Formation range from . Presently no electrical property data measurements exist for the Sag River formation in the Northstar wells. Archie parameters were obtained from analog Sag River formation in the Milne Point area. The Archie parameters that were used in determining water saturation are "m" (cementation exponent) of _ and on "n" (saturation exponent) _. At present no capillary pressure measurement are available in the Sag River formation to confirm the log derived saturation model. Shublik Formation The only horizon containing possible moveable hydrocarbons in the Shublik formation is the Shublik D unit. Determining water saturation within this section is difficult using a conventional analysis and logs due to the presence or abundance of pyrite, which suppresses the induction log and gives anomalously high water saturation. Test and core fluorescence in Northstar-1 suggest that the Shublik may be gas bearing at that location. Ivishak Formation Since the cores from the Seal and Northstar wells were not acquired with low invasion oil based mud, the core water saturation measurements were not suitable for calibrating to log derived water saturation results. Traditional log derived saturation methods were also complicated by the various mud systems used and presence of significant amounts of microporous chert. Given the problems associated with the log derived saturation model, the average water saturation for the reservoir was generated from a multiple regression analysis of the available capillary pressure data to generate a capillary pressure model from samples representing conglomerates and sandstone. This average oil saturation was determined to be _ for the reservoir at the reservoir volumetric centroid of the field. The volumetric centroid of the reservoir is . The maximum oil column is estimated to be . The generic form of the equation for the reservoir water saturation was derived primarily from the porous plate, mercury air and centrifuge capillary pressure data from the core in Seal A-02A: Page 12 Northstar Pool Rules and Area Injection Order Application 6/25/2001 c.> (,) PUBLIC INFORMATION Conglomerates: Sw= Sandstones: Sw= Where: Sw = Water saturation (v/v) 0= Porosity (v/v) HAOWC = Height above oil water contact (feet) A total of 131 capillary pressure curve measurements were obtained from the Seal A-01, Seal A-02A, Seal A-03 and Northstar-1 wells. Of these, 101 were mercury injection, 24 were porous plate and 8 were centrifuge capillary pressure measurements. Of these, 26 were conglomerates, 94 were sandstones and 13 were cherts. This data was used to define the amount of effective porosity, micro-porosity, pore size distribution and oil saturation as a function of height above a free water level for both the conglomerate and sandstone facies. A significant amount of special core analysis measurements were obtained from the Northstar cores. Electrical property measurements were conducted on 35 core samples in order to define "m" (cementation exponent) and on 24 core samples to define "n" (saturation exponent) for use in the Archie equation to calculate water saturation from log data. The average "m" and "n" value for the Northstar Pool is ,respectively. These electrical property measurements were also broken out by conglomerates and sandstones facies. The average "m" value for the conglomerates and sandstones were ,respectively. The average "n" value for the conglomerates and sandstones were , respectively. Water resistivity was determined to be based on a formation water sample of 19,340 ppm NaCI from the Seal A-01 well. The chemical composition of the formation water sample taken from Seal A-01 is shown in Exhibit 13. Comparing core porosity measurements to the wireline log curves indicates that the sonic log provides the best correlation to core porosity followed by the density log and then finally the neutron log. The average grain density of the Ivishak reservoir rock _ glee. Page 13 Northstar Pool Rules and Area Injection Order Application 6/25/2001 f:) ~,'} PUBLIC INFORMATION PRESSURE & TEMPERATURE The initial pressure of the Northstar Pool at , the oil water contact, was _ psig (pounds per square inch gauge) based on RFT and bottom hole pressures measured in the Seal A-02 and Seal A-01 wells. For reference, this equates to _ psig at _ ft. TVDss, which is near the crest of the structure. Average reservoir temperature is estimated to be _ F at the oil column centroid. FLUID PVT DATA PVT analysis was carried out on recombined surface samples from Seal A-01, Seal A-02A, Seal A-03 and the Northstar-1 wells. A compositional analysis from Seal A-01 Test #2 is included as Exhibit 30 to typify the Northstar oil and gas. One bottom hole sample was obtained from the Seal A-01 well allowing comparison to the surface samples. Analysis of the PVT fluid samples indicates _ The ranges of fluid properties at initial reservoir conditions are listed below. Page 14 Northstar Pool Rules and Area Injection Order Application 6/25/2001 c> .) PUBLIC INFORMATION Fluid Property Oil API Gravity (Degrees API) Solution GOR (SCF/STB) Oil Formation Volume Factor (RB/STF) Oil Density at Bubble Point Pressure (gm/cc) Oil Viscosity (cp) Gas Viscosity Estimated (cp) Water Viscosity Estimated (cp) Near Water-Oil Contact II - II · · - · Near Gas-Oil Contact II - II II - . . Analysis of the bubble point pressure versus depth from the Seal A-01 well indicates the reservoir may be Several feet of gas were present in the top of the reservoir in the Shublik 0 zone in the Northstar-1 well. The gas elevated the GOR to _ SCF/STB in the well test in which the upper 30 feet of the well was perforated. These perforations included the Shublik D in addition to the upper Ivishak (Ivishak E). This gas appears to be isolated from other upstructure Ivishak wells in which free gas is not present. There is no evidence of a Heavy Oil Tar zone in the Northstar Ivishak reservoir. Results from the PVT data were used to generate both a 10 and a 15 component equation of state ("EOS"). The EOS along with the oil compositional gradient were used in the reservoir simulation studies. One slim tube experiment has been run with oil from the Northstar-1 well to verify miscibility. This experiment, which achieved a _ recovery efficiency at _ gas injection, was used to validate the EOS by history matching the slim tube results. PVT quality bottom hole fluid samples were taken in late May 2001 with the MDT tool from NS31. Oil samples (450 cc) were taken throughout the oil column with larger samples taken near the oil column centroid. The oil samples will be used in PVT studies to determine bubble point pressures and compositions, and for slim tube experiments to verify miscibility. _ Page 15 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ~) r) PUBLIC INFORMATION HYDROCARBONS IN PLACE Estimates of hydrocarbons in place for the Northstar Pool reflect well control, stratigraphic and structural interpretation, and rock and fluid properties. These data were integrated into a geologic model that provides the basis for the estimation of the original fluids in place. The results indicate an Original Oil in Place ("OOIP") of ("MMSTB"), a _ inferred gas cap occupying _ of the hydrocarbon pore volume, and _ total gas including solution gas. Structural interpretation is believed to have the greatest impact on uncertainty in 001 P, although there is also large uncertainty in determining the volume of oil filled intergranular porosity versus water filled microporosity. DEVELOPMENT PLANS Reservoir models of the Northstar Pool were constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles ,for facility design. This section of the application describes the reservoir models, recovery process selection, and the current development plans. Reservoir Model Description To evaluate the performance of the Northstar reservoir, both 3-D (three dimensional) full field models ("FFM") and finer grid mechanistic models were constructed. The models are compositional utilizing either a 10 or 15 component equation of state. The 3-D compositional full field model covers the entire Ivishak reservoir and the surrounding aquifer. The Sag and Shublik formations were not included in the reservoir simulation. The FFM has 400 foot (3.7 acre) grid blocks over the oil column with 2000 foot (92 acre) grid blocks over the surrounding aquifer. There are 18 vertical layers with grid block thickness averaging 15 to 30 feet. Faults are included in the model through corner point geometry and are considered to be neutral with respect to fluid flow. A capillary pressure equation (as defined earlier) relating porosity and height above the oil water contact was used to predict initial water Page 16 Northstar Pool Rules and Area Injection Order Application 6/25/2001 .) ~) PUBLIC INFORMATION saturations. Grid block values for porosity, permeability, net to gross, and isopach layer thickness were obtained by back interpolating grid block coordinates against the static model. Grid block values for top Ivishak were derived from maps of top Sag River and isopach maps of the Sag and Shublik. Very finely gridded mechanistic 1-0 (one dimensional) models were used to study miscible displacement aspects of the flood. One slim tube experiment has been run with oil from the Northstar-1 well to verify miscibility. This experiment was used to validate the EOS by history matching the slim tube results. Mechanistic finer gridded 3-D partial field models were also developed. These ongoing model studies are being used to study water coning, horizontal versus vertical well performance, and to validate the coarser grid FFM. The full field model is in the process of being updated to incorporate the revised geological model which is being modified to include the results of the development wells drilled to date. Recovery Process Selection A miscible gas injection project, along with waterflood, gas cycling, and primary depletion scenarios, were evaluated. All of the cases used the same number of wells and locations. Injection was controlled to maintain reservoir pressure near for the miscible gas and waterflood cases, with pressure declining in the gas cycling and primary depletion cases. Oil and natural gas liquids ("NGL") recovery for these cases are given below with production plots shown in Exhibits 14 through 17. Oil NGL Total Liquid RF . 0/0 OOIP (Oil) Miscible Gas Injection - - · Waterflood - II - · Gas Cycling - . - · Primary Depletion . II . · Miscible gas injection was the recovery method selected due to its significantly higher recovery efficiency. Oil recovery with miscible gas injection is forecast to be higher than Page 17 Northstar Pool Rules and Area Injection Order Application 6/25/2001 c) .) PUBLIC INFORMATION either gas cycling or waterflood. The project is being implemented concurrent with field startup to deliver maximum benefit. Water alternating with gas ("WAG") injection was also evaluated. The model runs indicated essentially no additional recovery from WAG injection. However, if the reservoir turns out to be highly stratified, WAG injection could mitigate gas channeling through high permeability intervals. Miscible injectant is made by blending "make-up" gas from Prudhoe Bay Unit ("PBU") with Northstar produced gas. NGLs are left in the produced gas during the miscible injection phase of the project by not running the refrigeration unit of the NGL plant. The "make-up" gas from PBU acts to maintain reservoir pressure which maintains miscibility. It is currently anticipated that NGLs will be left in the produced gas forthe first four years of the project resulting in injection of up to _ hydrocarbon pore volume of miscible enriched natural gas into the oil column. The miscible gas injection phase will be followed by leaner chase gas injection for the remainder of the oil production phase of field life. Current Development Plans The current Northstar development provides for drilling 21 new wells on an average well spacing of about 400 acres. Five of the wells are planned as miscible gas injectors, with sixteen oil producers. The injectors are located in the central thicker oil column portion of the reservoir to maximize miscible sweep efficiency in areas that contain the greatest OOIP. Two of the injectors will be pre-produced to help load the production facility at startup. The wells in the thicker oil column portion of the reservoir are scheduled earlier in the drilling schedule. The current development plan calls for drilling the peripheral producers as high angle wells which allows e-line or slick-line access for routine surveillance. Water coning at Northstar is an area of uncertainty due to the apparent absence of barriers to vertical flow, and horizontal peripheral wells are currently being evaluated as a possible option. To help evaluate water coning issues, we plan to take RFT pressure data in wells drilled after field startup to determine if there are vertical cement barriers present in the reservoir that "might act to reduce water Page 18 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ~) ~) PUBLIC INFORMATION coning. Recent model runs indicate that with sufficient standoff from the,OWC, water production should remain below the 30,000 BWPD facility limit. Future Development Plans Additional reserve options exist within the Northstar unit beyond the scope of the initial development described in this document. Our ability to drill extended reach wells presently limits. us to wells with bottom hole locations no more than approximately 17,500 ft. from the production island. As a consequence, approximately barrels of oil remain in the North West portion of the reservoir at the end of field life if no further development drilling were carried out after the initial 22 well drilling program. We expect that with the experience that the initial well schedule will gain uS,and with advances in drilling technology, that additional wells that will tap this remaining potential will be possible at the end of the current drilling program. The reserves in the North West portion of the reservoir will remain essentially untouched by the initial development program as a consequence of maintaining the reservoir pressure close to original pressure. We also recognize the possibility that satellite oil accumblations may exist within expected drilling reach from the island. These targets will be the subject of additional appraisal. RESERVOIR MANAGEMENT STRATEGY The objective of the reservoir management strategy is to maximize ultimate recovery consistent with sound engineering practice. Reservoir pressure strategy and field oil production rate are addressed in the reservoir management strategy. Reservoir Pressure Strategy Reservoir pressure in the Northstar reservoir will need to be managed in order to: ensure miscibility; minimize oil loss due to shrinkage from producing below bubble point pressure; minimize oil loss due to pushing oil into the aquifer by over pressuring the reservoir; and achieve some aquifer influx to sweep the periphery and structurally low areas. Our current reservoir management strategy during the miscible phase of the project, which is expected to last the first four years of field life, is to voidage replace 1000/0 of total production to maintain reservoir pressure at the initial value found at field startup. However, during the first Page 19 Northstar Pool Rules and Area Injection Order Application 6/25/2001 c) () PUBLIC INFORMATION year of the project we would like to maintain the option of exceeding 1000/0 voidage replacement to ensure miscibility and compensate for some of the prior and anticipated pressure declines. To maintain operational flexibility during the miscible phase we plan to operate within a range around the pressure found at flood start. After the miscible phase of the project, it is yet to be determined how much reservoir pressure should be allowed to drop to stimulate water influx around the periphery of the fièld. To prevent hydrocarbons from being displaced into the aquifer, the average reservoir pressure will not be increased appreciably above its initial value. Most of the reservoir is underlain by bottom water and there is also a large oil water contact periphery. Locating the injection wells in the thick oil column areas of the reservoir which have low OWC's will help to minimize oil pushed into the aquifer beneath injectors due to local pressure gradients. After the miscible phase of the project, there may be benefit from dropping reservoir pressure below the initial value to achieve natural water influx around the periphery of the reservoir and low in the oil column. The lower portion of the reservoir is not as efficiently swept by the injected gas due to gravity segregation of the gas within the oil column. Allowing a decline in reservoir pressure allows water influx to sweep areas that are less efficiently swept by the miscible flood. Late in field life (approximately 16 years after field start up) during blow down, reservoir pressure will be reduced ~o maximize recovery of the injected gas. Gas recovery volumes from blow down have not as yet been estimated. Impact Of Field Production Rate Three field production rate scenarios have been evaluated. These cases were run prior to obtaining the pressure data from new wells. Average oil off take rates of 65, 72, and 90 MSTB/D were evaluated in the full field simulation model with the results shown below and production plots shown in Exhibits 14, 18 and 19. Page 20 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ~) ~) PUBLIC INFORMATION Total Liquid Produced Produced Injected Gas Water Gas Plateau Rate (MMSTB) (MMBW) ... -- 65 MBOPD - - 72 MBOPD - - - -- 90 MBOPD - - - -- Water coning in the peripheral wells caused the runs to come off plateau due to water handling constraints. The 90 MBOPD case came off plateau in about two years, while the 65 MBOPD case remained on plateau for about four years. However, subsequent mechanistic and FFM model runs indicate water coning may not be as severe as observed in these cases and could be managed through the perforation strategy with sufficient standoff from the OWC. The 30,000 BWPD facility water handling limit currently appears to be more than adequate. Makeup gas imported from PBU was limited to 100 MCF/D for each of the cases. Reservoir pressure declines during the high fluid off take plateau periods ranged from _ for the 65 MBOPD scenario to _ for the 90 MBOPD plateau case. The ultimate oil recoveries determined from these model runs were not sensitive to field production rate. The higher off take cases did slightly better due to producing and injecting greater volumes of gas through the reservoir early in field life before gas handling facility limits were reached. BENEFIT OF IMPORTED PRUDHOE BAY GAS Page 21 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ~) () PUBLIC INFORMATION - Page 22 Northstar Pool Rules and Area Injection Order Application 6/25/2001 c) () PUBLIC INFORMATION 4. Facilities INTRODUCTION The Northstar project consists of a self-contained production facility on Seal Island, located 6 miles offshore of the Point Storkerson area in the Alaskan Beaufort Sea. Seal Island is a gravel island of approximately 5 acres constructed over the remains of the island built by Shell Oil Company to conduct exploratory activities during the 1980's. Two pipelines have been buried in a single trench from Seal Island to existing onshore facilities to transport hydrocarbons to and from the Northstar Unit. The pipelines include one 10-inch common carrier pipeline from Seal Island to Pump Station No. 1 to transport the sales oil to TAPS. The second 10-inch pipeline facilitates the import of up to 100 mmscfd hydrocarbon gas from the Central Compressor Plant in the Prudhoe Bay Unit to Seal Island to assist with the gas cycling process used to produce the Northstar Pool. The plant design allows the imported gas to be used for fuel. The production facility will be capable of handling 65 mbd of oil, 30 mbd of produced water, and 600 mmscfd of total injected gas. The processing facilities consist of three primary modules. The first, a three level module, will contain the separation, gas dehydration and power generation equipment. The second module will contain the low and high pressure gas compression equipment. The third module will contain the water storage and disposal systems. These three modules are being assembled in Anchorage and will be sea-lifted to Seal Island in the summer of 2001. A simplified process flow diagram is shown in Exhibit 20. Options to allow an increase in the facility handling capacities are currently being evaluated. A permanent camp facility for up to 74 production and drilling personnel will be installed on the island. Emergency power generation, seawater treatment and sewage facilities will be provided for the camp. Tankage for diesel fuel and water storage will also be included. Exhibit 21 shows the general layout of the island. While drilling operations are underway, access to the island in the winter months will be by ice road. During the summer open water period, routine access will be barge or supply boat. At all other times, helicopters will be used to travel to and from the island. Page 23 Northstar Pool Rules and Area Injection Order Application 6/25/2001 c) .) PUBLIC INFORMATION INFRASTRUCTURE Seal Island will be the first offshore production island in the Beaufort Sea. The critical infrastructure installed to support operating and essential maintenance of the production facility include: 1. A 74 bed permanent camp with kitchen, dining room, fitness equipment and critical medical care facility; 2. Utilities, including potable water generation, waste water treating, solids incineration, communication gear, and firewater systems; 3. Warehouse / Shop for onsite repairs and critical materials storage; 4. Helideck and dockface; and 5. Class 1 disposal well. Well Row Facilities The island layout is designed for. 37 well slots. Sixteen producers, five gas injectors and one disposal well are planned for the base development. The piperack along the well row has headers for well testing, single train production, gas injection and water disposal. A hydraulic well system and individual well safety panels are included in the piperack, as are utility water, fuel gas, highline electric connections, and vacuum / fluid exchange headers to support drill rig operations. Main Process Module The main process module, which will be sealifted in two halves and reconnected onsite, will house production separators, gas coolers and dehydration facilities, a Natural Gas Liquids ("NGL") stabilization system, turbine driven generators, a waste heat recovery system for process and utility heat, gas relief collection headers / scrubbers, fuel gas letdown skid, and plant air and nitrogen systems. The south end of the process module will house the oil custody transfer LACT unit, shipping pumps, the oil pipeline pig launcher and the gas import line pig receiver. Page 24 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ~) ~) PUBLIC INFORMATION Compressor Module The compressor module will support the flare boom, and will include a single low pressure, multi-section motor driven compressor, two turbine driven injection gas compressors, and coolers, piping and scrubbers for the three compressors. Pumphouse Module A small pump-house module will, have tankage for produced water and well cleanup fluids, centrifugal produced water pumps, and a positive displacement water disposal pump. Production Allocation Production will be allocated to producing wells based on individual well tests and actual plant oil sales volume. All production wells are individually connected to the test header. Each producing well will be tested monthly to ensure accurate allocation of the produced fluids. The Programmable Logic Control ("PLC") system (Plantscape) and Plant Historical Database (Uniformance Historian) will continuously gather operating data from the plant, wells, and test separator. The following points will be honored as part of the production allocation procedure: 1. All wells will be tested monthly. 2. The stabilization and duration of each test will be optimized by the operator to obtain a representative test. 3. Well and field operating condition information required for the construction of a field production history will be maintained. 4. Test separator meters and major gas system meters will be installed and maintained according to industry recommended practices or standards. 5. The Operator will maintain records that permit verification of the satisfactory execution of the production allocation methodologies. Flaring Philosophy Northstar flaring will be aligned with the BPXA corporate policy to "minimize flaring." Flaring will be governed by these principles: Page 25 Northstar Pool Rules and Area Injection Order Application 6/25/2001 t) ,.) PUBLIC INFORMATION 1. Gas injection will be started prior to opening production chokes. This ,.will minimize flaring of primary stage separation off gas during plant startup. 2. Gas will be flared from low pressure separators only long enough for gas flows to stabilize at a rate sufficient for startup of the multistage LP Compressor. 3. Maintenance flaring will continue only during limited periods of problem solving or equipment / compressor testing. In no event will maintenance flaring exceed 48 hours without notification and approval from the MMS as required by 30 CFR 250.11 05(a)(2)(i). 4. The control system will be configured to initiate an automatic shutdown of operator selected wells in the event of partial loss of Injection' Gas Compression capacity (shutdown of one of two IG compressors). In the event of a compressor emergency shutdown, this will limit flaring to equipment depressurization volume~ only. 5. Depressurized plant shutdown will be the automatic response to gas detected in environmentally controlled spaces of the process module. The gas injection plant and the gas injection well will be commissioned prior to the initial start of oil production at Northstar in November using Prudhoe Bay Unit make up gas. This will reduce the amount of flared gas that traditionally is associated with the start up of new production facilities. Page 26 Northstar Pool Rules and Area Injection Order Application 6/25/2001 () (') PUBLIC INFORMATION 5. Well Operations DRilliNG The Northstar Pool will be accessed by wells directionally drilled from the newly constructed Seal Island. These wells have been designed in accordance with standard practices and operations across the North Slope. Current island layout results in these wells being drilled on 10 foot nominal centers. Below is a brief summary outlining the proposed drilling and completion plans for both the production and injection wells. Well construction will be initiated on 20 inch structural casing which has already been driven to approximately 160 ft. below ground level for all of the wells. The structural casing will provide an adequate anchor for the diverter system and support any shallow unconsolidated strata. A diverter system compliant with 20 AAC 25.035(c) and 30 CFR 250.409 will be nippled up during surface hole drilling operations for the first five wells, during which the required data for a diverter waiver application will be collected. A diverter will not be rigged up for the remainder of the wells drilled at Northstar, assuming that BPXA, the Commission and MMS reach mutual agreement concerning the interpretation of the data. BPXA will request Field Drilling Rules from MMS at a later date in order to waive the MMS diverter requirements of 30 CFR 250.409. Conductor casing requirements as outlined in 20 AAC 25.030(c)(2) have been waived for the Northstar development as per the memo entitled "Dispensation for 20 AAC 25.030(c)(2)" dated March 1, 2000. The structural casing provides an adequate anchor to allowing drilling to the surface casing point at which point the blow-out preventer ("BOP") stack will be nippled up. Surface hole sections for all wells will be drilled to a depth of approximately 3160 ft. TVDss (150 ft. TVD below the SV6 marker). Intermediate hole sections for the gas injection wells will be directionally drilled to top set the Sag River formation at approximately 10,645 ft. TVDss, while intermediate hole sections for the production wells will be directionally drilled to top set the Miluveach formation at approximately 9264' TVDss. For production wells only, a second intermediate hole section will be required and will be directionally drilled to top set the Sag River formation at approximately 10,645 ft. TVDs. Both production and injection hole sections will be drilled through the Sag River, Shublik, and Ivishak formations to a TD in the Ivishak or the adjacent Kavik formation. Page 27 Northstar Pool Rules and Area Injection Order Application 6/25/2001 () () PUBLIC INFORMATION All casing strings will be run and cemented in accordance with 20 ACC 25.030" and 30 CFR 250.404. Injection wells will have a cement evaluation log run to confirm isolation of the injection fluids to the approved injection intervals (Sag River and Ivishak Formations) as required per 20 AAC 25.030(d)(7). Such logs will also satisfy the requirements of 30 CFR 250.404(a)(5). The casing and tubing heads will ,be nippled up with the BOP stack and tested according to Commission and MMS regulations. Leak-O'ff-Test ("LOT") and Formation Integrity Test ("FIT") will be performed on all casing strings after drilling 20-50 feet in accordance with 20 AAC 25.030(f) and 30 CFR 250.404(a)(6) or as approved by the drilling permit. In addition to lined, cemented, and perforated completions, it is proposed that the Pool Rules authorize the following alternative completions: 1 . Horizontal or "high angle" completions with slotted or perforated liners. 2. Open hole and/or slotted / pre-perforated completions. 3. Multi-lateral completions in which more than one reservoir penetration is completed from a single well. Tubing will be run in all wells with a packer. Injection well design will place the packer within 200 ft. of the targeted injection zones, the Sag River and Ivishak, in accordance with 20 AAC 25.412(b). Although this packer placement may result in a packer to perforation distance greater than 200 ft., it retains the option of perforating the Sag River in the future and it does not compromise zonal isolation given the depth and thickness of the overlying confining zone (Kingak formation). The drilling schedule for Northstar should follow a drill and complete scenario based on current planning. Batch drilling of surface and/or intermediate holes may be initiated dependent on broken ice restrictions and logistical constraints. Page 28 Northstar Pool Rules and Area Injection Order Application 6/25/2001 () (') PUBLIC INFORMATION BLOWOUT PREVENTION EQUIPMENT Blowout prevention equipment ("BOPE") will be rigged up and tested in accordance with 20 AAC 25.035 and 30 CFR 250.406, .407, .515 and 516, as applicable. Any modifications to previously submitted BOPE diagrams will be updated and submitted with the appropriate Application for Permit to Drill ("APD"). A diverter waiver request will be submitted if the above referenced shallow gas hazard identification indicates that no shallow gas hazard exists at Northstar. DRilliNG FLUIDS The drilling fluid program designed for Northstar will be prepared and implemented in full compliance with 20 AAC 25.033 and 30 CFR 250.410. Formation pressures for all horizons to be penetrated are known based on the Seal Island appraisal wells. DIRECTIONAL DRilliNG Conventional MWD surveys will be used at Northstar. BPXA requests that the detailed reporting and plotting for directionally drilled wells required by 20 AAC 25.050(b) be waived for the Northstar Pool. Current regulations require extensive data packages with the APD on all wells located within 200 f1. of a directionally drilled well. All drilling at Northstar will be confined to the Northstar Pool and Northstar Unit boundaries with established working and royalty ownership. Instead, the Operator requests that the following information be included in each APD: 1 . Plan view; 2. Vertical section; 3. Close approach data; and 4. Directional data. WEll DESIGN Current development plans for Northstar include five gas injectors, sixteen oil producers and one Class I disposal well. Three of the gas injectors will be completed with 7 -inch tubing and Ii ners. Two of these wells will be pre-produced for a period of between 3 and 6 months, and will be completed with 13 Chrome tubing and liners. The remaining 7 -inch gas injector will be Page 29 Northstar Pool Rules and Area Injection Order Application 6/25/2001 .... .) ~) PUBLIC INFORMATION placed on dedicated gas injection service from the start of operations and will be completed with L-80 grade tubulars. The other two gas injectors will be completed with 51h-inch L-80 tubing and liners. The sixteen production wells will be completed with 4Y2-inch 13 Chrome tubing and liners. Exhibits 22 through 26 show wellbore schematics for the completion designs. The detailed casing program will be included with the APD for each well and documented with the Commission or MMS, as applicable, in the completion record. API injection casing specifications must be submitted with each APD. All injection casing will be cemented, tested and its mechanical integrity verified in accordance with 20 AAC 25.030, 20 AAC 25.412, 30 CFR 250.404 and 30 CFR 250.405. The detailed well casing and cement program will be submitted with the APD for each injection well. Injection well tubing / casing annulus pressures will be monitored and recorded on a regular basis. BPXA, as Operator, will be responsible for the mechanical integrity of injection wells and for ensuring compliance with monitoring and reporting requirements. The tubing / casing annulus pressure of each injection well will be monitored weekly to ensure that there is no leakage and that the pressure does not subject the casing to a hoop stress greater than 70 percent of the casing's minimum yield strength. However, if an injection well is deemed to have anomalous annulus pressure, it will be investigated for tubing / annulus communication using a variety of diagnostic techniques and a mechanical integrity test. If a subsequent investigation proves hydraulic communication between the tubing / casing exists, then a plan for remedial action will be formulated and scheduled. In addition, a variance will be obtained from the Commission or MMS, as applicable, to continue safe operations, if technically feasible, until the remedial solution is implemented. Tubing / casing pressure variations between consecutive observations need not be reported to the Commission or MMS. A schedule will be developed and coordinated with the Commission which ensures that the casing / annulus for each injection well is pressure tested prior to initiating injection. A pressure test will consist of subjecting the injection well to a test surface pressure of at least 1 ,400 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70 percent of the casing's minimum yield strength. The test Page 30 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ,\:, . ') .) PUBLIC INFORMATION pressure must be held for 30 minutes with no more than a 10 percent decline. The Commission will be notified at least 24 hours in advance to enable a representative to witness the pressure test. Alternative EPA approved methods may also be used, with Commission approval, including, but not necessarily limited to: timed-run radioactive tracer surveys ("RTS"); oxygen activation logs ("OAL"); temperature logs ("TL") and noise logs ("NL"). An injection well located within the area subject to the AIO will not be plugged or abandoned unless approved by the Commission or MMS, as applicable, in accordance with 20 AAC 25.105 and 30 CFR 250.701. SURFACE AND SUBSURFACE SAFETY VALVES All Northstar wells, with the exception of the Class I disposal well, will be equipped with a fail safe automatic surface safety valve ("SSV") and a fail safe automatic surface controlled subsurface safety valve ("SSSV"). The SSSV's in both the producers and injectors will be wire line retrievable. The SSSV's will comply with the requirements of 30 CFR 250.801 and .806. RESERVOIR SURVEILLANCE PROGRAM Northstar reservoir data will be collected to monitor reservoir performance and to define reservoir properties. In lieu of the requirements of 20 AAC 25.071 (a), BPXA requests that a complete electrical or complete radioactivity log be required from below the structural casing to TO for only one well drilled from Seal Island. RESERVOIR PRESSURE MEASUREMENTS Initial static reservoir pressure will be measured in each new well prior to long term production or injection. Additionally, a reservoir pressure will be recorded in at least half of the available active wells annually. These will consist of stabilized static pressure measurements at bottom- hole conditions, or, in the case of the gas injectors where a single phase fluid occupies the well bore, extrapolations from shut in surface pressures, The reservoir pressures will be reported at the common datum elevation of 11,100 ft. TVDss. It is the intention to run surface read out real time fiber optic temperature and pressure gauges in the producing wells at Northstar. These gauges will provide additional static and dynamic pressure information above that normally available in traditional North Slope wells. Page 31 Northstar Pool Rules and Area Injection Order Application 6/25/2001 () (") PUBLIC INFORMATION SURVEILLANCE LOGS Additional surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir performance. Additionally, injected gas tracers are being evaluated as a means of further evaluating the sweep efficiency of the flood. The program as envisaged would involve a separate tracer being injected into each gas injector, followed by a program of sampling and analysis of produced gas at each producer. Page 32 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ~) ~) PUBLIC INFORMATION 6. Area Injection Order Application BPXA, as Northstar Unit Operator, hereby applies for an Area Injection Order ("AIO") to cover water and miscible fluid injection operations in the Northstar Pool as proposed herein. This section addresses the specific requirements of 20 AAC 25.402(c). PLAT OF PROJECT AREA- 20 AAC 25.402(c)(1) Exhibit 6 is a plat showing the location of existing and proposed injection and production wells, and· the original Northstar exploration and appraisal wells. Exhibit 3 contains the legal description of the lands subject to the Northstar Area Injection Order (the "Northstar Injection Area"), and these are presented on a map in Exhibit 2. OPERATORS/SURFACE OWNERS - 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) The surface owners and operators within a one-quarter mile radius of the Northstar Injection Area are: Operators: BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Surface Owners: Department of Natural Resources State of Alaska 550 W. ih Avenue, Suite 800 Anchorage, AK 99501 Minerals Management Service 949 East 36th Avenue, Room 308 Anchorage, AK 99508-4363 Oil & Gas Lessees: BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Murphy Exploration (Alaska) Inc. 550 Westlake Park Blvd., Suite 1000 Houston, TX 77079 Page 33 Northstar Pool Rules and Area Injection Order Application 6/25/2001 c) () PUBLIC INFORMATION Phillips Alaska, Inc. 700 G Street P.O. Box 100360 Anchorage, AK 99510-0360 A VCG LLC 225 North Market Wichita, KS 67202 Note: A VCG LLC has purchased Phillips Ala$ka, Inc.'s interest in ADLs 385198 and 385202. Assignments have been submitted to the State of Alaska, Department of Natural Resources, Division of Oil & Gas for approval. Exhibit 28 is an affidavit' showing that the Operators and Surface Owners within a one-quarter mile radius of the Northstar Injection Area have been provided a copy of this application, as required by 20 AAC 25.402(c)(3). Lessees have also been provided a copy. DESCRIPTION OF OPERATION - 20 AAC 25.402(c)(4) Development plans for the Northstar Pool are described in Section 3 of this application. Island facilities and operations are described in Sections 4 and 5. POOL INFORMATION - 20 AAC 25.402(c)(5) The proposed Northstar Injection Area encompasses the Northstar Pool. The Northstar Pool is defined as the accumulation of hydrocarbons in the Ivishak, Shublik and Sag River formations common to and correlating with the interval between the measured depths of 12,418 feet and 13,044 feet in the Seal A-01 well. GEOLOGIC INFORMATION - 20 AAC 25.402(c)(6) The geology of the Northstar Pool is described in Section 2 of this application. WELL LOGS - 20 AAC 25.402(c)(7) Copies of all open hole logs from Northstar wells are sent to the Commission as the wells are completed. Exhibit 4 is the type log for the proposed Northstar Injection Area with stratigraphic and marker horizons annotated. Page 34 Northstar Pool Rules and Area Injection Order Application 6/25/2001 .) ~) PUBLIC INFORMATION INJECTION WELL CASING INFORMATION -20 AAC 25.402(c)(8) The injection well casing design and additional information is described in Section 5 of this application. INJECTION FLUIDS - 20 AAC 25.402(c)(9) A description of the recovery process and development scheme is included in Section 3 of this document. Injection fluid will comprise a blend of associated reservoir gas and imported PBU gas. The composition of the injected fluids is listed in Exhibit 27. Maximum daily injection rates are presented in Exhibit 14. Fluid incompatibility problems, including asphaltene deposition, are not anticipated with the miscible gas flood. INJECTION PRESSURES - 20 AAC 25.402(c)(10) The maximum injection pressure at the wellhead is estimated to be 5300 psig. The average injection pressure at the wellhead is estimated to be 5000 psig. FRACTURE INFORMATION - 20 AAC 25.402(c)(11) The expected maximum injection pressure for the gas injection wells, 5300 psi, is insufficient to initiate or propagate fractures through the confining strata, and, therefore, will not allow injection or formation fluid to enter any freshwater strata. Fracture Gradients Exhibit 29 presents a summary of the fracture pressure and reservoir pressures determined from leak off testing, mud weights and drill stem testing in the discovery and appraisal wells in the Northstar Unit. Freshwater Strata EPA has determined that there are no underground sources of drinking water ("USDW") beneath the Northstar Unit, as stated in the Public Notice dated June 24, 2000, and the Fact Sheet for the proposed issuance of UIC Area Permit AK-1002-A dated June 23,2000. Page 35 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ..) () PUBLIC INFORMATION The lack of fresh water and USDW's in the Northstar Injection Area eliminates the need for an aquifer exemption. The presence of hydrocarbons, either live or as residual, causes the Northstar sands to be unsuitable as a source of drinking water FORMATION WATER ANALYSIS - 20 AAC 25.402(c)(12) Exhibit 13 lists the composition of a Northstar area formation water sample. The source of the sample was produced water from a production test on Seal A-01. A production test was performed to confirm the presence of an apparent oil-water contact at approximately 11,110 ft. TVDss. The water analysis was conducted by Chemical & Geological Laboratories of Alaska, Inc. on June 15, 1984. .AQUIFER EXEMPTION - 20 AAC 25.402(c)(13) As set forth above, the lack of fresh water and USDW's in the Northstar Injection Area eliminates the need for an aquifer exemption. The presence of hydrocarbons, either live or as residual, causes the Northstar Pool to be unsuitable as a source of drinking water. HYDROCARBON RECOVERY - 20 AAC 25.402(c)(14) The initial reservoir modeling of the Northstar Pool involving a waterflood only development scheme indicated recoverable reserves of 135 mmbbls of oil. The miscible gas recycle program currently yields 176 mmbbls oil, an increase of 41 mmbbls of ultimate oil recovery. The recoveries for the development options considered for the Northstar Pool are discussed in Section 3 of this document. MECHANICAL CONDITION OF ADJACENT WELLS - 20 AAC 25.402(c)(15) Exhibit 6 shows the location of proposed injection wells and existing wells. None of the proposed injection wells penetrate the injection zone within one-quarter mile radius of an existing well. The information submitted herein establishes that drilling 16 producers and 5 injectors at the Northstar project through 2003 will increase ultimate recovery without increasing the probability that any individual well will suffer an integrity failure. Page 36 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ..) ~) PUBLIC INFORMATION 7. Proposed Area Injection Order Rules BP, in its capacity as Northstar Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Northstar Oil Pool and consider the following rules to govern such activity. The boundary of the lands subject to the Northstar Area Injection Order (the "Northstar Injection Area") and the Northstar Pool Rules is shown in the map attached as Exhibit 2, and is described in Exhibit 3. Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, Class II fluids may be injected for the purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to the formation found in the Seal A-01 well between measured depths of 12,418 - 13,044 feet. Rule 2: Fluid Injection Wells The injection of fluids must be conducted through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 3: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 700/0 of the casing's minimum yield strength. Rule 4: Reporting the Tubing-Casing Annulus Pressure Variations Tubing-Casing annulus pressure variations between consecutive observations need not be reported to the Commission. Page 37 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ..) ~) rOBLIC INFORMATION Rule 5: Demonstration of Tubing-Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, and following well workovers affecting mechanical integrity. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casings minimum yield strength must be held for at least a 30 minute period with decline no more . than or equal to 10% of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever injection rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue injection and submit a plan of corrective action on Form 1 0-403 for Commission approval. Rule 7: Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8: Administrative Action Upon proper application, 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 principles. Page 38 Northstar Pool Rules and Area Injection Order Application 6/25/2001 ~'" ) (~) PUBLIC INFORMATION 8. Proposed Pool Rules BPXA, in its capacity as Northstar Operator, requests that the Commission adopt the following Pool Rules for the Northstar Pool: Subject to the rules below and statewide requirements, production from the Northstar reservoir may occur in a manner that will protect freshwater, prevent waste, protect correlative rights, and provide for the maximum ultimate recovery of oil and gas that is prudent. In addition to statewide requirements, the following pool rules are proposed to govern the proposed development and operation of the Northstar Pool. Rule 1: Field and Pool Name and CI'assification The field is the Northstar Oil Field and the pool is the Northstar Pool. The Northstar Pool is classified as an Oil Pool. Rule 2: Pool Definition The boundary of the lands subject to the Northstar Area Injection Order (the "Northstar Injection Area") and the Northstar Pool Rules is shown in the map attached as Exhibit 2, and is described in Exhibit 3. The Northstar Pool is defined as the accumulation of hydrocarbons in the Ivishak, Shublik and Sag River formations common to and correlating with the interval between measured depths of 12,418 feet and 13,044 feet in the Seal A-01 well. Rule 3: Spacing Minimum spacing within the pool will be 40 acres. The pool shall not be opened in any well closer than 500 feet to an external unit boundary where ownership changes. Rule 4: Drilling and Completion Practices a) The following alternative completions are authorized: 1) Horizontal or "high angle" completions with slotted or perforated liners. 2) Open hole and/or slotted / pre-perforated completions. 3) Multi-lateral completions in which more than one reservoir penetration is completed from a single well. Page 39 Northstar Pool Rules and Area Injection Order Application 6/25/2001 f') () PUBLIC INFORMATION b) At a minimum, the following information must be included in each APD: 1) Plan view; 2) Vertical section; 3) Close approach data; and 4) Directional data. c) A complete electrical or complete radioactivity log is required from below the structural casing to TO in only one well drilled from Seal Island. Rule 5: Reservoir Pressure Monitoring a) Bottom hole reservoir pressure will be measured in at least half of the active wells 'each year. b) The reservoir datum will be 11,100 ft. true vertical depth subsea. c) Pressure surveys may consist of stabilized static pressure measurements at bottom- hole conditions or, in the case of the gas injectors where a single phase fluid occupies the well bore, extrapolation from surface shut in pressure. Initial reservoir pressure may also be determined from open-hole formation tests. d) Data and results from pressure surveys shall be reported annually to the AOGCC (but within 60 days to the MMS). Rule 6: Gas-Oil Ratio Exemption Wells producing from the Northstar Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 7: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering. Page 40 Northstar Pool Rules and Area Injection Order Application 6/25/2001 o bp NORTHSTAR POOL L.OCA11ON MAP , ~ ~ ~ I CD Northstar Unit Tract Number - NorthsIBr Unit Boundary (Expansion Application Pending) ~ Northstar Lease Boundary Northstar Pool Area ... 28,004 AJ:;res o I 1 :78,000 1 I 2 Miles I T13N T12Ni i ; ¡ i I I ¡ i j i I I --+- I ! .. ...~} 1 CD. i~¡ - ~"I ~Y0179 CD ~_ . _ ,: _ _ :i::;:'~'!L1\:~ ..-:..__ L--:::::'IIl.'~i , - - -'~"-I·· ..... .:~ .. .., .n _ - æ· ~-. , . : i ' Li . ,'~~:. <I b:~c:-~':~~~~~:~:~~'1] f ' "f' .... '" .' ¡ ~1 ". -- -"- ,·'Jf>.:-· ¡<D' ! " i " ¡LjgJi27bsþr>'".ii ~ 1 ~~~...... ~~; l¡ " ~~~;..~'" "f! - ¡ ¡ ¡! -- "'-1~~'-'-~'.'<" ,- ~ ! v. ZJ Iff ~;: . ", ~ . , _ ! i ¡ ~. f, ¡ II . 1:'3. :~lf,.-- '~~ ~ ""~~"::~ ft 1, ,¡ I ~ H"~"-YT _ ~: ÞDl312808 I -: ",',:- . <,;,;Z , "'. J- ¡ I .c~_._.'L¡ ¡ L;~~1~t~i~~~Þ:I~I"""~£ ''':~&..w1r· -. :., ¡ I I i ~ i '" ~ ~~ nI"'._~õI~"'~--1-~ ~~ ~. ! ~ { :J1 ! ¡ ¡ ~ f~ '. ' î I ~ zc :.¡ ~ m A.k135~501'\1 ~ I, :s ;-f-, ,,;' 1ft : L j Q ¡'-'{"~"" _'~_'._."_n.·J II;~ I jl ! ~~- "~. ~.~.. U~-~\-,·~-"t~.. ----.(.<. {i I ß " #..;1' n ~ .' ~...._" "'-:--"H " ~. I U ! ,I . ¡ =.n :'t ti AD4312á09¡ ;-, '\ \ ~ ""1.--- ;m:.---' - l· I . \1 -~->~ -"'~'M"' -L~~-!U~", , Q r: ~> ,,-~~~~~~~, T~':~'~: .J.-~,,'~:~-=-::; ~ ~ .:.~ _: ¡ - - ¡-i . '(1645 r ;, :!7 ~ 3J as T14N T13N 10 21 èi I;) Exhibit 2 - .-.--- í I I i I I ! j ; to I 1t J.C 'D ;14 ~ ! ¡ I i i ¡ I I i ,= 11 !~ 12 WW 7 .,.10 liã: Z! T14N T1i I i -r- I ¡ f ; 1-- ¡-~. I ¡ i I i I ! ; J~ T13N ;N; ~ nt"JWa ,...-----.,..At...")IUHA-4~..c._ ~) ~) Exhibit 3 Description of Northstar Injection Area The Northstar Injection Area is. shown on the map attached as Exhibit 2. State Leases The Northstar Injection Area encompasses State oil and gas leases ADLs 312798, 312799, 312808,312809 and 355001 to the extent such leases are located within the lands described below: T. 14 N.. R. 13 E.. Umiat Meridian. Alaska Sections 30-35 T. 13 N.. R. 13 E.. Umiat Meridian. Alaska Sections 2-18, and 20-24 T. 13 N.. R~ 14 E.. Umiat Meridian. Alaska Sections 17-20, 29 and 30 ADL 312798 consists of Tract C30-46 (SF-46), a portion of Blocks 470 and 514 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30n9. ADL 312799 consists of Tract C30-47 (BF-47), a portion of Slocks 471 and 515 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30n9. ADL 312808 consists of Tract C30-56 (SF-56), a portion of Blocks 514, 515, 558 and 559 ås shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30n9. ADL 312809 consists of Tract C30-57 (SF-57), a portion of Blocks 516 and 560 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30n9. ADL 355001 consists of Tract 39-01, more particularly described as: T. 13 N.. R. 13 E.. Umiat Meridian. Alaska Section 17, Protracted, All, 640 acres; Section 18, Protracted, All, 631 acres; Section 19, Protracted, All, 633 acres; Section 20, Protracted, All, 640 acres; Section 25, Protracted, All, 640 acres; Section 26, Protracted, All, 640 acres; Section 27, Protracted, All, 640 acres; Section 28, Protracted, All, 640 acres; Section 29, Protracted, All, 640 acres. ~) () Exhibit 3 Description of Northstar Injection Area Federal Leases The Northstar Injection Area encompasses all lands within the following Federal oil and gas leases OCS-Y-1645, OCS-Y-0179 and OCS-Y-0181: OCS-Y-1645 consists of: That portion of Block 6510, OCS Official Protraction Diagram NR06-03, Beechey Point, approved February 1, 1996, shown as Federal 8(g) Area C on OCS Composite Block Diagram dated April 24, 1996. OCS-Y-0179 consists of: That area of Block 470 lying east of the line marking the western boundary of Parcel "1", and between the two lines bisecting Block 470, identified as Parcel "1", containing approximately 94.30 hectares, and Parcel "2", containing approximately 15.27 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29/75; and That area lying between the two lines bisecting Block 471, containing approximately 611.95 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29/75; and That area lying northeasterly of the line bisecting Block 515, containing approximately 189.83 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29/75; OCS-Y-0181 consists of: That area lying northeasterly of the line bisecting Block 516, containing approximately 2076.98 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29/75; and That area lying northeasterly of the line bisecting Block 560, located in the northeast corner of Block 560, containing approximately 44.65 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 12/9/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved 4/29/75. ~) ~) Exhibit 4 Northstar Type Log - Seal A-01 Stratigraphy GR (API) .:.< III g> 52 c: .2 16 E ~ ;::::~:~:~;;: ~I LL;;~;,,:. ~ j5 ;:) .s::. (f) . .~.' V\ILNVYY'A~ ';i:¡~:,a' III ! z,~~ ro C/) .... CD .c E CD ~ >- co m CD o .s::. "C 2 a.. c: .2 16 E o LL .:.::: 'S: co ~ Echooka Fm. -. ~:;~{. Usburne ,~ Group , E o C3 C2 C1 B A2 A1 TVD *1'~:":~Ii~t~':i!,t ~J~";:I ;~~,",'fi~~~·I' .. ~ ....!,~~ --10650"'.:_:.:. :.:.: .._~.- '7'7'7':) e....._ ..... ~.'·I~.~.~:. ,V~II'~~ .....-.- ..... -'0700- ....... ..... ...... .... '; .~.~. ;_;_-.4 ~~.....~,.~;. .:.~.:.:.:. -'" ,~I:\,,,.,,~,,,,,l,',."" ""¡, 10750 _........_,. !!,~~":: !!....!.-~..r ::~-;::"I;: ~-=---==..<!: .,.~.~r,~,i ~ -'0800.2>. ' . ! . '. ¡~,,;,. '~'''',~ ..,..~.-~. ..-. --..- ~~:;-¥ ~~, 'M~~. .. .'~( -10900" ~' :',' ".,_, " '".,' ~ ~ .:.~ 'V "., ' .,! D~J, -'0950" .. .-et.~ ~H", . . ~ tl -'1000- ~toeIì.:eDoIð~ I' ".,.".,1.,,'. ~ t::t't&~ " , ~~'Y~~.I: ~~,'~~ m**~?ë1 ""11~~~<~ .. . .. .. .. e.. . .,:.~...~... ¡-·-4 \..,. ......, .~. ...;.. -. -;...... .~ ....... .., 1100- . . . . . . ......... ....... ...... ....... ~."..C"I....'"^'.......'.....~"~ .. . .. .. . . .. . .. . ¡~~ ..., 1150- . . . . . . . .. .. . '-1125O·":t.-=-~ n.::n--r.:.. l'r~~~~ I I I I 11300 ..--:---...".~ ILM-DIL G;:~ Conglomerate ! { ~ 94 Mirrored Sonic 59 59 "',I.'."".~....··..'..·.'..'.' :"'. ,.:, ~ : ': .,:':::' ',' ""';"" "~',' i.: . ' ..~"., , , , " ~. 1'1' ,', ~"""I""- ':';,",",',,I\'¡:, ,/1''': .....:.,':~,.,...,.',..'.',".'....'.', ....:.,.,....:, ,.·...,.'1.·.,".'.":.'·,1",., . , ~;'::t:·i.:':" "':'I',','"....·~ ~,> ~':"""7§"'" ".": ' ,," ,',I '" '., ,\: :::::.,.. , ';< ';'''ï : ,', ' :' , "~ ' . :'.' . '::;,:,t,.. . ',"". ":.'" ]"",:", .." :,'.,......,...., I " ~ ,: ' I 94 Shales and silts. Transgressive Marine Sands, slits and shales, Low permeability Marine slits and shales, . Phosphatic limestones. Limestones, silts and shales. ..~~t,.,~.~ .~ Mixed gravel/sand & moo cong Massive, pebble I cobble dense congo Medium conglomerate and variably pebbly Medium conglomerate and variably pebbly Medium conglomerate and variably pebbly F-m sand w/occ. pebbles Fine to medium sands. Very fine to fine sands. Prodelta shales. Sand, silt and shale. ~---vTn'V\I'\~ Carbonates ~) ~) Exhibit 13 Chemical Composition of Seal #1 Formation Water Sample Component Concentration (mg/l) Ca 575 Mg 12 Na 7540 Fe 115 Sa 1 CI 11800 HC03 1425 sol 130 K 45 Sr 20 Total dissolved solids (TDS) 20804 Measured Resistivity 0.36 @ 68 deg F Resistivity 0.10 @ 245 deg F Source of sample: Produced water from Seal #1 II ~-, I§I ¡~¡ CLASS DISPOSAL WELL ~iJ~ DRlMO AND INJECT FACILITY r-'-", '-, \ '-. I /._~:. 3" 8" J- 5 mbd ,-- ~:-.......- --------- 3DOO pll ~, .~ \ i WELL CLEAN .1 ,._____.1 L UP TANK ----.::. I 3D mbd 2950 plI =r=+r~ ~.. L~ i:-~<' ~~-- SEWAGE! f :---, L TREATMENT I Dlsharge to sea OIL GAS WATER NGLs DRAINSlSLOPS GLYCOL IMPORT GAS ..........------------ I WATER ! SURGE TANK TEMPEllATURE F PRESSURE poIQ ( , I \. SLOP OIL WATER . '\..-_ SKIMMER ---,1 : : -=:>_.' 16 OIL PRODUCERS ~ ~:cõö~~J""""ï 1-- =~--", _L ( IOL SURDE \ " -, H'.1 ~- TAlK .I IfGL REFWX I __ ~MULAfR J iil k __,'_ ~ T r ; t) L..... ! [~~- :-r/1 REBOILER 1 \ _ _ <--_J..I_ ..- f . ., i-___:, ~. L' ~:_:'.:_:-. ...-- . , '''·F . I _ '''·F~ ~ '07·F ~ ·(L1 ''''F)l'''~ ~P~TOJ LDEPflAToRl ~¿EP~TOR· j _ (_~EPi~TÓRW u. ëB.........-_.·.!. .:_ 1. 73SplI I fSpll ~ I 310ptl1-.... L- 55ptl ê:-· lit C- I I ',0-.;- r 5O"F 847 psi .. B5 I1bd PS1 ~ '- ;.':'> -; 5 GAS INJECTORS - INCOMING 100 rrrrscfd GAS PIPELINE 75"F 3D"F 800 IIIIIIICfd '21'4Ð'I ~_ .,--_ šiõI 1. LI~ ~~ '::I uu~_ U. (" <=><=> U. H. ( . . ') "51 ,I " Q I I f3 ~LII II: I II) 'wa: po ~-, I~w I ~ ~__< !caw I ~h i ; !III: I i ~- .Ih ¡ ;~II I i STADE I ¡~=! ! STADE! !en&!. - -¡¡~ I~ 5 ! --12- ¡:5 Cot ' 3Q"F : It) en ! ¡-"en ¡ r-- --------- ~ ~ L .' ( NOL ' '----' .,~ ~ SEPARATOR )- ~I. 885 psi l__ _ r (,,) I ' ,I 'I --+ FUEL -GAS ïcom.£R1 :h :=:;;~1., ==== 100"F 8O"F ..J:.-.." j+- r~-;"i ~~ ~ 1'- 1. 40~ X -:L_mJ~L_~i! i! ¡lIIffi 13! ... ~ffi. ( \ (GLYCOL INLET ~ r-:3;il, ~ I r ~ ~ I a: I UCRUBBE_R J I sŸÀÒE! l'a 2i ~!!!J 'a 5 - . fi ~I 710 psI --¡:,... ë0- ~:~ - ~c~----L_·,-r . Y ~ ë5 i I OLYCOL INLET I Cot "1 FILTER/SEp· L ";( ~J I L) r----~ b 'CDOLER~ ~ I7"F 1'- 1. ~, ~~ wel: r;mJ mUl. . 1st . !III: &G. ,STABE S¡I UCot ,"":U):r I ! . ~ -,. Exhibit 20 Northstar Simplified Process Flow Diagram Northstar Facilities Seal Island General Layout Exhibit 21 I NORm, DRAINAGESUMP}."". -''','7.,." . ~." ~ -:-:s~~.~ ---GAs! ---. ". ',.",..".. ~';'^~;;~:;~¡;ftlj~~!¥X~~th~~;:;~;~\ COMPRESLESOR 1------ "";',~ ·,~)g¡''¡}~~~~¿i\t~'',*;~~'ìL~~~{1'~~~;Îi~~;~> ~ JDRILL RIG ~&~ t MODU! " ;.;;>~ti.-;:'". '~;!-:>.,(~\~·"··.,",;¡¡;~¡I.!.1,';~s~J.¡H!~'~5f;'~(J"''l"t''~'~~;'j!''{~"~\"i/.:.¿,;.,;¡I .~. ";\Y'~~.í..;U;(::¡',qi.,!'1'''- SERVJC~ " .~ r,¡.,,;'-'í.t~\', .-" . '!1'~ "'O"~ ~1' "'~. ...,. " ~ .~:;,..> '. ,." ¡'~"'. .., I ~~?~~.1.-:;t{~~~,,~~ r ! ~ __ . ..¡ .:~.., '"~j:~\"';.*,1'''f~".'';\';t¡Ò'~1T:r..~~;~~t-~~~~~.~.~~¡;,./., .~...:." ~ ~ . '-;~~44J'!I~;~ v. \ BUILDiNGS '¡ ,. <.-. "..-.., "'~. ",. >,... ..). . >."" ".',<' · 1 . . MLlWl·---···-··..-..··..··,., ~~"~,:: (;>:~.~~~~.~¡:~,.. " tl~ IPM"n ./ i~¿,:I:,~t;i;~{f.~ L __ .. I -"'. 'i'-0'!J,f~t¥. '~. ~/< _ ,:'¡-.\:..¡.{>,(.\ -.¡. >^. '~!? . · "" """"1;.1'" ' - ":{¡~~i,"'",-V", -.--' ~.._ _ ~~~10 :. lPROCESS "'~ ~ " .' \ "',~.i;;'n.! . '."--.--- , ~«:;:'~~ -, - :':""';";"1 .' MODULE · -------------- .," ;",..¡,,¡¡¡}!. ill .. , . '¡ ".1-".' . \ ' . ,. TFORM .l¡~&{----_.__._~ ;:; ,:i~[n{~,:: ~TORA,GE PexLAUNITS) 1.__.._. ~,:., '-"~è!(.,~,~..:..(,. ~ ~ '.. L,..."':;::"":':~S;'I'" (40 CONN r "", ..; """""'" l. ' 1,,:..,;..,.':-;':; . \ . .. -- \ ' "n"..,... .,.---. r.. .. .. '.. ._- ... '-, 't.i~; ----~-, - . r ;;~.@?!t.;. ~PUMP ·HOUS'E 1....___. ···;·,.i);¡¡--"~ l" Jo DISPOSAL: t .;</:,: ~:~\,:¿I . :J " '·It,,"";',,·,· -<""1\', LL, "". ..... '.' \ ---, ',... .",i~f~;;. WE ~'" '.\ _ .... ,~: .. ''''';'~'·tr.·'~ '-~-", ..---I '_I I','. I . :;;;i,P:.;;~{, L--.: -----------\ r---T~,'..._. ;:.\ DRII1- RI~& \ ' ',.'. ..,. ,. ~ r;., ,. - - - -1'·' , . SERVICt: ., ...."" .. I..:J~ · ,.- ,. :.. : ... U'LDIN"S ----:---- ,.1nj~~~;~:'.=_-~~-.- .~-\ \ \ ~'4~'/ I ~-~- [---.' ()USEISHOp1 \.,:""".".''''...._.... , , . '''_'~ WAREH -,---- '.."".f,:!"...::;,~ ' . ,_, ,_ ~~llj~~ODULE J----'--/·--,·:;¡!:~!!;;~:¡~;;i' ~ . L; -- --~ I L_ ... ....,c"..".".,... , \ ~~, "::\:"'l;~:·.···..: " -- ,.¡;,,<,~\.¡.\..., " /_.---<.,::;;;;;;, : ¡ I liVING. QUARTERS r- " I R.. _ ~ _ ....:..-.... [;: , - \{ -j) 11,.- - - ~ ,/ / ,/ ~ ,} /,. t ,i ,./ . /..i/I· \ /' I ---------" /~// ~ ' , , .1'/ . I I / :~ rsOIJT':I__'?~INAGE SUMP \.--. ______J \ &í I , , [:~~ÞJ€~""--"'--'-" í H EUPÀD1-,-------·----·,,,,·--..·" -'-"-' - ....., ..".jl J ~) ~) , · TREE: WELLHEAD: .. )NAL KB. ELEV = BF. ELEV = CB. ELEV = SSSV @2000' Exhibit - llimhole Producer 13 3/8". 68#/ft, L-80, BTC @ 4.5", 12.6#/ft, 13-Cr. Vam Ace TUBING ID: 3.958 " CAPACITY: .0152 BBUFT DATE 9-5/8" 47#/ft. L-80. BTC-M @ 4.5" X NIPPLE, @ 3.813" ID (OTIS) 4.5" X NIPPLE, @ , 3.813" ID (OTIS) 4.5" XN NIPPLE. @ 3.725" ID (OTIS) 4.5" WLEG, @ (OTIS) 7" 26#/ft, L-80. BTC-M @ PBTD @ TD@ REV. BY L<- ~ ~ .4 ~ .. 4.5" GLM 3.813" ID @ 3000' 6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 ~ Baker 83 PACKER ;,_ 3.875" ID @ B 4.5" LINER TOP @ 4.276" ID ~ I' .. i ~ COMMENTS 4.5". 12.6#. 13-Cr Vam Ace Northstar WEI I : API NO: BP Exploration (Alaska) ~ .. TREE: WEllHEAD: Exhibit #Åi9 Bore Producer 13 3/8", 68#/ft, l-80, BTC @ ~ 4.S", 12.6#/ft, 13-Cr, TUBING ID: " CAPACITY: BBUFT 4.S" X NIPPLE, @ "ID (OTIS) 4.S" X NIPPLE, @ · ~ "ID (OTIS) 4.S" XN NIPPLE, @ "ID (OTIS)- 4.S"WlEG, @ ~ "ID (OTIS) ... f" . ··)NAl KB. ElEV = BF. ElEV = CB. ElEV = SSSV @2000' .. 4.S" GLM ID @2200' 6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 t- ~~C¡;ER ~ 4.S" LINER TOP @ 9 S/8", 47#/ft L-80, BTC-M @ ... ~ PBTD @ TD@ i ~ DATE REV. BY COMMENTS .....------ .'-"'- .; 4.S", 12.6#, 13-Cr Northstar WFI I : API NO: BP Exploration (Alaska) ,", ~ TREE: WELLHEAD: EXhil J Big Bore Injector C-- -)INAL KB. ELEV = BF. ELEV = CB. ELEV = SSSV @2000' 7" HRQ SVLN 5.963" ID 13 3/8", 68#/ft, L-80, BTC @ ~ .. 6.8PPG DIESEL FREEZE PROTECTION AT +1- 2200 7", 29#/ft, L-80, TUBING ID: 6.184" CAPACITY: 0.037 BBUFT 7" R NIPPLE, @ 5.963" ID (OTIS) t 7" R NIPPLE, @ . ~ Baker SABL-3 PACKER, 5.963" ID (OTIS) 6.0"ID@ 7" RN NIPPLE, @ 5.5" ID (OTIS) 7" WLEG, @ , ! 7" LINER TOP (OTIS) - 6.188" ID @ 9 5/8", 53.S#/ft ... L-80, BTC-M @ PBTD @ TD@ j ~ 7",26#, L-80 DATE REV. BY COMMENTS Northstar .,WELJ.;.. API NO: ,- BP Exploration (Alaska) l.. " TREE: WELLHEAD: EXhibi~BlimhOle Injector 103/4", 45.5#/ft, L-80, BTC @ 5.5", 17#/ft, L-80, TUBING 10: " CAPACITY: BBLlFT DATE 5.5" X NIPPLE, @ "ID (OTIS) 5.5" X NIPPLE, @' "ID (OTIS) 5.5" XN NIPPLE, @ "ID (OTIS) . 5.5" WLEG, @ .. ID (OTIS)- 75/8", 29.7#/ft L-80, BTC-M @ PBTD @ TD@ REV. BY ..4 ~. J '8 ~ ~. ~ i ~ COMMENTS .... r ·")NAL KB. ELEV = BF. ELEV = CB. ELEV = SSSV @2000' ~ 6.8PPG DIESEL FREEZE PROTECTION AT +1- 2200 PACKER ID@ 5.5" LINER TOP @ 5.5", 17#, L-80 Northstar WJ:;.~~ API NO: BP Exploration (Alaska) l_ " TREE: WELLHEAD: ~ ,~re-Produced Big Bore EXhibit~· Injector (")NAL KB. ELEV = BF. ELEV = CB. ELEV = SSSV @2000' 7" HRQ SVLN 5.963" ID 13 3/8", 68#/ft, L-80, BTC @ .4 ~ 6.8PPG DIESEL FREEZE PROTECTION AT +1- 2200 T',29#/ft, 13Cr, TUBING ID: 6.184" CAPACITY: 0.037 BBUFT 7" R NIPPLE, @ 5.963" ID (OTIS) 7" R NIPPLE, @ · 5.963" ID (OTIS) 7" RN NIPPLE, @ 5.5" ID (OTIS)- 7" WLEG, @ "ID (OTIS)- J t- ~~<¡;ER B 7" LINER TOP @ 6.184" ID 9 5/8", 53.5#/ft L-80, BTC-M @ [' ... PBTD @ TD@ j ~ 7", 29#, 13Cr DATE REV. BY COMMENTS Northstar WFJ J : API NO: --.- -~- '._--,,'" BP Exploration (Alaska) L «) ~) Exhibit 28 Affidavit Of Krissell Crandall Regarding Notice To Surface Owners In The Vicinity Of The Proposed Injection Wells KRISSEll CRANDAll, on oath, deposes and says: 1. I am employed as a Senior Landman by BP Exploration (Alaska) Inc. BP Exploration (Alaska) Inc. is the Operator of the Northstar Unit, and the applicant for the Northstar Area Injection Order. 2. On Jun~ 2001, I caused copies of the confidential version of the application for the Northstar Pool Rules and Area Injection Order to be hand-delivered to the following persons who represent surtace owners and operators within one-quarter mile of the area affected by the proposed Northstar Area Injection Order: Pat Pourchot, Commissioner Department of Natural Resources State of Alaska 550 W. 7th Avenue, Suite 800 Anchorage, AK 99501 Mark Meyers, Director Division of Oil & Gas Department of Natural Resources State of Alaska 550 W. ¡th Avenue, Suite 800 Anchorage, AK 99501 Jeff Walker Regional Supervisor, Field Operations Minerals Management Service 949 East 36th Avenue, Room 308 Anchorage, AK 99508-4363 3. On Jun~ 2001, I caused a copy of the confidential version of the application for the Northstar Pool Rules and Area Injection Order to be mailed first class to: E. P. Zseleczky, land Manager BP Exploration (Alaska) Inc. 900 E. Benson Blvd. Anchorage, AK 99508 Buford Bates Murphy Exploration (Alaska) Inc. 550 Westlake Park Blvd., Suite 1000 Houston, TX 77079 Affidavit of K. Crandall Page 1 l. , " .) .) 4. On June;7q 2001, I caused a copy of the public version of the application for the Northstar Pool Rules and Area Injection Order to be mailed first class to: John Jay Darrah, Jr. Jim Ruud, Land Manager Managing Partner Phillips Alaska, Inc. AVCG LLC P.O. Box 100360 225 N. Market, Suite 300 Anchorage, AK 99510-0360 Wichita, KS 67202 . 5. The attached map shows the record ownership of leases in and adjacent to the Northstar Unit. AVCG LLC has purchased Phillips Alaska, Inc.'s interest in ADLs 377051, 385198 and 385202, and ExxonMobil's interest in ADL 377051. Assignments have been submitted to the State of Alaska, Department of Natural Resources, Division of Oil & Gas for approval. ~~ Kris5ell Crandall STATE OF ALASKA ) ) 55. THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this d-6 ~~\\\\\\\UIINIIII!üI ..~ ~ J. I ~q~ ~~~......"....~...6 ~ ~ .. ~".' T.t\ ~ §!§ ...00\ ~·.\J~o~ ~ ..~. .. ~ ::::: : A. 7:0'" ~ ';to ::: -- . J.~~ i;& h . - =-t'~ P1J'h~Yj = ~ ~. vdL....C: jf§ ~~.. ..c-.. :('.. M §§ ~ .AI' ... ~ ~ ... .,..~ ~ ~ l' ~..;.~~~;..~'" ~ ~ OF A\.~<:) ~ 'l/¡¡¡III ",mn\"'~~ My Commission Expires: :2 /t. ¡OJ' Affidavit of K. Crandall Page 2 r Exhibit 28 'lit -' 1 :250,000 25,000 50,000 Feet I I I I 6,000 12,000 Meters AlBERS EQUAL ARENNAD27 1r4 ~EA - LEASE STATUS EFFECTIVE MARCH 31, 2001 B/14~··~ UPOb ~(?S./iþ¡ '\I. ", r . ) ) United States Department ofthetterior Øß~/af MINERALS MANAGEMENT SERVICE Alaska Outer Continental Shelf Region 949 East 36th A venue, Suite 308 Anchorage, Alaska 99508-4363 Mr. Bill Turnbull BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, Alaska 99519-6612 I 5 APR 2001 Dear Mr. Turnbull: . This letter is in response to your draft "Northstar Pool Rules And Area Injection Order Application" (Application) submitted on December 18, 2000, and the revision dated January 8, 2001. We provide the following comments for your consideration after reviewing this document. Our comments are divided into two groups based on our perceived significance of the comment. The first group are the comments that we believe highlight significant enough problems that we would be unwilling to approve the Application without further explanation in these areas. For lack of a better term, we have labeled these "Critical Comments". The second category is labeled "General Comments" and contains questions that are not significant enough to alter our decision. However, additional information in these areas would aid our review of the Application while providing additional information for our reservoir management oversight responsibilities. When page numbers are referenced, they refer to the January 8th revision. Critical Comments: 1. The pool rules should be expanded to indicate where there are differences between the Minerals Management Service (MMS) and Alaska Oil and Gas Conservation Commission (AOGCC) regulations, particularly for the drilling and reservoir management regulations, and propose a solution to these differences. The MMS would be happy to meet with BPXA and the AOGCC to do a comparison of our regulations and workout compromises. This work could establish the basis for an agreement between the MMS and AOGCC for joint management of activities on joint Federal/State units. 2. At this time we disagree with the definition for the Northstar Pool proposed by the AOGCC in their comments of January 9, 2001. We do not believe that it has been sufficiently proved that the Sag River and Shublik fonnations are in pressure and fluid communication with the Ivishak fonnation. Before you submit a final application we think BPXA, the MMS, and the AOGCC should meet to further discuss the pool definition. 3. We disagree with your proposed classification of the Northstar Pool as a nonsensitive , reservoir. The MMS regulation 30 CFR 250.110 1 (d) requires that all oil reservoirs with an associated gas cap shall initially be classified as a sensitive reservoir. On page 9 of the Application under the "Hydrocarbons in Place" section, you indicate that the Northstar Pool contains an inferred gas cap of approximately 7 BCF. Therefore, the Northstar Pool must " '. e) .) 2 r Mr. Bill Turnbull BP Exploration (Alaska) Inc. initially be classified as sensitive. The information that you provide in the Application indicates that the reservoir can produce at 90,000 barrels of oil per day, or possibly more, without affecting ultimate recovery. Since the Northstar facility's capacity is only 65,000 barrels of oil per day, the definition of sensitive reservoir in our regulations can be interpreted to mean that the Northstar Pool is a nonsensitive reservoir. However, you f provide further information in·the Application that indicates that reservoir pressure can not J drop more than 200 psi from the initial pressure without significantly affecting ultimate recovery. Therefore, the conclusion that the Northstar Pool is not sensitive to production rate is conditional and based on being able to maintain reservoir pressure through the injection first of miscible injectant and later of dry gas. Our conclusion is that the reservoir is sensitive to the rate of reservoir voidage replacement, therefore we consider the reservoir to be a sensitive reservoir and require the submission of Form MMS-127 Request for Reservoir Maximum Efficient Rate (MER) for the Northstar Pool. 4. The method for requesting a reservoir classification and a MER is to submit Form MMS- / 127 with the appropriate supporting information. Therefore, these requests should be removed from the Application and submitted on the proper form. This form can reference the Application so that much of the supporting information does not have to be duplicated for the two submissions. 5. We can not agree to the portion of proposed pool rule 3 that deals with the distance between open completions and the external unit boundaries. The MMS requires a minimum of500 V feet of separation between an open completion and a lease/unit boundary (30 CFR 250.1101 (b», We believe that exceptions to this rule should be looked at on a case-by-case basis and will not approve the blanket waiver requested by the proposed rule'7P ¿~&f~; ~rC} $'00 ,~ 6. We have concerns with part c of proposed pool rule 5. It has been our experience that attempting to detennine reservoir pressure by extrapolation from a surface pressure reading can be inaccurate. Since maintaining reservoir pressure within 200 psi of the original reservoir pressure is very important to achieving ultimate recovery, we feel uncomfortable allowing this type of measurement to determine the shut-in reservoir pressure. In order to allow this type of measurement on a well, we will require additional information to prove that it is an acceptable method. We believe that the other methods mention,edpro~~~ y.J} .' ./~~ acceptable results and are therefore acceptable to us. ~ ~p wi 7A11.i;:. c:'J-r16A~,,}~. ~ "/ L r bA¡ ~ w E:J..~.::) .,. 7. We do not agree with part d of proposed pool rule 5. The MMS regulations require that bottomhole pressure survey (BHP) data be submitted within 60 days of the test.' For reservoir management oversight we believe it is important to receive the BHP data in a tim~ly manner. J~.p \N)LD)I\.pL~ # 8. We can not agree to the proposed pool rule 7. Since any of the activities listed have the possibility of affecting ultimate recovery from the reservoir, we will require that \york on Federal wells be performed !n ~c~2r~aI!ce with the provisions of30 'CF1t250 S'ubparts E añd F. The only activities that we will allow wÍìliolÙ:pr¡or" approval are the routine operations listed in 30 CFR 250.601. . . ) . ) Mr. Bill Turnbull BP Exploration (Alaska) Inc. 3 l" We can not agree to the proposed pool rule 8. Since the Northstar pool is a joint Federal/State unit, any waivers of the pool rules or amendments to them will require approval of both the AOGCC and the MMS. General Comments 1. On page 3 of the Application, you reference the use of slim-tube experiments to determine the minimum miscibility pressure. It is unclear whether this refers to tests that have already been completed, tests that will be done during production, or a combination of the two. Please provide clarification on this. Also, will experiments be conducted on samples from various wells in order to identify potential differences in fluid properties throughout the reservoir? - ONl..1 ) 't~7 "70 b" '1¿, t>...AN eN MIö P-..t:_... 2. Page 4 indicates that a structure map has been prepared for Northstar Pool at the top of the Ivishak formation. For other applications you have provided property maps that indicate that the upper portion of the pool includes some of the Shublik formation. Please clarify whether the structure map was prepared for the top of the Ivishak formation or for RJ'·· JO~t' somewhere within the Shublik formation. St1LJ ßl.--) t D· 1\JL;....u Œ..O } v IV J ~+A.L I ^J . ~:.Sèf:.I-, - t:/ óf'- ~Ð·· o~.J).-\l I N A. ..¡;~ of:" 7'H"6, w'Ð-L5 .-:-MrV'l!'-I ¡'IIJ () . 3. Page 8 indicates that "a capillary pressure model was generated to determine saturation as a function of porosity and height of [sic] above the free water level." We have yet to receive any water saturation data for the Northstar Pool. Please provide us with either a copy of this model or the water saturation property models for the various zones in the reservoir so that we can include water saturation in our calculations of oil in place to use in our models. '?J..AtJ M'1~ ï'ø' i)JÓL-Vb6 w/~6N ~I~~..$ .. 4. Page 9 indicates that several feet of gas were present in the Shublik D zone in the Northstar- 1 well, which caused an elevated gas oil ratio when the well was tested. For the test, the upper 30 feet of the well was perforated. It is unclear whether this 30 feet included the ,Shublik D, or was the upper 30 feet if the Ivishak and the gas migrated from the Shublik to the Ivishak. Since this issue could affect the definition of the pool, it would be appropriate to have additional clarification on this. ,j1~O\)H:.Jùßo1t~~.- 5. Please indicate what percentage of the total reservoir volume the inferred gas cap occupies. 6. Þa;;oiÛ'indicates that a "J Function" equation was used to predict the initial water saturation versus height in the reservoir. Is this the same as the capillary pressure model that was discussed on page 8 of this document? If not, please explain why you used the different methods to determine water saturation. NI P J.,A t,j 1JI'y'6/Õ Ù ) ~(Y6 <S w) J; 6t:.:..JJ C} t.:., S 7. When do you expect to complete work on the mechanistic finer grid 3-D partial field models, referenced on page 10, that will be used to validate the full field model? ßASl:::O c/'.J G£ð 1- . 'NO'P-I? IN Pt-Obt2...t:-S~- ~")~I"-!ú DYNA"IlI(., R-~. MOf:jt.'1- Nt.:j.-f 3 Nì(}~, - DA-rA .),vLo/v11I'JG 8. Did you consider any combination development scenarios when you were determining the "- optimal production method? For example, did you consider a combination waterflood and miscible gas injection development scenario? If you did consider any combination development scenarios or other development scenarios that were not listed in the Application, please provide the results for these scenarios. 6~~ 1-_DO~~ Ö ID (\)07 ~-'" (yQ...ÇJ.....&:...^J1J-~ µO'tL ¡N6 A\. vJ~ G ~\Y-\ 6_~..__~~..~.,Y~'?~9_- Vt..~.~ H)6 Ii Rt(EQVt~Y ~-:ï\ct<:J ~..~" ~, rJ\ V l---A}1 0 r-J f<-v tV ~ , IV (J.·U 0 t.D J Aj A f:.v.-: t.) LJ.\ '7 f 0 Ai v . '\ , I Mr. Bill Turnbull BP Exploration (Alaska) Inc. . ) 9. Your analysis indicates that regardless of the oil production rate scenario, the reason for coming off plateau was that the produced water handling capacity was reached. Did you perfonn any model runs with an increased produced water handling capacity? If so, did this have a significant effect on the ultimate oil recovery? y t:,s - Thank you for considering our comments when you revise the Application. If you havè any questions concerning our comments please contact Mr. David Roby at (907) 271-6557 to . discuss them. We look forward to working with you and the AOGCC in developing the pool rules for the Northstar Pool. Sincerely, 4 b\~r~~ Regional Supervisor Field Operations cc: ~r~ Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 1000 Anchorage, Alaska 99501 IT/2C/2/I//2l .. . lip/? 2 'l 'ON .', ¿DO! & Gas Cons ~. ~iSsion . [Fwd: Re:iSed Dra~ of Area Injection Order / P021e:') . . ~) ~) Subject: [Fwd: Revised Draft of Area Injection Order / Pool Rules] Date: Tue, 09 Jan 2001 07:56:59 -0900 From: Robert Crandall <Bob_Crandall@admin.state.ak.us> Organization: DOA-AOGCC To: "Davies, Steve" <steve_davies@admin.state.ak.us>, "Hartz, John" <jack_hartz@admin.state.ak.us>, "Mahan, Wendy" <wendy _ mahan@admin.state.ak.us>, "Maunder, Thomas" <tom _ maunder@admin.state.ak. us>, "Oechsli- Taylor, Camille" <cammy _ oechsli@admin.state.ak.us>, "Seamount, Dan" <dan _ seamount@admin.state.ak.us>, "Heusser, Julie" <julie _ heusser@admin.state.ak.us> Subject: Revised Draft of Area Injection Order / Pool Rules Date: Tue, 9 Jan 2001 00:28:50 -0000 From: "Crandall, Krissell" <CrandaK@BP .com> To: "Robert Crandall (E-mail)..<bob_crandall@admin.state.ak.us>. "Kyle Monklein (E-mail)" <kyle.monkelien@mms.gov>, "Douglas Chromanski (E-mail)" <douglas.chromanski@mms.gov> CC: "Turnbull, Bill F" <turnbuwf@BP.com>, "Reeves, T Brent" <ReevesTB@BP.com>, "Armstrong, Tom L" <ArmstrTL@BP . com> «North star Pool Rules and AIO Application (MMS AOGCC DRAFT).doc» This is a revised draft of the Area Injection Order and Pool Rules Application which includes references to MMS's regulations. The new material is highlighted, and is found in the Introduction, Sections 5, 7, 8 and 9. This draft is intended to facilitate our working meeting tomorrow afternoon. I'll have maps and an exhibit describing the larger area available at the meeting. Krissell Crandall Sr. Landman BP Exploration (Alaska) Inc. 900 E. Benson Blvd., Anchorage, AK 99508 P.O. Box 196612, Anchorage, AK 99519-6612 (907) 564-4535 (direct) (907) 564-5132 (facsimile) 10f2 1/9/01 8:09 AM Fwd: Revised Draft of Area Injection Order / Poo~es 1 .. ."' . ) L! ¡ IN olihstar Pool Rules and AIO Application (MMS AOGCC DRAFT).doc 20f2 Name: Northstar Pool R and AlO Applic (MMS AOGCC DRAFT).doc Type: Microsoft Word Document ( application/ms Encodï.!,:g~ .~~~~~~.,.v.. 1/9/01 8:09 AM