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CO 458
Conservation Order Cover Page XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning, and identifies certain actions that have been taken. Please insUre that it retains it's current location in this file. ,Z_._._~y_ Conservation Order Category Identifier Organizing RESCAN_....~ DIGITAL DATA OVERSIZED (Scannable with large plotter/scanner) V Color items: [] Diskettes, No. [] Maps: [3 Grayscale items: [] Other, No/Type [] Other items [] Poor Quality Originals: OVERSIZED (Not suitable for [3 Other: plotter/scanner, may work with 'log' scanner) [] Logs of various kinds [] Other NOTES: BY: ~MARIA Scanning Preparation Production Scanning Stage 1 PAGE COUNT FROM SCANNED DOCUMENT: ~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: ,~ YES NO Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES NO General Notes or Comments about this Document: 5/21/03 Conse~OrdCwPg.wpd 0 0 INDEX CONSERVATION ORDER NO. 458 NORTHSTAR OIL POOL 1) June 25, 2001 BP's Northstar Application fir Area Injection Order and Pool Rule 2) 3) 4) 5) 6) 7) 8) July 2, 2001 Notice of Hearing, Publication, affidavit from newspaper, copy of bulk mailing list and certificates of service July 31, 2001 BP's request for Approval of Gas Injection, Enhanced Oil Recovery and Application for Maximum Efficient Rate (form MMS-127) in Confidential Room August 13, 2001 Public Version of Northstar Pool Rules and Area Injection Order (public version replaced Confidential Versions submitted on 6/25/01 and 8/3/01) Confidential versions were withdrawn by the Operator at 8/16/01 hearing and therefore shredded by AOGCC. August 16, 2001 Sign in Sheet for Hearing and Confidential Maps located in Confidential Room ---------------------- Conservation Order 458 Various emails and copy of bulk mailing February 7, 2005 BPXA request for Modifications to Northstar Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP ) Conservation Order No. 458 EXPLORATION (ALASKA) INC. ) for an order to establish pool rules for ) Northstar Field development of the Northstar Oil ) Northstar OilPool Pool, Northstar Field, Beaufort Sea, ) Alaska October 9, 2001 IT APPEARING THAT: 1. By letter and application dated June 25, 2001, BP Exploration '(Alaska) Inc. ("BPXA") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") defining a Northstar Pool encompassing acreage within the Northstar Unit, Beaufort Sea, Alaska and prescribing rules governing the development and operation of the pool. 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 injection of fluids for enhanced recovery from the proposed pool. FINDINGS: 1. The proposed Northstar Oil Pool ("NOP") is an 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-01 well. 2. The NOP encompasses all or portions of State of Alaska and Federal OCS lands within the expanded Northstar Unit, as approved b.y the Alaska Department of Natural Resources, Division of Oil and Gas, on July 13, 2001 and bY the Regional Supervisor for Field Operations of the United States Mineral Management Service, on July 24, 2001, and as shown on Exhibits 2 and 3 included in the August 13, 2001 BPXA document titled "Application to AOGCC For Approval Of Pool Rules And Area Injection Order, Public Information Copy." Conservation Order No.i-,',%o October 9, 2001 Page 2 3. BPXA is the designated operator of the Northstar Unit. BPXA and Murphy Exploration, Inc. are working interest owners in the Northstar Unit. The State of Alaska and the United States are the landowners. 4. Shell Western E&P Inc. and Amerada Hess Corporation drilled six exploratory wells into the Northstar Unit. Well and 3-D seismic data have been used by BPXA to characterize the hydrocarbon accumulation within the NOP. 5. The reservoir interval of the NOP consists of the Sag River, Shublik, and Ivishak Formations. 6. The Sag River Formation in the NOP was deposited as Triassic-aged transgressive marine sandstone, siltstone and shale. The sandstone mineralogy is mature, composed of quartz with minor amounts of feldspar and authigenic clay. The primary cementing agents are calcite, silica and siderite. The Sag River Formation is typically 100 feet thick within the NOP. 7. The Shublik Formation in the NOP is Triassic in age, and is stratigraphically complex, characterized by marine siltstone, shale, sandstone and phosphatic limestone. Shublik Formation reservoir intervals are limited to a basal sandstone member, the Shublik D. The Shublik D was included with the unconformably underlying Ivishak Formation in the Operator's reservoir simulation and volumetric analysis. 8. The Ivishak Formation comprises a series of Permian and Triassic-aged delta-front sandstones and shales that grade upward to fluvial sandstone and medium to coarse- grained pebbly conglomerates. Within the NOP, the Ivishak is about 325 feet thick, and it is more proximal, coarser grained, more deeply buried and cemented than at the ?rudhoe Bay Field. The Formation is primarily cemented with calcite, silica and siderite. 9. The Ivishak Formation is informally subdivided into a lower sand. unit and an upper conglomeratic unit. 10. The upper conglomeratic unit consists of chert and quartz clasts with minor amounts of silt and quartz grains as matrix. Micro-porous chert grains occur in varying amounts as part of the rock framework. It is approximately 225 feet thick within the NOP. 11. The lower sand unit consists of medium to coarse-grained sandstone with minor siltstone and shale. It is approximately 100 feet thick within the NOP, and is present below the oil-water contact ("OWC") throughout most of the area. 12. The NOP structure consists of a faulted, anticline defined by three-way dip closure on west, south and east. Closure to the north is obtained through fault seal or structural dip. 13. Faults within the NOP have interpreted maximum vertical displacements of less than 200 feet, and they are not expected to significantly effect reservoir performance. Pressure buildup analyses and pressure data collected to date have not shown any evidence of production barriers. Conservation Order No. 2,.,o October 9, 2001 Page 3 20. 21. 22. 23. 24. 14. The NOP is confined below by the Kavik Formation, which consists of a 100-foot thick sequence of impermeable, Permian-aged marine shale that is continuous throughout the area. The pool is confined above by approximately 1,000 feet of impermeable, Jurassic-aged marine shale and siltstone assigned to the Kingak Formation. 15. Petrophysical log and conventional core data from the Seal A-01, Seal A-02A, Seal A-03, Seal A-04 and Northstar #1 wells have been used to determine reservoir properties for the NOP. 16. Based on limited core data, porosity for the Sag River Formation averages 13%, and ranges from 6.8% to 22.8%. Core plug permeability averages 0.86 millidarcies ("md"), and ranges from 0.01 to 28.0 md. Porosity values calculated from density well logs average 16% to 18% for the 10 to 30-foot thick section that is considered to be reservoir quality. Permeability for this section is estimated to be 1 to 4 md based on core porosity-permeability relationships. Water saturation values calculated from well logs range from 50% to 65%. 17. The Shublik D unit porosity and permeability are typically less than 10% and 1 md, respectively. However, thin (less than 3 inches thick), discontinuous intervals within this unit yield porosity measurements up to 16.3% and permeability measurements up to 100 md. The cumulative thickness of these thin intervals is typically less than two feet. 18. Porosity and permeability measurements for the Ivishak Formation are based upon extensive routine analysis of core from four wells, with additional data at in-situ confining pressures from two wells. 19. The lower sand unit of the Ivishak Formation has an average porosity of about 18%, and the overlying conglomerate unit averages approximately 14%. Average stress- corrected core porosity above the OWC is 15%. Laboratory studies have determined that about 40% of the total porosity within the lower sand unit is non-effective micro-porosity, and within the conglomeratic unit, about 50% of the total porosity is micro-porosity. Ivishak Formation core permeability ranges from 0.01 to 808 md, with a stress- corrected mean value of 53 md. Pressure and production data indicates a kV/kH ratio of about 1. Permeability derived from Ivishak Formation drill stem tests is higher than the average permeability derived from core analysis. The net-to-gross ratio for the Sag River Formation varies from 15% to 20%, assuming porosity and permeability cutoff values of 16% and 1 md. The net-to-gross ratio of the Shublik D unit is about 50%. The Ivishak Formation net-to-gross ratio is 93% to 95%, based on cutoff values of 50% shale volume and 10% porosity for sandstone layers, and an 8% porosity cutoff for conglomerates. The average oil saturation of the Ivishak is 42% at the volumetric centroid of the reservoir, and the maximum oil column is estimated to range from 270 to 300 feet. Conservation Order No. October 9, 2001 Page 4 25. 26. 27. 28. 29. 30. 31. The NOP OWC is 11,100 feet TVDss, based on core, RFT, MDT and well test data. Original oil and gas in place within the Sag River Formation were estimated by the Operator to be 37.7 million barrels and 52.1 billion cubic feet ("BCF"). There are currently no well tests in the Sag River Formation within the NOP. Well test and core fluorescence data in Northstar #1 Well suggest the Shublik Formation may be gas bearing at that location. 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. The Operator constructed a three dimensional ("3-D"), compositional, full field ("FFM") and fine grid mechanistic models to evaluate the performance of the NOP. The models utilized a 10 or 15 component equation of state ("EOS"). The 3-D compositional FFM covers the entire Ivishak reservoir plus the Shublik D sandstone and the surrounding aquifer. The Sag River Formation was not included in the reservoir simulation. One slim tube experiment was 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. Data for the initial exploratory wells was used to control the currently available reservoir simulations. Additional slim tube experiments and a revised geological model are being used to update the FFM to include results from recent wells. 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 Conservation Order No. October 9, 2001 Page 5 32. 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 injection 33. 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. 34. The project will inject up to 60% hydrocarbon pore volume of miscible enriched 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. 35. 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. 36. 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. Vertical barriers to water coning in the NOP will be evaluated with reservoir pressure data obtained after field startup. 37. 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 Ivishak reservoirs. 38. PVT analysis on recombined surface samples from Seal A-01, Seal A-02A, Seal A-03 and the Northstar #1 wells indicates a slight oil compositional gradient with depth. The ranges of fluid properties at initial reservoir conditions are listed below. Near Water-Oil Near Gas-Oil Fluid Property Contact Contact Oil API Gravity (Degrees API) 43 45 Solution GOR (SCF/STB) 1900 2400 Oil Formation Volume Factor (RB/STF) 2.1 2.3 Oil Density at Bubble Point Pressure (gm/cc) 0.54 .51 Oil Viscosity (cp) 0.15 0.13 Gas Viscosity Estimated (cp) 0.06 0.07 Water Viscosity Estimated (cp) 0.25 0.26 Conservation Order No. October 9, 2001 Page 6 39. 40. 41. 42. 43. 44. 45. 46'. Analysis of the bubble point pressure versus depth from the Seal A-01 well indicates oil column is slightly under saturated. Bubble point pressures from the PVT data range from 4936 pounds per square inch, gauge ("psig") at 11068 feet TVDss in Seal A-02 to 5216 psig at 10864 feet TVDss in Seal A-01. PVT data were used to generate both 10 and 15 component equations of state ("EOS") used in the reservoir simulation studies. One slim tube experiment run with oil from the Northstar #1 achieved 98.7% recovery efficiency with 1.2 pore volumes of injected gas. The EOS was verified by history matching the slim tube results. Newer PVT quality oil samples taken in May 2001 will be used in studies to determine bubble point pressures and compositions, and for additional slim tube experiments. Slim tube simulations indicate the oil compositional gradient has a negligible impact on minimum miscibility pressure ("MMP"). 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 +/- 50psi of the current pressure level, 5180 psi at 11,100 feet TVDss. 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. The Operator has acknowledged that the 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. The current development plan envisions that late in field life (approximately 16 years after field start up), reservoir pressure will be reduced to maximize recovery of the injected gas. Gas recovery volumes from blow down have not as yet been estimated. Initial development is limited to wells with bottom hole locations at distances no more than approximately 17,500 feet from the production island. Approximately 7 to 8 million barrels of oil will remain in the northwest portion of the reservoir at the end of field life if no further development drilling is done after the initial 22 well drilling program. Conservation Order No. 4.,6 October 9, 2001 Page 7 47. 48. Ways to access resources in the northwest area require evaluation of drilling operations and technological capability to reach beyond 17,500 feet. The hydrocarbon resources in the northwest portion of the reservoir will remain essentially untouched by the initial development program as a consequence of maintaining the reservoir pressure close to original (current) pressure. Average oil off take rates of 65, 72, and 90 thousand stock tank barrels per day ("MSTB/D") were evaluated in the FFM. The evaluation indicated that the NOP recovery is not highly sensitive to off take rate. 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. Total Produced Produced Injected Liquid Water Gas 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 49. 50. 51. 52. 53. 54. 55. The production facility will be capable of handling 65,000 barrels oil, 30,000 barrels of produced water, and 600 MMSCF of total injected gas on a daily basis. 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. Production will be allocated to producing wells based on monthly individual well tests and actual plant oil sales volume. The NOP will be accessed by wells directionally drilled from Seal island. 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. A diverter system compliant with 20 AAC 25.035(c) and 30 CFR 250.409 will be assembled during surface hole drilling operations for the first five development wells. The operator plans to apply for a waiver from the diverter requirements when enough data has been gathered to support the application. 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). Conservation Order No. '4~( a October 9, 2001 Page 8 a) 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). b) 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. c) Production wells will have two intermediate hole sections. The first will be drilled to top set casing at the Miluveach Formation at approximately 9264 feet TVDss; the second drilled to top set casing or production liner at the Sag River Formation at approximately 10,645 feet TVDss. d) 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. 56. The Operator has requested the pool rules authorize the following altemative completions: horizontal or "high angle" completions with slotted or perforated liners; open hole, slotted liner and pre-perforated liner or a combination of each; multi- lateral completions in which more than one reservoir penetration is completed from a single well. 57. All Northstar 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. 58. BPXA requested that a complete electrical or complete radioactivity log be required from below the structural casing to TD for only one well drilled from Seal Island. 59. Surveillance plans include initial static reservoir pressure to be measured in each new well prior to its long-term production or injection. Reservoir pressure will be recorded in at least half of the available active wells annually. Surface read out real time fiber optic temperature and pressure gauges are planned for the producing wells, which will provide additional static and dynamic pressure information. 60. Surveillance logs, such as flowmeters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir performance. CONCLUSIONS: 1. Pool rules are appropriate for the initial development of the NOP. 2. Development of the NOP will occur within the Northstar Unit. The NOP will be developed on acreage administered by the State of Alaska and the United States Minerals Management Service. Conservation Order No. 4.,o October 9, 2001 Page 9 3. The Ivishak Formation is expected to produce the bulk of reserves to be recovered from the NOP. 4. Minimum well spacing units of 40 acres will accommodate reservoir compartmentalization and therefore, promote ultimate recovery. 5. With the exception of the Class I disposal well, all Northstar wells must be equipped with a fail-safe automatic SSV and a fail-safe automatic surface-controlled SSSV. 6. Monitoring of reservoir performance by measurement of production and reservoir pressure using standard industry practices on a regular basis will help ensure proper management of the NOP. 7. Early implementation of an enhanced recovery operation involving miscible gas injection will preserve reservoir pressure (energy) and enhance ultimate recovery. 8. The planned enhanced oil recovery operation meets the criteria under 20 AAC 25.240(b) for waiving the gas-oil-ratio limitations under 20 AAC 25.240(a). 9. Production and reservoir surveillance, including the incorporation of additional information on rock and fluid properties from recently drilled wells, will allow the Operator to evaluate recovery processes, reservoir heterogeneity, reservoir performance and adjust the development plan as appropriate and will ensure proper management of the pool. NOW THEREFORE IT IS ORDERED: , 1. Pool Name, Definition, and Classification The Northsfar Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between measured depths of 12,418 feet and 13,044 feet the Seal A-01 well. The Northstar Oil Pool is classified as an oil pool. 2. The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded 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 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: Umiat Meridian STATE LEASES 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 ,i~' Conservation Order No. 4~o October 9, 2001 Page 10 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 N 1/2 S 1/2 (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 N1/2, N1/2 S1/2 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. 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 Conservation Order No. [.~o October 9, 2001 Page 11 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. FEDERAL LEASES Lease Number Description OCS-Y-1645 All Federal lands OCS-Y-0179 All Federal lands OCS-Y-0181 All Federal lands 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. Conservation Order No. 4~o October 9, 2001 Page 12 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 comer 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: Field Name The field overlying the Northstar Oil Pool is the Northstar Oil Field. Rule 2: Well 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 3: Drilling and Completion Practices Alternative completions will be authorized on a case by case basis so long as the requirements of 20 AAC 25.030(a) are met. Rule 4: Safety Valve System Equipment and Performance Testing Requirements a) With the exception of the Class I disposal well, each well must be equipped with a Commission approved fail-safe automatic SSV system capable of preventing an uncontrolled flow and fail-safe automatic surface controlled SSSV system capable Conservation Order No. k~o October 9, 2001 Page 13 b) c) of preventing an uncontrolled flow, unless another type of subsurface valve with that capability is approved by the Commission. The SSV and SSSV systems and the individual components of the SSV and SSSV systems must be maintained in proper working condition at all times unless the well is shut in and secured. Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the SSV system, SSSV system, and associated equipment are in proper working condition. At least 24 hours notice must be given prior to the performance of a test to allow a representative of the Commission to witness the test. Rule 5: Reservoir Pressure Management and Monitoring a) Prior to placing each well on regular production or injection, an initial pressure survey must be obtained. b) Bottom-hole pressure surveys must be acquired in at least one-half the active wells each year. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement. c) The reservoir pressure datum will be 11,100 feet TVDss. d) Pressure surveys may be stabilized static pressure measurements at bottom-hole or extrapolated from surface (single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests. e) Data and results from all relevant reservoir pressure surveys must be reported quarterly on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but must be available to the Commission upon request. f) Results and data from special reservoir pressure monitoring tests or surveys must also be submitted in accordance with paragraph (e) of this rule. Rule 6: Gas-Oil Ratio Exemption Wells producing from the Northstar Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240(b) are met. Rule 7: Annual Reservoir Performance Report The first operations and reservoir performance report will be due April 1, 2002 and annually thereafter. The report shall include, but is not limited to, the following: ,, Conservation Order No. 4.,o October 9, 2001 Page 14 a) Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation techniques. b) Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval. c) Summary and analysis of reservoir pressure surveys within the pool. d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. e) Review of pool production allocation factors and issues over the prior year. f) Future development plans. g) Review of Annual Plan of Operations and Development. Rule 8: Administrative Action Unless notice and public heating 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 tights, 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. Cammy O~hsli ;i'~ylor, ClfJair (~~1~~ Co mm is sion Dan~l T. SeamountI Jr., Commissioner Alaska Oil and Gas Conservation Commission · .AA., 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 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by 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., l0th day after the application for rehearing was filed). PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION P O BOX 2221 NEW YORK, NY 10163-2221 OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 TECHSYS CORP, BRANDY KERNS PO BOX8485 GATHERSBURG, MD 20898 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 DPC, DANIEL DONKEL 2121 NORTH BAYSHORE DR #616 MIAMI, FL 33137 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 AMOCO CORP 2002A, LIBRARY/INFO CTR P O BOX 87703 CHICAGO, IL 60680-0703 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 XTO ENERGY, 'SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73t02-5605 IOGCC, P O BOX 53127 OKLAHOMA CITY, OK 73152-3127 R E MCMILLEN CONSULT GEOL 2O2 E 16TH ST OWASSO, OK 74055-4905 OIL & GAS JOURNAL, LAURA BELL P O BOX 1260 TULSA, OK 74101 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 BAPI RAJU 335 PINYON LN COPPELL, TX 75019 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 DEGOLYER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 STANDARD AMERICAN OIL CO, AL GRIFFITH P O BOX 370 GRANBURY, TX 76048 XTO ENERGY, MARYJONES 810HOUSTONST STE2000 FORT WORTH, TX 76102-6298 SHELL WESTERN E&P INC, G.S. NADY P O BOX 576 HOUSTON, TX 77001-0574 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 MURPHY EXPLORATION & PRODUCTION CO., BOB SAWYER 550 WESTLAKE PARK BLVD STE 1000 HOUSTON, TX 77079 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 P O BOX 4813 HOUSTON, TX 77210 UNOCAL, REVENUE ACCOUNTING P O BOX 4531 HOUSTON, TX 77210-4531 EXXON EXPLORATION CO., T E ALFORD P O BOX 4778 HOUSTON, TX 77210-4778 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 P O BOX 4778 HOUSTON, TX 77210-4778 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLINGTON P O BOX 1635 HOUSTON, TX 77251 PETR INFO, DAVID PHILLIPS P O BOX 1702 HOUSTON, TX 77251-1702 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 WORLD OIL, DONNA WILLIAMS P O BOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN P O BOX 2967 HOUSTON, TX 77252-2967 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 P O BOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR P O BOX 2100 HOUSTON, TX 77252-9987 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 P O BOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert P O BOX 3128, Ste 3915 HOUSTON, TX 77253-3128 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 TEXACO INC, R Ewing Clemons P O BOX 430 BELLAIRE, TX 77402-0430 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 INTL OIL SCOUTS, MASON MAP SERV INC P O BOX 338 AUSTIN, TX 78767 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 GEORGE G VAUGHT JR P O BOX 13557 DENVER, CO 80201 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 C & R INDUSTRIES, INC.,, KURT SALTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC, RICHARD NEHRING P O BOX 1655 COLORADO SPRINGS, CO 1655 8O901- RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 MUNGER OIL INFOR SERV INC, P O BOX 45738 LOS ANGELES, CA 90045-0738 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 BABSON & SHEPPARD, JOHN F BERGQUIST P O BOX 8279 VIKING STN LONG BEACH, CA 90808-0279 ANTONIO MADRID P O BOX 94625 PASADENA, CA 91109 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 TEXACO INC, Portfolio Team Manager R W HILL P O BOX 5197x Bakersfield, CA 93388 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 ECONOMIC INSIGHT INC, SAM VAN VACTOR P O BOX 683 PORTLAND, OR 97207 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 715 1 ST #.4 ANCHORAGE, AK 99501 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD 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 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 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 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 GAFO, GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF REVENUE, OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 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 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 DEPT OF NATURAL RESOURCES, DIV OIL & GAS WILLIAM VAN DYKE 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 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR AND ENG SERVICE,, MIKE TORPY 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 ARLEN EHM GEOL CONSLTNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 UOA/ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR 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 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE, AK 99508~4302 GORDON J. SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH AV STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, LIBRARY 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MILLER 949 E 36TH AV STE 603 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 CIRI, LAND DEPT P O BOX 9333O ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 ANCHORAGE TIMES, BERT TARRANT P O BOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, JOANN GRUBER ATO 712 P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR ATO 1968 P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER P O BOX 10036 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON P O BOX 102278 ANCHORAGE, AK 99510-2278 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 P O BOX 196105 ANCHORAGE, AK 99510-6105 ALYESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ALYESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY P O BOX 149001 ANCHORAGE, AK 99514 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 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 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 DAVID CUSATO 600 W 76TH AV #508 ANCHORAGE, AK 99518 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900ARCTIC BLVD ANCHORAGE, AK 99518-2146 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL P O BOX 190754 ANCHORAGE, AK 99519 TESORO ALASKA COMPANY, PO BOX 196272 ANCHORAGE, AK 99519 JACK O HAKKILA P O BOX 190083 ANCHORAGE, AK 99519-0083 ENSTAR NATURAL GAS CO, PRESIDENT TONY IZZO P O BOX 190288 ANCHORAGE, AK 99519-0288 MARATHON OIL CO, LAND BROCK RIDDLE P O BOX 196168 ANCHORAGE, AK 99519-6168 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON P O BOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, P O BOX196247 ANCHORAGE, AK 99519-6247 UNOCAL, KEVIN TABLER P O BOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA)INC, INFO RESOURCE CTR MB 3-2 P O BOX 196612 ANCHORAGE, AK 99519-6612 EXXONMOBILPRODUCTION COMPANY, MARK PEVANS PO BOX196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, PETE ZSELECZKY LAND MGR P O BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, SUE MILLER P O BOX 196612 M/S LR2-3 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, MR. DAVIS, ESQ P O BOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM O VALLEE PRES PO BOX 243O86 ANCHORAGE, AK 99524-3086 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE ClR EAGLE RIVER, AK 99577 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 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER P O BOX 7728O5 EAGLE RIVER, AK 99577-2805 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 pHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P O DRAWER 66 KENAI, AK 99611 RON DOLCHOK P O BOX 83 KENAI, AK 99611 DOCUMENT SERVICE CO, JOHN PARKER P O BOX 1468 KENAI, AK 99611-1468 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN P O BOX 3029 KENAI, AK 99611-3029 NANCY LORD PO BOX 558 HOMER, AK 99623 PENNY VADLA P O BOX 467 NINILCHIK, AK 99639 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 JAMES GIBBS P O BOX 1597 SOLDOTNA, AK 99669 PACE, SHEILA DICKSON P O BOX 2018 SOLDOTNA, AK 99669 KENAI NATL WILDLIFE REFUGE, REFUGE MGR P O BOX 2139 SOLDOTNA, AK 99669-2139 ALYESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK P O BOX 300 MS/701 VALDEZ, AK 99686 VALDEZ PIONEER, P O BOX 367 VALDEZ, AK 99686 VALDEZ VANGUARD, EDITOR P O BOX 98 VALDEZ, AK 99686-0098 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 COOK AND HAUGEBERG, JAMES DIERINGER, JR. 119 NORTH CUSHMAN, STE 300 FAIRBANKS, AK 99701 RICK WAGNER P O BOX 60868 FAIRBANKS, AK 99706 FAIRBANKS DALLY NEWS-MINER, KATE RIPLEY P O BOX 70710 FAIRBANKS, AK 99707 C BURGLIN P O BOX 131 FAIRBANKS, AK 99707 FRED PRATT P O BOX 72981 FAIRBANKS, AK 99707-2981 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 K&K RECYCL INC, P O BOX 58055 FAIRBANKS, AK 99711 ASRC, BILL THOMAS P O BOX 129 BARROW, AK 99723 RICHARD FINEBERG P O BOX 416 ESTER, AK 99725 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL P O BOX 75588O FAIRBANKS, AK 99775-5880 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 FTWF-*l �im February 7, 2005 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 W. 7"' Ave #100 Anchorage, Alaska 99501-3539 RE: Modifications to Northstar Oil Pool. Dear Mr. Norman, BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 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 0il 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. Skillem Landman -Alaska cc: Bob Crandall Attachment: Modeling Results - Summary 0 ort Modeling Results - Summary Northstar Pressure Regimes 4.0 2.0 0.0 N E -2.0 -4.0 M -8.0 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. pThe positive effect of aquifer support was not modeled. #6 Turnbull, Bill F From: Sent: To: Subject: Turnbull, Bill F Tuesday, September 18, 2001 1:45 PM 'julie_heusser@admin.state.ak. us' RE: Northstar Pool Rules - clarification Julie, here is the original email as promised, anticipated start up mentioned in last para. Thank you, Bill Turnbull Subsurface Team Leader Alaska New Developments (AND) BP Exploration (Alaska) Inc. (907) 564-4662 work (907) 440-8310 cell RECEIVED SF.P 1 9 2001 ..... Original Message ..... From: Turnbull, Bill F Alaska Oil & Gas Cons. Commission Sent: Wednesday, September 12, 2001 10:11 AM Anchorage To: 'julie_heusser@admin.state.ak. us' Cc: 'bob_crandall@admin.state.ak. us'; 'jack_hartz@admin.state.ak. us'; Crandall, Krissell; Flones, Peter F Subject: Northstar Pool Rules - clarification Commissioner Heusser, We've just received the transcript of the Northstar Pool Rules hearing and noticed that we inadvertently answered one of your questions incorrectly. When you inquired of Pete Flones whether there would be any gas injection into the reservoir prior to start of oil production, he replied that there would not. In actuality it is our plan to commission the gas injection compressors and the gas injector prior to the start of oil production. This will involve displacing the completion fluid and establishing gas injection into the well and into the reservoir. This enables us to establish that when we do start the oil plant that we have a fully functioning system for handling the gas. In this manner we can reduce to a minimum the flaring that would otherwise accompany a new facility start up. The volumes of gas being injected prior to the oil plant start up would be small, with injection lasting a couple of days at most. In light of this clarification please could you advise if we need to do anything further to help facilitate your approval of the Pool Rules and Area Injection Order. Construction and commissioning activities on the island are progressing very well, and oil plant start up is now anticipated as early as October 11th. Would it be possible to let us know the approximate timeframe for issuing your decision? Thanks, Bill Turnbull Subsurface Team Leader Alaska New Developments (AND) BP Exploration (Alaska)Inc, (907) 564-4662 work (907) 440-8310 cell http://alaska.bpweb.bp.com/and/ [Fwd: Northstar Startup FLARE VOLUME Estin~ Subject: Date: From: Organization: To: CC: [Fwd: Northstar Startup FLARE VOLUME Estimates] Thu, 16 Aug 2001 16:05:31 -0800 Wendy Mahan <Wendy_Mahan@admin.state.ak.us> doa-aogcc Camille O Taylor <cammy_taylor~admin.state.ak.us>, Dan Seamount <dan_seamount@admin.state.ak.us>, Julie Heusser <julie heusser~admin.state.ak.us> Jane Williamson <Jane_Williamson@admin.state.ak.us>, Jody Colombie <jody_colombie~admin.state.ak.us>, John D Hartz <jack hartz@admin.state.ak.us>, Robert P Crandall <bob_crandall~admin.state.ak.us>, Stephen F Davies <steve_davies~admin. state.ak.us>, Thomas E Maunder <tom_maunder~admin.state.ak.us> Subject: Date: From: To: CC: Northstar Startup FLARE VOLUME Estimates Thu, 16 Aug 2001 18:50:58 -0500 "Armstrong, Tom L" <ArmstrTL@BP.com> "Wendy Mahan (E-mail)" <Wendy_Mahan~admin. state.ak.us>, "Dennis Hinnah' (E-mail 2)" <Dennis. Hinnah~mms.gov> "Tumbull, Bill F" <tumbuwf@BP.com>, "Dickey, Jeanne H" <DickeyJH~BP.com>, "Flones, Peter F" <FlonesPF~BP.com>, "Athans, Murray P" <AthansMP~BP.com>, "Summers, Steve M" <SummerSM~BP.com>, "Johns, Michael D" <JohnsMD@BP.com>, "Cusack, Louis A" <CusackLA~BP.com> Wendy / Dennis, We have a estimate of Northstar Startup Flare volumes. 1. Volumes estimated for Gas Pipeline / Gas Injection systems startup: 160 MMSCF 2. Volumes estimated for Processing Facility / Production / Oil Pipeline startup: 550 MMSCF This flaring is planned to occur during the time period estimated to be between Sept 10th and December 31st, 2001. The volumes listed above do not include Flare system purge and pilot gas If you need more detailed breakdown, please contact me via e-mail and we can go over our assumptions and startup plan. I will begin a two week work tour on the Slope starting August 21st, 2001. Tom L Armstrong Northstar Operations Manager 907-564-5802 - Anchorage Office 907-564-5200 - Anchorage Fax 907-373-6625 - Home 907-440-8016 - Cell armstrtl@bp.com - Internet From: Sent: To: ..... Original Message ..... Flones, Peter F Thursday, August 16, 2001 11:12 AM Armstrong, Tom L I of 2 8/16/01 4:42 PM [Fwd: Northstar Startup FLARE VOLUME Estin{ ~,, Cc: Turnbull, Bill F; Dickey, Jeanne H Subject: FLARE VOLUMES We advised the AOGCC commissioners that you would provide confirmation of volumes to Wendy Mayham by Monday,August 20th. Thanks -Please copy us on your e-mail to her. 2 of 2 8/16/01 4:42 PM ALASKA OIL AND GAS CONSERVATION COMMISSION Meeting Subject Date/Time NAME - AFFILIATION TELEPHONE (PLEASE PRINT) :2 ~/- ~ [Fwd: Revised Draft of Area Injection Order/PoolRules] 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_rnahan~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: "Tumbull, Bill F" <turnbuwf~BP.com>, "Reeves, T Brent" <ReevesTB~BP.com>, "Armstrong, Tom L" <ArmstrTL@BP.com> <<Northstar 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) 1 of 2 1/9/01 8:09 AM [Fwd: Revised Draft of Area Injection Order/Pool Rules] ,. ~Northstar Pool Rules and AIO Application (MMS AOGCC DRAFT).doc Name: Northstar Pool R and AIO Applic (MMS AOGCC DRAFT).doc Type: Microsoft Word Document (application/ms Encoding: base64 2 of 2 1/9/01 8:09 AM United States Department of the Interior MINERALS MANAGEMENT SERVICE Alaska Outer Continental Shelf Region 949 East 36th Avenue, Suite 308 Anchorage, Alaska 995084363 Mr. Bill Tumbull BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, Alaska 99519-6612 Dear Mr. Tumbull: 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: 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 formations are in pressure and fluid communication with the Ivishak formation. 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 250.1101 (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 Mr. Bill Tumbull 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 provide further information in the Application that indicates that reservoir pressure can not ~d 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- v/ 127 with the appropriate supporting information. Therefore, these requests should be removed from the Application and submitted on the proper form. This fo'rm 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 of 500 Xj 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?, ..~,,,~ ~.~ ~, ~,.. 6. We have concerns with part c of proposed pool rule 5. It has been our experience that attempting to determine 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 mentioned provide acceptable results and are therefore acceptable to us. :b / -~ ..... . / 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 timely manner. ~/~ 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 work on Federal wells be .performed in accordance with the provisions iSf ~J'Ui~2'~'~J'~ ~ubparts E and F. The only aCt--s t-ih"'fiT'~e will allow w~l/out prior approvhT'~e the routine Operations listed in 30 CFR 250.601. ,,, Mr. Bill Tumbull BP Exploration (Alaska) Inc. 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? - °'~-9 I -ce,~, -to 13~, -~ ~ ~>,-~,~ o,~ ~4~ c~.../: ..... 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 somewhere within the Shublik formation. 8,~-~ b - t.o~o~_o ~o Iw 5~,r_.. c~~ 3.~,o~> o^.,~I ~~ ,~ ,r~w ~'F" 'r~, 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. 4. Page 9 indicates that several feet of gas were present in the Shublik D Zone in the Northstar- [ 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 ~he Ivishak. Since this issue could affect the definition of the pool, it would be appropriate to have additional clarification on this. ~Y~-~oB.~,.~3 5. Please indicate what percentage of the total reservoir volume the inferred gas cap occupiesl I- z..°/o. "J 6. Page 10 indicates that a 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. ~/¢1.~,., ayd-[g D.~icv~% ~?'~ ~:~ 7. When do you expect to complete work on the mechanistic finer grid 3-D partial field models, referenced on page 1~, that_will be used to validate the full field model?a~,ssj:) 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. Mr. Bill Tumbull BP Exploration (Alaska) Inc. . 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 perform any model hms with an increased produced water handling capacity? If so, did this have a significant effect on the ultimate oil recovery? 5/S5 - Thank you for considering our comments when you revise the Application. If you have 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. CC: Sincerely, Regional Supervisor Field Operations p2Ctr, Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 1000 Anchorage, Alaska 99501 Comments on North Star CO and AIO Application~ Subject: Comments on North Star CO and AIO Applications Date: Fri, 05 Jan 2001 17:05:21 -0900 From: Jack Hartz <jack_hartz~admin.state.ak.us> Organization: AC)GCC To: Robert Crandall <bob_crandall~admin. state.ak.us>, Wendy Mahan <wendy_mahan~admin.state.ak.us> CC: Julie Heusser <julie_heusser~admin.state.ak.us> I'll be gone for the Jan. 9th meeting so will comment now. These can be integrated into the note we give to BPX during the meeting so we have something on the record that we've asked for more information. Pool Rules Testimony Comments 1. Provide a gas analysis and oil analysis that will typify the North Star oil and gas. 2. What are the sensitivities that BPX considered for the recovery processes, i.e., what would be a critical parameter(s) that would decrease the projected recovery. 3. Provide transient pressure data and or test results that provide the basis for reservoir properties. 4. (Bob - you may want to expand on this?) Provide core analyses that contributed to the geologic reservoir description. 5. Provide slim tube experimental results and or reports. If confidential, state why, how long and we will store them that way or give them back. 6. Provide PVT analyses and reports that were done to support the engineering effort and EOR project design. 7. Provide the geologic model description and engineering model description so that we can understand how the models were constructed and what may be the sensitive parameters. These can be as supporting documents supplementing your testimony. 8. Is is your intent to maintain average reservoir pressure at 5100 psi (11,100' ss)? Or will you try to maintain reservoir pressure near 5100 psi with some measure of cushion. What do you consider a reasonable cushion. 9. Regarding the estimated loss of reserves at Prudhoe, could the voidage be made up with additional water injection? Was that considered when the estimate was done? 10. Do you have a qualitative idea of or an order of magnitude estimate 1 of 3 1/8/01 8:00 AM Comments on North Star CO and AIO Application]" of the benefits from blowdown? Lacking numbers, what is the advantageous mechanism? 11. What would be a possible remedial plan should an FIT fail and perhaps indicate the casing shoe is leaking? 12. What is the nominal spacing in the reservoir based on the 16 producers, what is the surface area of the reservoir? How many barrels of oil are there per acre foot? 13. How do you plan to monitor OWC or Gas movement in the reservoir? Injection Order Comments/questions. 1. What are the producing zone and confining zone mechanical properties that lead to the comment on page 27, Fracture Information? Has there been any modeling of fracture conditions to support the referenced statement? It is important that the record shows this was addressed and that there is support for a finding. Comment on Rules 1. Rule 7: we probably will require a weekly (or monthly) summary of the work actually done in lieu of 10-403's. That way we can track work and anticipate the reports of Sundry Operations 10-404. This is not expected to be a report but rather a list, i.e., 12/15/01 NS-21 perforated 12100-12150 etc. 2. The development plan you are presenting is actually a work in progress that will change and improve as data and reservoir performance are gathered and analyzed. There will be a rule which calls for a periodic review of depletion plans, new simulations, new technology being employed or new evaluation techniques, experimental procedures. This will enable the AOGCC to keep abreast of developments and ensure the project is proceeding toward maximum ultimate recovery. Jack Hartz <jack hartz~admin.state.ak.us> Sr. Petroleum Reservoir Engineer Alaska Oil & Gas Conservation Commission 2 of 3 1/8/01 8:00 AM Northstar meeting Subject: Northstar meeting Date: Tue, 19 Dec 2000 14:36:18-0900 From: Wendy Mahan <Wendy_Mahan~admin.state.ak.us> Organization: doa-aogcc To: "Turnbull, Bill F" <tumbuwf~BP.com>, "Crandall, Krissell" <CrandaK@BP.com>, "Walker, Jeffrey" <Jeffrey. Walker~mms.gov> We have scheduled a work meeting for January 9th, 2001, 2-4 pm, to discuss BPXA's draft Northstar Pool Rules/AIO application. Our address is 333 W 7th Avenue, Suite 100.Please let me know of any conflicts as soon as possible. Thanks, Wendy Mahan 1 of 1 1/9/01 1:57 PM Northstar comments Subject: Northstar comments Date: Mon, 08 Jan 2001 14:41:19 -0900 From: Wendy Mahan <Wendy_Mahan@admin.state.ak.us> Organization: doa-aogcc To: Robert P Crandall <bob_crandall~admin.state.ak.us> Additional Comments on North Star CO and AIO Applications: Would like explanation of startup plan and flaring estimates. Also equipment operating guidelines with respect to flaring, p. 18 of application also mentions continuous flaring from tank vapors and glycol regeneration vent scrubber vapors. Continuous flaring shouldn't be allowed from these sources. AIO application only covers EOR. Do they plan on any Class II or annular disposal, or will Class I handle all wastes? Thanks, Wendy 1 of 1 1/8/01 3:46 PM #5 #4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION NORTHSTAR POOL RULES AND AREA INJECTION ORDER August 16~ 2001 9:00 AM NAME - AFFILIATION (PLEASE PRINT) ADDRESS/PHONE NUMBER TESTIFY (Yes or No) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION NORTHSTAR POOL RULES AND AREA INJECTION ORDER August 16~ 2001 9:00 AM NAME - AFFILIATION ADDRESS/PHONE NUMBER TESTIFY (Yes or No) (PLEASE PRINT) 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING In Re: NORTHSTAR OIL POOL, NORTHSTAR FIELD POOL RULES AND AREA INJECTION ORDER. TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska August 16, 2001 9:00 o'clock a.m. APPEARANCES: Commissioners: MS. MR. MS. CAMMY OECHSLI TAYLOR, DAN SEAMOUNT, JR. JULIE HEUSSER CHAIRPERSON Attorney General's Office: MR. ROBERT MINTZ RECEIVED AUG 2 8 Z0O! ^laska Oil & Gas Cons. Commission Anchorage METRO COURT REPORTING, 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 INC. ORIGINAL 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 TABLE OF CONTENTS Witnesses: FOR THE APPLICANT: DIRECT Peter Flones Kenneth Lemley Terry Wilcox 16 31 METRO COURT REPORTING, 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 INC. 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 P R O C E E D I N G S (On record - 9:05 a.m.) THE CHAIRPERSON: I would like to call this hearing to order. Today is Thursday, August 16th, and the time is approximately 9:05. We are at the AOGCC offices at 333 West Seventh, Suite 100. The subject of today's hearing is BP's application for pool rules and area injection order for the Northstar Oil Pool. I'd like to introduce here at the head table the three commissioners. To my right is Dan Seamount. To my very far left is Commissioner Julie Heusser. My name is Cammi Taylor. To my very far right is Laura Ferro from Metro Court Reporting. These proceedings are being recorded and transcribed, and arrangements for copies of the transcripts can be made directly with Metro Court Reporting. To my immediate left is Rob Mintz. He's an assistant attorney general who is here to advise the Commission on procedural and legal questions. A notice of public hearing was published in the ,. Anchorage Daily News on July 5, 2001. These proceedings will be conducted in accordance with 20 AAC 25.540. We ask that the Applicant present testimony first, and all persons wishing to testify will be sworn. Each witness shall be asked to state their name and who they represent. If they wish to give expert testimony, we ask that you state your qualifications, and the Commission will then rule on whether you qualify as an expert. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 Ail others wishing to present testimony will be heard next. A person wishing to make an oral statement will be allowed to do so after the conclusion of all the testimony. We ask that a person not ask questions of the witness directly, but if they have questions in the audience that they would like to have directed to a witness, that we ask that you provide that question in writing along with your name and the name of the witness that you would like the question directed to, and have you provide that to one of the designated Commission staff members. And we have several Commission staff here. In the back of the room are Jack Hartz and Bob Crandall, and Jane Williamson seated here in the middle. So if you have a written question from the audience that you would like to have directed to the head table, you could provide it to them and then pass 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. program manager for Northstar. testify today? I'm the THE CHAIRPERSON: And who will you be having MR. FLONES: MR. LEMLEY: Ken Lemley. I'm Ken Lemley. I'm the geologist METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 for Northstar. MR. WILCOX: I'm Terry Wilcox, the reservoir engineer for Northstar. THE CHAIRPERSON: Good morning. Thank you. Before we actually start taking testimony, perhaps if we could ask a clarification on some of the documents that have been submitted. We have initially filed was an application that came in two forms on June 25th, followed by a proposed draft of testimony on August 3rd, and then a subsequent document that was filed on August 13th. Some of those initial documents had requests for confidentiality held on that. We noticed some subsequent discussion between our staff and your staff about what would be -- whether there would be a request for confidentiality. As I understand it, the last document that was filed on August 13th, there are no longer claims for confidentiality except for one portion of the initial application. Do you have copy of that? It's on page 21. MS. DICKEY: The last one that was filed has no claim of confidentiality, and we would ask to have it replaced, the confidential portion -- the confidential version that was first filed. THE CHAIRPERSON: Okay. And with respect to the draft testimony, is all of that then public testimony? MS. DICKEY: No, the first draft we would like it replaced with what we give today. I think it had claims of METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 confidentiality, too. THE CHAIRPERSON: Okay. And there will be new ..... today? MS. DICKEY: Yeah. THE CHAIRPERSON: ..... testimony submitted MS. DICKEY: The testimony we're submitting today has removed all the confidential claims. It's all public. Unless you ask questions that, you know, come up that are confidential. But the first drafts that claimed confidentiality have been replaced by the subsequent draft, for which there are no claims of confidentiality. THE CHAIRPERSON: So you don't plan today to need a hearing -- any portion of the hearing to be confidential? MS. DICKEY: No. THE CHAIRPERSON: Okay. If I could have just a minute. Would you like to withdraw then the first two applications that have the confidential portion and substitute in the August 13th? MS. DICKEY: Yes. THE CHAIRPERSON: Okay. We will do that. And the testimony will also be withdrawn. MS. DICKEY: Withdrawn, the first one. Yeah. THE CHAIRPERSON: Okay. I think that takes METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 care of it. Thank you very much. We're ready proceed. Who's going to start? MR. FLONES: I'll start. My name is Pete Flones. I am the Northstar Program Manager for BP Exploration Alaska, Inc.. BP is the operator of the Northstar Unit on behalf of itself and Murphy Exploration, Inc.. This hearing has been scheduled in accordance with 20 AAC 25.520 and 20 AAC 25.540 in order to consider evidence relevant to the establishment of pool rules and an area injection order for the development of the Northstar Pool. BP previously filed an application with numerous exhibits and technical data. We would like to incorporate that application into the record. BP is requesting an order from AOGCC defining the . geographic area of the Northstar Pool, the stratigraphic description of the NorthStar Pool, and the spacing rules for development drilling in the Northstar Pool. In our application, we have defined the Northstar Pool 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. With regard to spacing, we seek to establish 40 acre drilling units with authorization to drill into and produce from any bottom hole location within the Northstar Pool without METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 regard to section lines or lease boundaries within the unit. We are also requesting an exemption from the standard requirements for gas/oil ratios in order to conduct enhanced oil recovery using miscible injectant. BP also requested that the United States Mineral Management Service approve gas reinjection and enhanced oil recovery under its regulations. BP has coordinated its submissions to AOGCC and MMS so that each agency receives the same information and is cross copied on any request or application to the other agency. Where there are any difference between the requirements imposed by A©GCC and MMS, BP will comply with the more stringent regulati~on or statute. We are not aware at this time of any instance where complying with the regulatory requirements of any one agency would violate the requirements imposed by the other. We also submit an application to the State of Alaska, Department of Natural Resources, and the MMS requesting the formation of the Northstar initial participating area. The participating area application includes proposed tract allocation factors. The testimony we are presenting today is divided into three parts. I will provide an overview of the project facilities and the well operations. Ken Lemley will testify about the geology of the Northstar Pool, and Terry Wilcox will testify about the reservoir. We are asking that each witness METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 995021 (907) 276-3876 10 11 12 1'3 14 15 16 17 18 19 2O 21 22 23 24 25 be qualified as an expert, and each of us is prepared to respond to questions concerning our testimony and related exhibits. I'd now like to be sworn and qualified as an expert witness. THE CHAIRPERSON: Okay. Would you raise your right hand, please? .... (Oath administered) MR. FLONES: I do. PETER FLONES having been first duly sworn under Oath, testified as follows on examination: DIRECT EXAMINATION THE CHAIRPERSON: Would you state your full name and spell it for the record, and then proceed with your qualifications? A Okay. My name is Peter Flones, F-l-o-n-e-s. Okay. My name is Pete Flones. I received a degree in physical metallurgy from Washington State University in 1969, and have been a licensed mechanical engineer in the State of California since 1979. I've been employed by BP since February of 1975 as an engineer project manager and field operations manager. I've spent almost my entire career at BP working on the development and operation of Alaskan arctic oil fields. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 995021 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I was the project manager and field operations manager for the Endicott oil field, and the program manager for the development of the Badami field. I've been the program manager for Northstar since 1998. THE CHAIRPERSON: Do either of you have any questions? COMMISSIONER HEUSSER: No. THE CHAIRPERSON: And the subject of your expertise for your testimony today is as a project manager? A No, I'm the program manager with -- for the Northstar ..... THE CHAIRPERSON: As the program manager. That's the area of your expertise? A Right. COMMISSIONER SEAMOUNT: I have no questions. THE CHAIRPERSON: Any objections? COMMISSIONER HEUSSER: No. THE CHAIRPERSON: We'll consider your testimony as an expert. A Okay, thank you. We have a outline here of the Northstar Unit. This map shows the Northstar unit with the Ivishak outline. I now will provide an overview of the Northstar project and facilities. The Northstar Oil Field was discovered in 1983 by Shell during the drilling of METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 the Seal A-01 well. The Ivishak Formation contains a volatile sweet crude with oil gravities ranging from 43 to 45 api. Initial gas/oil ratios were -- were approximately 2,200 standard cubic feet per stock tank barrel. The Northstar project is a self-contained production facility on Seal Island. It is located six miles offshore in the Beaufort Sea north of the Prudhoe Bay Unit. Seal Island is a five-acre gravel island constructed over the remains of an exploration island built by Shell. The island and pipelines were constructed in early 2000, and the permanent camp was installed in the summer of 2000. The processing and compression modules were recently moved from Anchorage to Seal Island, and are being installed during August and September of this year. We anticipate starting production in October. The Northstar project includes two pipelines buried in a single trench from Seal Island to existing onshore facilities. The Northstar oil pipeline is a 10 inch common carrier pipeline for the export of oil from Seal Island to Pump Station 1 of the Trans-Alaska Pipeline System'. The Northstar gas pipeline is a 10 inch pipeline for importing up to 100 million standard cubic feet a day of gas from the central compressor METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 11 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 plant at Prudhoe Bay Unit. The gas will be used to fuel a processing facility and for enhanced oil recovery. This exhibit is a process flow diagram of the production facilities. Exhibit 20 is the process flow diagram showing the major components of the production facility. The production facility will be capable of handling 65,000 barrels of oil, 30,000 barrels a day of produced water, and 600 million cubic feet per day of injected gas. The processing facilities consist of three primary modules. The first module constructed in two halves contains the separation, gas dehydration, and power generation equipment. The second module contains the low and high pressure gas compression equipment, and the third module contains the water storage and disposal systems. Exhibit 21 shows the general layout of the island. A permanent camp of -- for up to 70 people has been installed on the island. The camp facilities includes emergency power generation, seawater treatment, sewage facilities, and tanks for diesel fuel and water storage. The island is designed for 37 well slots. The initial development consists of 16 production wells, 5 gas injection wells, and a Class I waste disposal well. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 12 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 Drilling began in December 2000, and to date, we have drilled a disposal well, one gas injection well, and two pre-produced gas injection wells. Ail the wells drilled to date comply with the standard spacing requirements imposed by AOGCC regulations. After the facilities start up in October, development drilling will resume and will continue into 2003. We will access the island by ice road in winter. During the summer open water period, we will use barges or supply boats to access the island. We'll use -- we will use helicopters to supplement seasonal access, and also as primary access during thin and broken ice periods. Production will be allocated based on individual well tests and actual plant oil sales volume. Ail production wells are individually connected to test header. Each producing well will be tested monthly to ensure accurate allocation of produced fluids. We will continuously gather operating data from the plant, wells, and test separator. The Northstar project will follow BP's corporate policy of minimizing flaring. The gas injection plant and the gas injection well was planned to be commissioned before the initial start of oil production using gas imported from Prudhoe -- the Prudhoe Bay Unit. We will reduce the amount of flared METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 9950I (907) 276-3876 13 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 gas that is traditionally associated with start up of new production facilities. We will use miscible fluid displacement to enhance oil recovery at Northstar. We will inject a large slug of miscible enriched natural gas into the oil column of the Ivishak Formation for approximately four years. After that, we will inject leaner chase gas until the end of the field life. The miscible gas will be a blended mixture of gas produced from the Northstar pool and gas imported from Prudhoe Bay. We will maintain reservoir pressure close to its initial value at field start up. Are there any questions before Ken Lemley testifies about geology? THE CHAIRPERSON: Do any of you have questions? COMMISSIONER HEUSSER: I do. Mr. Flones, did I hear you say that gas injection with gas from Prudhoe Bay is actually going to start prior to oil production? A We'll be using it for fuel. COMMISSIONER HEUSSER: For fuel gas, okay. A Right. the reservoir? A No. COMMISSIONER HEUSSER: But no gas injection in COMMISSIONER HEUSSER: Okay. Thank you. COMMISSIONER SEAMOUNT: Mr. Flones, do you have METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 14 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 any estimate of what -- of how much you're going to -- how much start up flaring gas you're going to have to deal with? A Yeah, we do have an estimate of that, and I'm -- I think it's -- I hate -- I -- I think I'd have to get -- consult with some of my colleagues here to get the number, but do you folks remember what it is. I -- we can give you that number later. I -- I don't have it off the top of my head. COMMISSIONER SEAMOUNT: Okay. And do you have plans of mitigation to try to keep -- you know, you said that you were going to do your best to keep the amount of flared -- start up flare gas down. Do you have any special ways to do that? A Yeah, we do that. We -- yeah, we -- we start up to get the compression trained, pre-commissioned, and ready to go before we start oil production, so that's -- that's what we -- in our start up sequence, we'll be pre- commissioning the compression unit. Oftentimes, you'll start up a field, and start the oil production section first, and then follow with your gas compression. And we're trying to sequence it where we can get our gas compression pre-commissioned and ready to go at start up oil production. COMMISSIONER SEAMOUNT: Thank you. THE CHAIRPERSON: Any other questions? I'm METRO COURT REPORTING, INC. .745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 15 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 sorry, who did you want to have testify next? MR. FLONES: Ken Lemley. THE CHAIRPERSON: Mr. Lemley, would you raise your right hand, please? MR. LEMLEY: You bet. (Oath administered) MR. LEMLEY: Yes, I do. KENNETH LEMLEY having been first duly sworn under Oath, testified as follows on examination: DIRECT EXAMINATION THE CHAIRPERSON: If you would state for the record your full name and spell your last name, and then proceed to describe your qualifications and in what area of expertise you wish to be considered an expert? A Okay. My name is Kenneth Lemley, L-e-m-l-e-y. I'm a geologist, and that's the area I'd like to be qualified as an expert, in geology. Let's see. My name is Kenneth Lemley. I'm the development geologist for the Northstar Field. I received a bachelor of science degree in geology from California State University at Sacramento in 1982, and a master of science degree in geology from the New Mexico Institute of Mining and Technology in 1984. I also received an MBA degree in business in 1995 from the University of Houston. I've METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 16 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 been with BP for one year. Previously, I was with Fina Oil and Chemical for 15 years as a geologist working the Texas Gulf Coast and Alaska. I have been working the subsurface of the North Slope for the past four years concentrating primarily on Badami and Northstar Fields. My testimony will include an overview of the Northstar Field and its geology. THE CHAIRPERSON: Do any of the other commissions have any questions? COMMISSIONER HEUSSER: COMMISSIONER SEAMOUNT: NO. I have no questions. THE CHAIRPERSON: Any objection to him being considered an expert? COMMISSIONER HEUSSER: A None. THE CHAIRPERSON: Okay. Why don't you proceed? Thank you. 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. The Kingak shale serves as the overlying top seal, and the Kavik shale serves as the underlying bottom seal. The top of the Northstar Pool which coincides with the top of the Sag River formation occurs at a depth of 10,650 feet TVDrkb in the Seal A-01 type log. The base of the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 17 10 11 1¸2 13 14 15 16 17 18 19 2O 21 22 23 24 25 Northstar pool which coincides with the base of the Ivishak occurs at a depth of 11,160 feet TVDrkb in the Seal A-01 type log, with the interpreted oil-water contact at 11,100 feet TVD subsea. The Northstar Field consists of a faulted four way structure. Our reservoir description of the Northstar Pool is based on the 3-D seismic survey, whole core, and well log data from the Seal A-i, Seal A-2A, Seal A-3, Seal A-4, and Northstar 1 wells. A total of 1,196.3 feet of Ivishak core was acquired from these four wells. Exhibit 6. Exhibit 6 is a structure map at the top of the Ivishak, and illustrates the trapping configuration. The structure consists of a faulted anticline defined by three way dip closure to the east, west, and south, with fault seal and/or dip closure to the north. Exhibit 7. Exhibit 7 shows two structural cross sections. Cross section AA prime is a cross section running from the southwest to the northeast across the Northstar Pool. Cross section BB prime is a cross section running from the northwest to the southeast. These two cross sections also serve to illustrate the trapping configuration of the Northstar Pool. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 18 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 I will now discuss the Sag River Formation in more detail. The Sag River Formation lies immediately below the Kingak Formation and above the Shublik Formation. The Sag River formation consists of a series of transgressive marine sands, silts, and shales, and is continuous throughout the area. 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. The Sag River is approximately 100 feet thick in the vicinity of the Northstar Field. The core plug permeability values range from .01 to 28 millidarcies, with a mean value of .86 mean millidarcies. The mean core porosity is 13 percent with a minimum and maximum range of 6.8 to 22.8 percent, respectfully. We generated the average log derived porosity from the density log using an average grain density of 2.73 grams per cubic centimeter. The log porosity results averaged 16 to 18 percent in the pay interval. We estimated permeability from a core drive porosity and permeability relationship. We estimate the likely permeability range to be from 1 to 4 millidarcies in the pay intervals. No well or production tests are available for comparison with the core data. We METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 19 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 consider porosities greater than 16 percent and permeabilities greater than 1 millidarcy to be pay. The net to gross ratio varies from 15 to 20 percent utilizing these cut offs. Water saturations within the · Sag River Formation range from 50 to 65 percent, and the Archie parameters that were used in calculating water saturations were m=2.071 and n=2.0. We estimate the original oil in place for the Sag River to be 37.7 million barrels, and 52.1 BCF. We created isopack maps for the Sag River and Shublik using existing well control. We determined porosity, water saturation, and net to gross ratios for the Sag River from well log and core data analysis. We then combined these data to determine the original oil in place for the Sag River. We observed oil and gas shows from the Sag River in the mud logs in the Seal A- 1, Seal A-2A, and Seal A-3 wells. No oil or gas shows were present in the Seal A-4. We estimated water saturation calculations within the Sag River from well logs. We obtained Archie water saturation parameters from analog Sag River data available in the Milne Point area located approximately 10 miles to the southwest. At present, we do not have any capillary pressure measurements in the Sag River Formation to confirm the log derived saturation model. Currently, there is no METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 2O 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 well test in the Sag River Formation to demonstrate its producibility. Next, I will discuss the Shublik Formation. The Shublik Formation lies immediately below the Sag River Formation of Triassic age, and uncomformably overlies the Ivishak Formation of Permian and Triassic age. The Shublik Formation consists of marine silts, shales, sands, and phosphatic limestones, and is continuous throughout the Northstar Pool area. The Shublik Formation is divided into four lithologic units. Marine silts and shales in the Shublik A unit grade 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 grain sands in the Shublik D units. Calcites, silica, siderite, and pyrite are the primary cementing agents within the Shublik Formation. The Shublik 'Formation is approximately 85 feet thick in the vicinity of the Northstar Pool area. The Shublik A unit is approximately 35 feet thick. The Shublik B unit is approximately 10 feet thick. The Shublik C unit is approximately 30 feet thick, and the Shublik D unit is approximately 10 feet thick. The whole core porosity and permeability data suggests that most of the Shublik is tight and non-reservoir with the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 21 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 exception of the Shublik D unit. Permeability is generally less than one millidarcy and porosity less than 10 percent. However, porosity and permeability measurements as high as 16.3 percent and 100 millidarcies occur in a few instances in thin discontinuous intervals of less than three inches. These thin intervals are not resolvable on well logs, and usually add up to less than two feet. The Shublik D unit was combined with the Ivishak reservoir in a static reservoir model. Core data across the Shublik Formation exists in the Northstar 1 and the Seal A-2A wells. Core porosity and permeability data suggest that most of the section is tight and non-reservoir with the exception of zone D. It is difficult to determine water saturation within this section using conventional analysis and well logs due to the presence of pyrite, which suppresses the induction log and gives anomalously high water saturation estimates. A well test and core fluorescence in Northstar 1 suggests that the Shublik may be gas bearing at that location. Finally, I will discuss the 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 continuous METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 22 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 throughout the Northstar Pool area. The Ivishak consists of delta front sands and shales grading upward to fluvial sands, and finally, into medium to course grain pebbly conglomerates. The Ivishak is approximately 325 feet thick in the vicinity of the Northstar Pool. The Ivishak reservoir is divided into an upper conglomeratic unit, and a lower sandy unit. The upper conglomeratic unit is approximately 225 feet thick, and is characterized by a bimodal grain sized distribution consisting of mostly chert and quartz class, 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 is approximately 100 feet thick, and consists of medium to course grain sand with minor amounts of silt and shale. This lower unit is present below the oil-water contact throughout most of the field area. Calcite, silica, and siderite are also the primary cementi'ng agents present within the lower sand unit. The Ivishak reservoir at Northstar is more proximal, courser grained, more deeply buried, and cemented than the Ivishak reservoir in Prudhoe Bay, leading to lower average porosities and permeabilities. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 23 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 Extensive routine porosity and permeability measurements were available from four wells. Seal A- 01, Seal A-2A, Seal A-3, and Northstar 1. Permeabilities 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 porosity and permeability trend relationships. The conglomerate facies studied by Shell in core laboratories, have an average porosity of nearly 14 percent, while the sandstones have an average porosity of nearly 18 percent. These studies also indicated that the volume fraction of microporosity increases as one moves downward in the reservoir section. Our analysis of pressure and production data indicates an absence of vertical permeability barriers within the Ivishak. The kV/kH ratio is nearly 1, and the presence of cemented intervals does not appear to be laterally extensive. A sensitivity study of the impact of the insitu confining stress on porosity and permeability indicates that porosity loss was minimal, 3 percent loss, whereas the reduction of permeability METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 24 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 was more significant, 14 to 21 percent loss. The mean stress corrected core porosity for the Ivishak Formation above the oil-water contact is approximately 15 percent. Core permeability ranges from 0.01 to 808 millidarcies, with the mean stress corrected value of 53 millidarcies. We made net to gross estimates using a combined ~ shale cutoff of 50 percent, and 10 percent porosity cutoff for sandstones, and an 8 percent porosity cutoff for conglomerates, which equates to a 1 millidarcy permeability cut off. The reservoir has a very high net to gross ratio of 93 to 95 percent. We determined that the average oil saturation was 42 percent 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 at 11,100 foot TVD subsea at 11,020 foot subsea. We estimate that the maximum oil column ranges from 270 to 300 feet. We derived the equation for the reservoir water saturation used in the static geologic model from the regression analysis of the porous plate, mercury air, and centrifuge capillary pressure data, from the core in the Seal A-2A well. We determined the Archie water saturation parameters from electrical property measurements on 35 core samples. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 25 10 1t 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 The average M value for the conglomerate was 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 determined that water resistivity was 0.10 ohm meters at 247 degrees Fahrenheit based on a formation water sample of 19,340 parts per million sodium chloride from the Seal A-1 well. My next topic is faulting at Northstar. 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 styles of deformation in nearly 1,200 feet of whole core. Pressure build up analysis from several wells found no evidence of production barriers surrounding existing appraisal wells even though they are relatively close to mapped faults. RFT and pressure data from the Seal A-2 and Seal A-1 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 than the average reservoir thickness of 325 feet. We interpreted faults at Northstar to be METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 26 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 neutral with respect to reservoir performance given the high net to gross ratios observed, the lack of deformation observed in the core data, and the inability to determine reservoir boundaries from build up 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 the relative importance of faulting and reservoir compartmentalization more completely during development. My next topic is fluid contacts. We estimated the Northstar oil-water contact at 11,100 feet TVD subsea, primarily from Seal A-1 and Seal A-2 core oil stains, RFT and MDT pressure analysis, and a well test directly above the oil-water contact in the Seal A-1. A test below 11,100 feet TVD subsea in Seal A-3 and Seal A-2A indicated water production. No oil-water contact was observed in the Seal A-4 well. Oil-water contact is not obvious on any of the Seal well logs, with the exception of Northstar 1, as the well log calculated water saturation numbers are in general quite high near the oil-water contact. This is because of the significant amount of bound water in the microporosity. Additionally, the pressure gradient METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 27 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 analysis of the RFTs run in Northstar 1, NS 27, and NS 31, also indicates an oil-water contact at 11,100 feet TVD subsea. I will now discuss the confining intervals. The Northstar pools 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 shell 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 a 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. We used the geological information I just described to construct the static geologic model. For our model, we divide -- we subdivided the upper conglomeratic unit of the Ivishak into five subunits, and included the Shublik D within the upper METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 28 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 conglomeratic unit in the Ivishak. We subdivided the lower sandy unit of the Ivishak into three subunits. We then constructed isopack maps, porosity maps, net to gross ratio maps, and permeability maps for each of these subunits within the Ivishak horizon. We created the structure map for the top of the static model by adding the structure map derived from the 3D seismic interpretation at the top of the Sag River to the inner isopack between the Sag River and the top of the Shublik D. We then sequentially added together subsequent interval isopack maps to create the structural model. We then back interpolated each of these reservoir maps to generate a series of grids at 100 foot increments. We calibrated all map grids, and the structure and reservoir properties to existing well control. The core water saturation measurements were not suitable for calibrating to well log derived water saturation results because the cores from the Seal and Northstar wells were not acquired with low invasion oil based mud. Traditional well log derived saturation methods were complicated by the presence of significant amounts of microporous chert. Given the problems associated with well log derived saturation model, we generated an equation representing the water saturation METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 29 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 for the reservoir as a function of height above the free water level for both conglomerates and sandstones using a multiple regression analysis of 131 capillary pressure measurements. We determined water resistivity, Rw, based on a formation water sample of 19,340 parts per million sodium chloride from the Seal A-1 well. Exhibit 13 shows the chemical composition of the formation water sample taken from Seal A-1. In general, the log derived water saturation model and the capillary pressure derived water saturation model are in close agreement. The static geologic models were used to define the structure of the Northstar pool, and are the basis for the construction of the dynamic reservoir simulator. That concludes the geologic part of our testimony. Are there any questions before Terry Wilcox provides testimony about the reservoir? COMMISSIONER SEAMOUNT: I don't have any questions at this time. Thank you. THE CHAIRPERSON: Commissioner Heusser, do you have any questions? COMMISSIONER HEUSSER: Not at this time. Thanks. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 3O 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 please. THE CHAIRPERSON: MR. WILCOX: Yes. THE CHAIRPERSON: Thank you. You'll be next? I'd like to be ..... Raise your right hand, (Oath administered) MR. WILCOX: Yes. TERRY WILCOX having been first duly sworn under Oath, testified as follows on examination: DIRECT EXAMINATION THE CHAIRPERSON: And you wish to be qualified as an expert? A Yes. A THE CHAIRPERSON: Reservoir engineer. THE CHAIRPERSON: In what area? Okay. Why don't you go ahead? Why don't you state your full name and spell your name for the record, and then give us your qualifications? A My name is Terry Wilcox, W-i-l-c-o-x. I am a reservoir engineer for the Northstar field. I received a bachelor of science in civil engineering from Auburn University in 1979, and a master of science degree in 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 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 31 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 7 years for Exxon as a reservoir engineer on Gulf Coast oil and gas condensate reservoirs. I'm a licensed petroleum engineer with the State of Florida since 1985. I have worked on Northstar since May of 2000. THE CHAIRPERSON: Are there any other questions about his qualifications? COMMISSIONER SEAMOUNT: I have no questions. And I don't have an objection. COMMISSIONER HEUSSER: And no objection. THE CHAIRPERSON: expert. A I have no questions. We'll accept you as an Thank you. First, I'd like to discuss our estimates of 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 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 32 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 microporosity, and in the fluid PVT properties. Now, I'll talk about the reservoir pressure and temperature. The initial pressure of the Northstar pool at 11,100 feet TVD subsea, which is the oil-water contact, was 5,305 pounds per square inch gauge. We estimate average reservoir temperature to be 254 degrees Fahrenheit at the oil column centroid. Reservoir pressure appears to have declined by about 125 psi since the exploration wells were drilled in 1984 through 1986. Average reservoir pressure at the oil-water contact is now 5,180 psig based on RFT and MDT pressure measurements in NS 27 and NS 31, the development wells drilled earlier this year. Our current interpretation is that this pressure drop is a consequence of the pressure decline in the Prudhoe Bay Ivishak reservoir, which we believe is in hydraulic communication with the Northstar Ivishak reservoir through the aquifer. Right now, the reservoir pressure appears to be about 80 psi above the bubble point pressure at the centroid of the oil column. The lower 150 to 225 feet of the reservoir appear to be at pressures exceeding bubble point pressure, while the upper portion of the reservoir may have dropped below bubble point pressure. A small amount of gas in the region below bubble point pressure may have formed a METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 33 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 critical gas saturation or migrated to the structurally higher areas of the reservoir. I'll now address our fluid PVT data. PVT analysis was performed on recombined surface samples from Seal A-i, Seal A-2A, Seal A-3, and the Northstar 1 wells. Our analysis indicates a slight oil compositional gradient with oil density increasing with depth. Oil gravity averages 44 degrees api. The solution gas/oil ratio averages 2,200 standard cubic feet per barrel. The oil formation volume factor averages 2.2 reservoir barrels per stock tank barrel. The oil viscosity averages .14 centipoise. Our analysis of the bubble point pressure versus depth from the Seal A-1 well indicates the reservoir may be saturated near the crest of the structure with a gas-oil contact inferred to be located at 10,839 feet TVD subsea. This inferred GOC has not been verified by drill wells. Several feet of gas were present in the top of the reservoir in the Shublik D zone in the Northstar 1 well. The gas elevated the GOR to 5,300 SCF per stock tank barrel in the well test in which the upper 30 feet of the well was perforated. These perforations include the Shublik D in addition to the upper Ivishak E. This gas appears to be isolated from other upstructure Ivishak wells in which free gas METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 34 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 was not present. There is no evidence of a heavy oil tar zone in the Northstar Ivishak reservoir. We have run one slim tube experiment with oil from the Northstar 1 well to verify miscibility. This experiment achieved a 98.7 percent recovery efficiency at 1.2 pour volume gas injection. PVT quality bottom hole fluid samples were taken in late May 2001, with the MDT tool from the Northstar 31 well. The oil samples taken near the oil column centroid will be used in PVT studies to determine bubble point pressures and compositions, and for further slim tube experiments to verify miscibility. Slim tube simulations indicate the oil compositional gradient has a negligible impact on minimum miscibility pressure. I will now describe our reservoir models in more detail. We constructed reservoir models of the Northstar pool to evaluate development plans, and options to investigate reservoir management practices, and to generate rate profiles for facility design. We constructed a three dimensional full field model and a finer grid mechanistic models. The models are compositional, utilizing either a 10 or 15 component of equation of state. The 3D compositional full field model covers the entire Ivishak reservoir and the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 35 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 surrounding aquifer. The Sag and Shublik Formations except for the Shublik B sand were not included in the reservoir simulation. The full field model has 400' foot or a 3.78 acre grid box over the oil column with 2,000 feet or 92 acre grid blocks over the surrounding aquifer. There are 18 vertical layers with grid block thickness averaging 15 to 30 feet. We included faults in the model through corner point geometry, and considered them to be neutral with respect to flow. We used a capillary pressure equation relating porosity and height above the oil-water contact to predict initial water saturation. We obtained grid block values for porosity, permeability, net to gross, and isopack layer thickness by back interpolating grid block coordinates against the static model. We used very finely gridded mechanistic one dimensional models to study miscible displacement aspects of the flood. We have run one slim tube experiment with oil from Northstar 1 to verify miscibility. The experiment was used to validate the equation of state by history matching the slim tube results. We have additional slim tube experiments under way using oil samples taken from a recent development well. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 36 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 We also developed mechanistic finer grid 3D partial fiel'd models. These studies are being used to investigate water coning, horizontal versus vertical well performance, and to validate the courser grid full field model. 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. I will now describe the process we used to select the enhanced oil recovery program. We evaluated miscible gas injection along with waterflood, gas cycling, and primary depletion scenarios. Ail of the cases run on our model use the same number of wells and locations. We controlled injection to maintain reservoir pressure near original for the miscible gas and waterflood cases, with pressure declining in the gas cycling and primary depletion cases. Total hydrocarbon liquid recovery for the miscible gas injection case was 176 million barrels. The waterflood case produced 135 million barrels. The gas cycling case, 136 million barrels, and primary depletion produced 94 million barrels. We also evaluated water alternating with gas injection but the model runs indicated no additional recovery. We selected miscible gas injection because it METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 37 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 resulted in significantly higher recovery efficiency. We forecast that recovery with miscible gas injection is 12 to 14 percent OOIP higher than either gas cycling or waterflood. We are implementing miscible gas injection concurrent with drill start up in order to get maximum benefit. We evaluated three field production rate scenarios with average oil off takes rates of 65, 72, and 90 thousand stock tank barrels per day. The ultimate oil recoveries determined from these model runs were not sensitive to field production rate. The higher offtake cases did slightly better due to producing and injecting greater volumes of gas to the reservoir early in field life before gas handling facility limits were reached. We also have options for additional reserves within the Northstar unit. We are currently limited to drilling extended reach wells with bottom hole locations, no more than approximately 17,500 feet from the production island. Because of this limit, 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 carried out. We expect that with the experience from our initial program, and with advances in drilling METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 38 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 technology, we will be able to tap the seven to eight million barrel potential at the end of the current drilling program. We also recognize that satellite oil accumulations may exist within expected drilling reach from the island. These targets will be the subject of additional appraisal. I will now discuss current development plans. The Northstar current 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 16 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 current development plan calls for drilling the peripheral producers as high angle wells which allows e-line or slick-line access for routine surveillance. Miscible injectant is made by blending gas imported from Prudhoe Bay Unit with gas produced at Northstar. 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 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 39 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 make up gas from PBU acts to maintain reservoir pressure which maintains miscibility. We currently anticipate that NGLs will be left in the produced gas for the first four years of the project. The miscible gas injectant phase will be followed up by leaner chase gas injection for the remainder of the oil production phase of field life. I need to add that one of the objectives of the slim tube studies currently under way is to determine if miscibility can be achieved if the NGLs, which are mostly C5s and heavier, are removed from the -- from the miscible injectant. Let me clarify that. We're looking to see if we can leave -- remove the C5 and heaviers from the miscible injectant, and put -- put them into the -- into the oil export line. Our current iD simulation studies indicate that the NGLs can be removed while still maintaining miscibility. Water coning at Northstar is an area of uncertainty due to the apparent absence of barriers to vertical flow. We are currently evaluating horizontal peripheral wells as a possible option. To help evaluate water coning issues, we plan to take RFT pressure data and the wells drilled after field start up to determine if there are vertical cement barriers present in the reservoir which may act to reduce water METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 40 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 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 41 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 the project, we would like to maintain the option of exceeding 100 percent 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 100 percent voidage replacement, reservoir pressure may decline assuming continued pressure depletion through Ivishak aquifer. To prevent hydrocarbons from being displaced into the aquifer, we will not increase the average reservoir pressure 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 oil water contacts 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 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 42 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 as sufficiently 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 during blow down, we will reduce reservoir pressure to maximize recovery of the injected gas. We have not yet determined gas recovery volume from blow down. Based on the information provided in our application and and at this hearing, we are requesting 40 acre spacing for maximum flexibility, and an exemption from the standard gas-oil ratio requirements. This concludes our formal presentation. Are there any questions for me or the other witnesses? THE CHAIRPERSON: Do either of the commissioners have questions for Mr. Wilcox? COMMISSIONER HEUSSER: I have several. Okay. Mr. Wilcox, you mentioned the possible development of satellite pools from Northstar. What might those be? A They -- they could potentially be the Kuparuk interval. COMMISSIONER HEUSSER: Okay. And did I correctly hear you say that you could maintain miscibility without the presence of NGLs, that once you figure out how to spike them into your oil line, that's METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 43 ¸,4 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A what you intend to do? Well, we're running a slim tube test to verify that we can extract these NGLs and still maintain miscibility. The gas appears -- the -- the oil appears to be light enough that it would be miscible even if we take these 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 project. But before we do that, we want to verify that with some experimental data just to make sure we're right on that point. COMMISSIONER HEUSSER: What would the minimum miscibility pressure be? A . The minimum miscibility pressure is -- we think it's fairly close to the bubble point pressure, and we think we're fairly close to bubble point pressure, and that's why we're not planning to let the pressure drop. We're planning to maintain pressure. If anything, we're -- we're wanting to build pressure slightly during the -- the early part of this project, so we -- but we're planning to operate within 50 psi of what -- what it was to start with. Again, this is -- what the slim tube studies are looking at are exactly what is the minimum miscibility pressure. COMMISSIONER HEUSSER: Okay. I heard you talk METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 44 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 that or say that later in the field life, you anticipate reducing injection and reducing the reservoir pressure and allowing the aquifer to kind of come on in and potentially move some hydrocarbons that way. 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 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 45 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 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 that is expected to be produced from this reservoir. It appears to be substantial. There was a table in here. How do you intend to handle that produced water? A The produced waters, we have a 30,000 barrel a day water handling facility, and it's going to be disposed 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? A 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 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 46 10 11 12 13 14 15 16 17 18 19 2O 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 of how do you intend to evaluate the effect of Prudhoe Bay pressure decline both before and after major gas sales should that occur on the performance of the Northstar reservoir? A 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 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 47 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 we've only experienced 125 psi pressure decline. We still think for the most part we're above our bubble point on our oil, and that we're miscible with our gas. And, you know, again, that's why we're planning early on in this project to over-inject just a little bit to build some pressure in the central area of our reservoir where most of our reserves are. The way the pattern is set up, the injectors are in the central interior, thick part of the reservoir, and the producers are out on the periphery. So we'd like to build pressure in the central part of the reservoir, and pressure will be down a little bit out on the periphery where the producers are producing. COMMISSIONER HEUSSER: Thank you. I have no more questions. COMMISSIONER SEAMOUNT: I think all my questions have been answered. Thank you. THE CHAIRPERSON: Let me check at this time. I haven't seen the sign in sheet. Are there any other people present today that wish to provide testimony? Are there any members of the public who are here that wish to make a statement at this time? Have any of our designated commission staff received any questions from the public? What we would like to do at this time is take about a METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 48 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 15 minute break, and then we can regroup and come back with any remaining questions that we have, and we'll see if we can be good on our timing for 15 minutes. Off record. (Off record - 10:15 a.m.) (On record - 10:40 A.M.) THE CHAIRPERSON: We're back on record. The time is approximately 10:40. We're not doing as well as we thought we would on our estimate of time off. I apologize. We have no additional members of the audience who are here to testify or to make statements. There were no written questions submitted to us to pass on, but I believe there are a few additional questions from the Commission. Which one of you would like to begin? COMMISSIONER SEAMOUNT: I just have a couple of quick ones. What's the total amount of gas you plan to import for this project? A It's about 400 billion cubic feet. COMMISSIONER SEAMOUNT: At what rate? A Up to 100 million a day. COMMISSIONER SEAMOUNT: I have no further questions. Thank you. THE CHAIRPERSON: Okay. Commissioner Heusser? COMMISSIONER HEUSSER: I have just a couple. When you were evaluating your various pressure maintenance options, did you consider aquifer injection? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 49 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 A Injecting water down in the aquifer. COMMISSIONER HEUSSER: Uh-hum. A 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. A 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 that BP intends to qualify this project for EOR credits? A We have filed a EOR certification with the Internal 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 credits. COMMISSIONER HEUSSER: And I believe I heard you say, Mr. wilcox, that and the plan is to do gas METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 5O 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 injection only at this time. I think in your application for an area injection order, you request both gas and water. A The water injection I think is into the disposal well into the shallower sands. I'm I may be a little confused. You know, we're -- I don't think we're requesting injection of water into the Ivishak reservoir. That wasn't my understanding but maybe if - - if Mr. Turnbull (ph) could look at that and verify that. COMMISSIONER HEUSSER: Are you requesting authorization for any water injection? A Just the water injection into the disposal well. COMMISSIONER HEUSSER: Okay. Just the disposal well, which is the Schrader Bluff ..... A Yes. COMMISSIONER HEUSSER: ..... Formation? A The Schrader Bluff. THE CHAIRPERSON: I understand that that well though was permitted by the EPA a Class I injection well. A I think so, yes. Let's see. Let me just see where this is -- in the area injection order where it says injection fluids, it says a description of the recovery process and development schemes as included in Section III of this document. Injection fluid will comprise a blend of associated reservoir gas and imported PBU gas. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 51 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 The composition of the injected fluids is listed in Exhibit 27. COMMISSIONER HEUSSER: Okay. A I don't think we mention injecting water into this reservoir. THE CHAIRPERSON: The only reason I think there was some confusion was because in the actual introduction to the application for area injection order, it says to cover water and miscible fluid injection, so I think you've answered our question. That'll -- that takes care of that I think. COMMISSIONER HEUSSER: And, Mr. Wilcox, would you in just very general terms explain to us the difference between the gas cycling option and the miscible injection option that you've considered? A The gas cycling option is we're only going to take the gas produced from the Northstar reservoir and reinject that minus what we need for fuel to run the facilities, and so we're not bringing in any additional gas to replace the oil voidage. And so therefore the pressure's going to go decline, and as the pressure declines, the injected gas is going to lose miscibility with the oil and leave higher residuals, leave a miscible oil saturation residual, so therefore you get a lot less recovery benefit. So we -- we -- to maintain miscibility, we must have a -- an additional METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 52 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 source of gas to make up for the oil voidage that we're going to be taking out of the reservoir. COMMISSIONER HEUSSER: Thank you. I've got a question about your gas injector spacing. I believe I read that you're going to have 16 producers and 5 gas injectors? A Yes. COMMISSIONER HEUSSER: And that with the information that you have right now, there's a fairly high net to gross ratio within the Ivishak? A Yes. COMMISSIONER HEUSSER: And so there is really no barriers, you know, to fluids. When you go and you inject your gas, and you talk about this gravity segregation, it's just not clear to me how your gas is actually going to contact the majority of your oil reservoir if you've got kind of gravity overriding going on with just five gas injectors and 400 acre spacing. A Well, the way our project works is the gas injectors are located in the central thicker portion of the reservoir to where the water contacts are real low. And we're going to be injecting through the entire column. Now, this oil is very light. It's the lightest oil on the Slope, so its -- its density is much less than something like Prudhoe Bay, for instance. So the density difference between the gas, METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 53 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 and -- and I might almost say the gas is -- the produced gas is richer than normal produced gas out of Prudhoe Bay. It's not going to be as rich as the miscible injectant that Prudhoe Bay's using, but the density difference between the gas and the oil is not as great as at Prudhoe Bay or Kuparuk where their oils are heavier. So you do see gravity segregation, but it's not as severe as you might think it could be. The other thing is the injection rates that were putting 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 average 125 million if all five wells were on. If one of the wells was off for any reason, then you've got 150 million. So the faster you inject the gas, the less severe the gravity segregation is. And the more you can sweep out of the reservoir, the simulation studies show that you -- you do sweep the reservoir fairly -- fairly effectively, leaving just a little bit down towards the bottom part. The permeability distribution also kind of enters into the equation. The 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. COMMISSIONER HEUSSER: Thank you. I have no METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 54 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 further questions. THE CHAIRPERSON: Do you have other questions? COMMISSIONER SEAMOUNT: No. THE CHAIRPERSON: Well, I think that will do it. MR. FLONES: You -- I think Dan asked about the flare volumes, and we just wanted to mention that one of our people on the project, Tom Armstrong, is working on those volumes, and he's been working with Wendy Mahan and hopefully by Monday we should be able to transmit you those volumes. COMMISSIONER SEAMOUNT: Okay. That would be good to know. THE CHAIRPERSON: Well, then perhaps on that representation, why don't we keep the record open until, say, Tuesday afternoon at 4:30 to receive that information. MR. FLONES: Okay. THE CHAIRPERSON: Well, thank you very much for an excellent presentation, and thank you also for working with us on the issues of confidentiality. We appreciate it. MR. FLONES: Okay. Thank you. COMMISSIONER SEAMOUNT: Thanks. THE CHAIRPERSON: We're off record. (Off record - 10:55 a.m.) END OF PROCEEDINGS METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 55 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 C E R T I F I C A T E UNITED STATES OF AMERICA) )SS. STATE OF ALASKA ) I, ~/~./~X/k/~t'~/-;~~Notary Public in and for the State of Alaska, and Reporter for Metro Court Reporting, do hereby certify: That the foregoing Alaska Oil & Gas Conservation Public Commission Public Hearing was taken before Laura C. Ferro on the 16th day of August 2001, commencing at the hour of 9:05 o'clock a.m., at the offices of the Alaska Oil & Gas Conservation Commission, 333 West Seventh Avenue, Suite 100, Anchorage, Alaska; That the public hearing was transcribed by Laura C. Ferro to the best of her knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and affixed my seal this 27th day of August 2001. Notary Public in/~.nd for A~ska My commission e~pires: 7~-.~ METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 #3 bp 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 IA Gas Conservation Commission 333 W. 7TM 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". Aisc 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' 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, i RECEIVED Bill Turnbull Northstar Subsurface Team Leader Alaska Oil & Gas Cons. Commission Anchorage cc: Krissell Crandall .]eanne Dickey File: AOGCC PUBLIC 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 /~UG ~- 3 ZOO1 Alaska Oil & Gas Cons, Commission Anchorage PUBLIC 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 PUBLIC INFORMATION Exhibit 1. Exhibit 2. Exhibit 3. Exhibit 4. Exhibit 5. Exhibit 6. Exhibit 7. Exhibit 8. Exhibit 9. Exhibit .10. Exhibit 11. Exhibit 12. Exhibit 13. Exhibit 14. Exhibit 15. Exhibit 16. Exhibit 17. Exhibit 18. Exhibit 19. Exhibit 20. Exhibit 21. Exhibit 22. Exhibit 23. Exhibit 24. Exhibit 25. Exhibit 26. Exhibit 27. Exhibit 28. Exhibit 29. Exhibit 30. List of Exhibits Northstar Pool Location Map Northstar Injection Area Map Northstar Injection Area Description Northstar Type Log - Seal A-01 Ivishak Isopach Map (Rev 1) Northstar Reservoir Structure and Development Well Location Map Cross Sections - Northstar 1 - Seal A-01 - Seal A-02A - Seal A-03 - Seal A-04 composition of Seal A-01 Formation Water Sample Northstar Type Log Type Log Type Log Type Log Type Log Chemical Northstar Northstar Northstar Northstar Northstar Northstar Northstar Miscible Gas Flood 65 mbd Plateau Rate Waterflood Gas Cycling Primary Depletion Miscible Gas Flood 72 mbd Plateau Rate Miscible Gas Flood 90 mbd Plateau Rate Simplified Process Flow Diagram Northstar Facilities Seal Island General Layout Slimhole Producer Wellbore Diagram Bigbore Producer Wellbore Diagram 7" Injector Wellbore Diagram 5-1/2" Injector Wellbore Diagram Pre-produced Injector Wellbore Diagram Northstar Injection Fluid Compositions Affadavit of Notice to Surface Owners Northstar Pressure Gradients Northstar Oil and Gas Composition 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 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 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 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 43-45° APl. Initial gas oil ratios ("GOR") 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 ('q'APS") 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 ("EOR") 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 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 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 CTVDss"). 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 100 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 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 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 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 D 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 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. 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 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 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 boundaries 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-I, 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-I, 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 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-I, 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-I). 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 I 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 6.8% 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 16-18% for the 10 to 30 ft. section that is considered pay. Permeability was estimated from a core poro-perm relationship. The likely permeability range is estimated to be from I 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 I 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 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-I). 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-l. 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 15%. 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 17.7% and 17.5%, respectively. Additionally, Shell and Core Laboratories reported that within the conglomerate facies 47.4% and 53.2% respectively of the total porosity is micro-porosity. They determined that within the sandstone facies 37.9% and 42.3% 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 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 16% 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 15-25% 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 I 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 93-95%. Non-pay intervals include rare silty/shaley intervals recognized on the gamma ray log (V-shale) and Iow 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 10% porosity cutoff for sandstones and a 8% 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 OOIP 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 IUnits I Sag River Oil I Sag River Gas Bulk rock volume ft3 34.2 x 10"'9 15.3 x 1 N/G ratio % 20 20 Sw % 60 60 Porosity % 17 17 1/Formation volume factor stb/rb 0.455 1/Formation volume factor Bbl/mcf 0.71 Hydrocarbon pore volume ~n reservoir ft3 211 x 10A6 208 x 1 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 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 Iow 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 42% 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 PUBLIC INFORMATION Conglomerates: Sw = 1.3049-2.607*2~-0.076255*LN(HAOWC) Sandstones: Sw = 1.3549-3.607*2~-0.056255*LN(HAOWC) Where: Sw = Water saturation (v/v) 2~= 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 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 247° 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 PUBLIC INFORMATION PRESSURE & TEMPERATURE The initial pressure of the Northstar Pool at 11,100ft. 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 254° 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 OWC 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 PUBLIC INFORMATION Near Water-Oil Near Gas-Oil Fluid Property Contact Contact Oil APl Gravity (Degrees APl) 43 45 Solution GOR (SCF/STB) 1900 2400 Oil Formation Volume Factor (RB/STF) 2.1 2.3 Oil Density at Bubble Point Pressure (gm/cc) 0.54 .51 Oil Viscosity (cp) 0.15 0.13 Gas Viscosity Estimated (cp) 0.06 0.07 Water Viscosity Estimated (cp) 0.25 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 10,839 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 D zone in the Northstar-1 well. The gas elevated the GOR to 5300 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 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 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 % 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 12-14% OOIP higher than Page 17 Northstar Pool Rules and Area Injection Order Application 8/10/2001 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 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 O01P. 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 Iow 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 100% 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 PUBLIC INFORMATION year of the project we would like to maintain the option of exceeding 100% 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 100% 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 Iow 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 Iow 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 PUBLIC INFORMATION Total Liquid Produced Produced Injected Gas Water Gas Plateau Rate (MUSTS) (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 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 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 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 Iow 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 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. Compressor Module The compressor module will support the flare boom, and will include a single Iow 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: . . . . All wells will be tested monthly. The stabilization and duration of each test will be optimized by the operator to obtain a representative test. Well and field operating condition information required for the construction of a field production history will be maintained. Test separator meters and major gas system meters will be installed and maintained according to industry recommended practices or standards. 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: . . Gas injection will be started prior to opening production chokes. This will minimize flaring of primary stage separation off gas during plant startup. Gas will be flared from Iow 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 PUBLIC INFORMATION o , . 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 250.1105(a)(2)(i). 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. 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 PUBLIC INFORMATION Sm 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 10foot 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 26 Northstar Pool Rules and Area Injection Order Application 8/10/2001 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 20AAC25.030(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 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. 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 PUBLIC 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 PUBLIC 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. APl 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 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 PUBLIC INFORMATION 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 ('q'u') 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 TD 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. 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 PUBLIC INFORMATION 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 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 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. 7th 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 AVCG 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-1002-A dated June 23, 2000. Page 34 Northstar Pool Rules and Area Injection Order Application 8/10/2001 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 35 Northstar Pool Rules and Area Injection Order Application 8/10/2001 PUBLIC INFORMATION 1 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 PUBLIC 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 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 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. classified as an Oil Pool. The Northstar Pool is 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 TD 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 ADL~55001 ~= ADL8~ ~809 ~@~~ ~@~ ~hib~t 2 ~ :, NorCl'~s~r UnA Yra~t 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. Section 17. Section 18 Section 19, Section 20, Section 25 Section 26, Section 27. Section 28, Section 29. 13 E., Umiat Meridian, Alaska Protracted All, 640 acres; Protracted Protracted Protracted Protracted Protracted Protracted Protracted Protracted All, 631 acres; All, 633 acres; All, 640 acres; All, 640 acres; All, 640 acres; All, 640 acres; All, 640 acres; 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 Nodhstar Type Lo9 - Seal A~01 Mirrored Sonic GR (APl) ILM-DIL 94 59 59 Shales and silts. Trans§ressive Marine Ssnds, silts and sha~es. Low permeability Marine silts and sh~l Limestones, silts and shales. _ Massive, pebble / cobbie dense cong. Medium conglomerate and variably pebbfy Medium conglomerate and variably pebbly Medium conglomerate and variably pebbly pebbles Fine to medium sands Very fine to fine sands. Prodelta shales, Sand, silt and shale. Carbonates C3 C2 C1 B A2 A1 Exhibit 8 Northstar Reservoir Structure arid 8evelopme~t We~ Locstior~ t~ap ® E×p Planned Oil Producfion Weli ? Pkm~ed Gc~s [niecf[or~ Wel~ ~¢ Appro×fmc~fe Oil Waf®F Con~'rdci d¢ ~1,i00 f} subsec~ Exhibit 7 SVV A Northsta~ Cross SeaNA~01 Seal-A-0~ Sections NB A~ NVV Vedica! Exaggeration = lox Northstar 1 B SeaFA-,O1 SE -11000' Vertical Exagge~alion = lox i2000' ~×hibi{ 8 NORTHSTAR- 1 e×~i~i~ ~ SEAL A- 01 ~×~ibi~ ~ SEAL A- 0 2 A Exhibit ii SEAL A-03 Exhibit'S2 SEAL A- 0 4 Exhibit 13 Chemical Composition of Seal #1 Formation Water Sample Component Concentration (mgll) Ca 575 Mg 12 Na 7540 Fe 115 Ba 1 CI 11800 HC03 1425 S042 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 ~4 No~hstar ~iscible Gas ?lood 65 mhd P~ateau ~ate Liquid Production Profile Gas Production a~d ~nject~on Profiles Cumulative Liquid Production -4oon~ +Produced Water 151.2 mmstb 20,000 0 J ~tnjecled Gas (mmscfd) Cumulative Gas Production and injection 3,ooo,ooo I ~-'Produced Gas 2,485 TCF ¢ 2,5oo,oo~ ~ i ~ Injected Gas 2.757 TCF Water Cut Gas Oi~ Ratio 8o,ooo 70r000 00,000 50,000 40,0OO Exhibit 15 No~hstar Wate~flood q i~e Gas P~oduction and Injection Profiles J i ~ Black Oil (r~ls~bod) Cumulative Liquid Production Cumulative Gas Production and Water Injection Water Cut 400,000 300.000 250,000 Gas 0[~ Exhibit 16 No~thsta~ Gas Cycling Cumulative Liquid P~oduction ~ 2o,ooo Water Gas Oil Ratio Exhibit ~? Northstar Primary Depletion Liquid Production Profile Gas Production Profile Cumulative Liquid Production Cumulative Gas Production 90,000 ~ 8o,ooo Water Cut Gas Oil Ratio Exhibit J8 No~hstar ¢~iscib~e Gas F~oo~ 7'2 mhd Plateau Rate Liquid Production Profile ;~ 40 Gas Production and Injection ProfiJes umu at ye L qu d Production Cumulative Gas Production and Injection WaterCut Gas O~l Ratio Exhibit '~9 Northstar ~liscib~e Gas F~ood 90 mbd Ptateau Rate Liquid Production Profile Gas Production ~nd Injection Profiles Cumulative Liquid Production Cumulative Gas Productio~ and Injection Water Cut Gas Oil Ratio ~xhibi~ 20 5 GAS INJECTORS Northstar Simplified Process F~ow Diagram INCOMING ~oo ~, ~ ~ FUEL GAS 16 Oil. PRODUCERS CLASS 1 DISPOSAL WELL IMPORT GAS [STORAGE PU~TFORR't (,'it) C-QN~, ~ UNITS'} - i)JTILl%'t MODi SOUTH DRAINAGE SUMP I ........... '"' D~SPOSAL WELL,x SERVICE Northstar Facilities Sea~ ls~asd Geserai Layout Exhibit 21 TREE: £xhibit 22 WELLHEAD: 13 3/8", 68#/ft, L-80, BTC (!~ Slimhole Producer ORIGINAL KB. ELEV = BF. ELEV = CB. ELEV = @2000' 4.5" GLM 3.813" ID @ 3000' __.6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 4.5", 12.6#/ff, 13-Cr, Yam Ace TUBING ID: 3.958" CAPACITY: .0152 BBL/FT 9-5/8" 47#/ft, L-80, BTC-M (~ 4.5" X NIPPLE, ~ 3.813" ID (OTIS) 4.5" X NIPPLE, (f~' 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 ~ DATE REV. BY COMMENTS Baker S3 PACKER 3.875" ID @ 4.5" LINER TOP @ 4.276" ID 4.5", 12.6#, 13-Cr Vam Ace Northstar WELL: APl NO; BP Exploration (Alaska) "REE: ORIGINAL KB. ELEV = WELLHEAD:Exhibit 23 Big Bore ProducerBF. ELEV = .... "= "-- ' CB. ELEV = ~ .--., -- --SSSV @2000' I [ __ _.. __ 4.5" GLM ID @2200' ~.6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 13 3/8", 68#/ff, ~ · L-80, BTC (~ 4.5", 12.6#/ff, 13-Cr, -- TUBING ID:" CAPACITY: BBL/FT I I 4.5" X NIPPLE, @ "ID (OTIS) 4.5" X NIPPLE, @' ;~ [] ~ PACKER "ID (OTIS). 4.5" XN NIPPLE, @ ___..__.--I II "ID (OTIS)- 4.5" WLEG, @ "ID (OTIS) -- 9 5/8", 47#/ft ~ L-80, BTC-M @ I I PBTD @ TD (~ '~ ~ 4.5", 12.6#, 13-0r DATE REV. BY COMMENTS Northstar WELL: APl NO: ., BP Exploration (Alaska) TREE: WELLHEAD: Exhibit 24 Big Bore Injector ORIGINAL KB. ELEV = BF. ELEV = CB. ELEV = @2000' 7" HRQ SVLN 5.963" ID 13 3/8", 68#/ft, L-80, BTC @ __.6.SPPG DIESEL FREEZE PROTECTION AT +/- 2200 7", 29#/ft, L-80, TUBING ID: 6.184" CAPACITY: 0.037 BBL/FT 7" R NIPPLE, ~ 5.963" ID (OTIS) 7" R NIPPLE, (~' 5.963" ID (OTIS) 7" RN NIPPLE, (~ 5.5" ID (OTIS) 7" WLEG, (~ (OTIS) 9 5/8", 53.5#/ft L-80, BTC-M @ PBTD @ TD ~ Baker SABL-3 PACKER, 6.0" ID @ 7" LINER TOP 6.188" ID @ 7", 26#, L-80 DATE REV. BY COMMENTS Northstar APl NO; BP Exploration (Alaska) TREE: WELLHEAD: Exhibit 25 Slimhole Injector II ORIGINAL KB. ELEV = BF. ELEV = CB. ELEV = @2000' 10 3/4", 45.5#/ft, L-80, BTC @ ~6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 5.5", 17#/ff, L-80, TUBING ID:" CAPACITY: BBL/FT 5.5" X NIPPLE, @ "ID (OTIS) 5.5" X NIPPLE, @' "ID (OTIS) 5.5" XN NIPPLE, @ "ID (OTIS) 5.5" WLEG, @ "ID (OTIS) 7 5/8", 29.7#/ft L-80, BTC-M @ PBTD @ TD @ PACKER IDB 5.5" LINER TOP @ 5.5", 17#, L-80 DATE REV. BY COMMENTS Northstar WELL: APl NO: BP Exploration (Alaska) TREE: WELLHEAD: Exhibit 26 Pre-Produced Big Bore In ector ORIGINAL KB. ELEV = BF. ELEV = CB. ELEV = @2000' 7" HRQ SVLN 5.963" ID 13 3/8", 68#/ft, L-80, BTC @ ~6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 7", 29#/ft, 13Cr, TUBING ID: 6.184" CAPACITY: 0.037 BBL/FT 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) 9 5/8", 53,5#/ft L-80, BTC-M @ PBTD @ TD(~ PACKER ID ~ 7" LINER TOP (i~ 6.184" ID 7", 29#, 13Cr DATE REV. BY COMMENTS Northstar APl 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 8O.32 C2 8.00 5.32 C3 4.56 1.75 I-C4 O.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 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 June~, 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. 7th Avenue, Suite 800 Anchorage, AK 99501 Mark Meyers, Director Division of Oil & Gas Department of Natural Resources State of Alaska 550 W. 7th 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 E. P. Zseleczky, Land Manager BP Exploration (Alaska)Inc. 900 E. Benson Blvd. Anchorage, AK 99508 3. On June,~, 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: Buford Bates Murphy Exploration (Alaska) Inc. 550 WestLake Park Bivd'., Suite 1000 Houston, TX 77079 Affidavit of K. Crandall Page 1 , for the Northstar Pool Rules and Area Injection Order to be mailed first class to: On June ~,¢~', 2001, I caused a copy of the public version of the application Jim Ruud, Land Manager Phillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 John Jay Darrah, Jr. Managing Partner AVCG LLC 225 N. Market, Suite 300 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. Krissell Crandall STATE OF ALASKA THIRD JUDICIAL DISTRICT SUBSCRIBED AND SWORN to before me this C;~.~ daC~f June, 2001. Notary Public in and for Alaska My Commission Expires: Affidavit of K. Crandall Page 2 STATUS EFFECTIVE MARCH 31,2001 Exhibit 28 ALE~RS EQUAL AR~27 Exhibit 29 o 1,ooo- 2,000 3,000 5,000 6,000, 7,000 · 8,000 - 9,000 - 10,000 11,000 t2,000 No~hstar Pressure Gradients Pressure (psi) 1,000 2,000 3,000 4,000 5,000 0,OOO 7,000 8,000 9,000 10,000 tl,000 12,000 I3,000 Equivalent Mud Weight (ppg) Exhibit 30 Northstar Oil and Gas Composition Seal A-01 Test #2 Recombined (RFL 840067) 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 #2A ia/ #2 STATE OF ALASKA [ NOTICE TO PUBLISHER { ADVERTISING ORDER NO. ADVERTISING ~NVO~CE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFF,DAV,T OF POSL,CAT,ON IP^RT2 Or ~.,S ~OR~)WITH ^TT^CHED COPY OF A0'02214001 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FORINVOICE,~ADDRESS',~' !, F AOGCC AGENCY CONTACT DATEOFA.O. R 333 W 7th Ave, Ste 100 Jody Colombie July 2, 2001 o Anchorage, AK 99501 PHONE PCN - (907~ 793-1221 I~ATE~ ADVERTISEMENT REQUI RED: T Anchorage Daily News July 5, 2001 o P O Box 149001 Anchorage, AK 99514 T.E MA~EmA'~ ~£~WEEN T,E DOU,'.E'.~NES MUSt,E P"JNTED ,N its ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement [~] Legal [-] Display r--I Classified [--IOther (Specify) SEE ATTACHED PUBLIC HEARING NOTICE I [IITOTALOF I PAGES$1 SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF 'ALL · TO " Anchora~_e, AK 99501 2 PAGES REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 3 ., 4 FIN AMOUNT SY CC PGM LC ACCT :FY NMR DIST LIQ I 0l 02140100 73540 2 3 RE/QUI~IONED pY: I/ IDlYlSlON APPROVAL: ,., 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: 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 information, 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 [ NOTICE TO PUBLISHER , ADVERTISINC ORDER ~0. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFF,DAV,T OF PUB.,CAT,ON (P^RT 2 OF..,S FORMI W,TH ^~AC.EO COP~ OF A O'0221 4001 ORDER ADVERTISEMENT MUST BE SUBMI'FI'ED WITH INVOICE SEE BOTTOM FORINVOICE ADDRESS ~ · FAOGCC AGENCY CONTACT DATEOFA.O. R 333 West 7th Avenue, Suite 100 Jodv Colombie July 2. 200] o Anchorage, AK 99501 PHOI~E PCi~ M - (90% 793 -122 l i~ATE~ ADVERTISEMENT REQUIRED: t Anchorage Daily News July 5, 2001 o P O Box 149001 Anchorage, AK 99514 ThE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE division. THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION Before me, the undersigned, a notary public this day personally appeared MUST BE SUBMI'I-I'ED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 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) AO.FRM Page 2 PUBLISHER Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 7/5/2001 AD # DATE PO PRICE OTHER OTHER GRAND 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 Solivan, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it wasp. ublished in regular issues (and-riot in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of safd period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private in&~idua*l . ~, ('~ ~ .,--. Signed~~__~ Subscribed and sworn to me before this date: Notary Public in anti for the State of Alaska. Third Division. Anchorage, Alaska ,. . S...'.~rrr,,. · ,Notice 0i PUblic Hearing . STATE OF ALASKA , AlaSka' Oil and Gas Con- servation, C0rntnlssio9 :~,Re: Northstar O11 POoh :N or,t h,sta~r Fl,eld-POol BP Expl'orotlon. '(A'ioska)', .Inc.' by letter '.:_doted june. 26,...12001.,. has ~hP~l' ed f0r~ Po~l 'rUle%' and' cr .x-ct: -,:~rt'~.-'c~,." ,,nth:.r 2:. ;,,;~'~ }.16.. :;"'.' t" =b~. .',, V ~t.(: I,. I;"'.J :~ii::i%~if~'.:'k~Iy ~ f.' Unit, offshore in the.. '. Beaufort Sea 'of. Alaska. The commission has public .heotin~ On ~Ogus't..16; 2001. Of 9:00am ot..the AlosRa Oil '.Co'nservoHon .:' SiOn at 333 West 7th Av- ~'n. ue, Sulte'.100, Anchor- .age;Alaska. In aclditJon, a pet. son may 'SUbmit' .wr.i.t*en c.-,,-,me,,t.~' re- ~{;r{],llCl ":.} ,);~(', r. (.:: Or p'~eter.Services or other accommodations, call (907) 793;1221 'before Au- gust 9, 2001.. ' ,' Cammy Oechsl Taylor . Chair ' Pub: 'July 5, 200i 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 information, interpreter services or other accommodations, call (907) 793- 1221 before August 9, 2001. Cammy Oechsli Taylor Chair Published July 5, 2001 ADN AO# 02214001 of the above was f~tx~ each of the fol~k:~ng~, at their addresses of record:/-~ ~ ,~/o/~ t ~ 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 govem 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 information, interpreter services or other accommodations, call (907) 793- 1221 before August 9, 2001. Chair Published July 5, 2001 ADN AO# 02214001 of the above was faxed/mailed to each of the following at their addresse~ of PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION P O BOX 2221 NEW YORK, NY 10163-2221 OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 DPC, DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 AMOCO CORP 2002A, LIBRARY/INFO CTR P O BOX 877O3 CHICAGO, IL 60680-0703 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 ALFRED JAMES Ill 107 N MARKET STE 1000 WICHITA, KS 67202-1811 MURPHY E&P CO, ROBERT F SAWYER P O BOX 61780 NEW ORLEANS, LA 70161 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYET.TEVILLE, AR 72701 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 IOGCC, P O BOX 53127 OKLAHOMA CITY, OK 73152-3127 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 OIL & GAS JOURNAL, LAURA BELL P O BOX 1260 TULSA, OK 74101 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 BAPI RAJU 335 PINYON LN COPPELL, TX 75019 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 DEGOLYER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 STANDARD AMERICAN OIL CO, AL GRIFFITH P O BOX 370 GRANBURY, TX 76048 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 SHELL WESTERN E&P INC, G.S. NADY P O BOX 576 HOUSTON, TX 77001-0574 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 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 P O BOX 4813 HOUSTON, TX 77210 UNOCAL, REVENUE ACCOUNTING P O BOX 4531 HOUSTON, TX 77210-4531 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 P O BOX 4778 HOUSTON, TX 77210-4778 EXXON EXPLORATION CO., T E ALFORD P O BOX 4778 HOUSTON, TX 77210-4778 CHEVRON USA INC., ALASKA DIVISION ATTN: 'CORRY WOOLINGTON P O BOX 1635 HOUSTON, TX 77251 PETR INFO, DAVID PHILLIPS P O BOX 1702 HOUSTON, TX 77251-1702 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 WORLD OIL, DONNA WILLIAMS P O BOX 2608 HOUSTON, TX 77252 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 P O BOX 2180 HOUSTON, TX 77252-2180 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 P O BOX 2180 HOUSTON, TX 77252-2180 PENNZOIL E&P, WILL D MCCROCKLIN P O BOX 2967 HOUSTON, TX 77252-2967 CHEVRON CHEM CO, LIBRARY & INFO CTR P O BOX 2100 HOUSTON, TX 77252-9987 MARATHON, Ms. Norma L. Calvert P O BOX 3128, Ste 3915 HOUSTON, TX 77253-3128 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 PHILLIPS PETR CO, PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TEXACO INC, R Ewing Clemons P O BOX 43O BELLAIRE, TX 77402-0430 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 INTL OIL SCOUTS, MASON MAP SERV INC P O BOX 338 AUSTIN, TX 78767 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 GEORGE G VAUGHT JR P O BOX 13557 DENVER, CO 80201 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 C & R INDUSTRIES, INC.,, KURT SALTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC, RICHARD NEHRING P O BOX 1655 COLORADO SPRINGS, CO 1655 80901- RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 MUNGER OIL INFOR SERV INC, P O BOX 45738 LOS ANGELES, CA 90045-0738 LA PUBLIC LIBRARY, SERIALS DIV 63O W 5TH ST LOS ANGELES, CA 90071 BABSON & SHEPPARD, JOHN F BERGQUIST P O BOX 8279 VIKING STN LONG BEACH, CA 90808-0279 ANTONIO MADRID P O BOX 94625 PASADENA, CA 91109 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 TEXACO INC, Portfolio Team Manager R W HILL P O BOX 5197x Bakersfield, CA 93388 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 ECONOMIC INSIGHT INC, SAM VAN VACTOR P O BOX 683 PORTLAND, OR 97207 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151 ST #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 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 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 DEPT OF REVENUE, BEVERLY MARQUART 550 W7"I'H AVSTE570 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 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 GAFO, GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF REVENUE, OIL & GAS AUDIT FRANKPARR 550 W 7TH AVE STE570 ANCHORAGE, AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 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 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JULIE HOULE 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 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 BRISTOL ENVIR SERVICES, JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 HDRALASKAINC, MARK DALTON 2525CST STE305 ANCHORAGE, AK 99503 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 ANADARKO, MARK HANLEY 3201 C STREET STE603 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 ARLEN EHM GEOL CONSLTNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800KUPREANOF ANCHORAGE, AK 99507 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 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 UOA/ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508.4302 GORDON J. SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, FRANK MILLER 949 E 36TH AV STE 603 ANCHORAGE, AK 99508-4363 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH AV STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, LIBRARY 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 CIRI, LAND DEPT P O BOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 ANCHORAGE TIMES, BERT TARRANT P O BOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER P O BOX 10036 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, JOANN GRUBER ATO 712 P O BOX 1O036O ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR ATO 1968 P O BOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON P O BOX 102278 ANCHORAGE, AK 99510-2278 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 P O BOX 196105 ANCHORAGE, AK 99510-6105 ALYESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ALYESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY P O BOX 149001 ANCHORAGE, AK 99514 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 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 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 DAVID CUSATO 600 W 76TH AV #508 ANCHORAGE, AK 99518 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL P O BOX 190754 ANCHORAGE, AK 99519 JACK O HAKKILA P O BOX 190083 ANCHORAGE, AK 99519-0083 ENSTAR NATURAL GAS CO, BARRETT HATCHES P O BOX 190288 ANCHORAGE, AK 99519-0288 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON P O BOX 196168 ANCHORAGE, AK 99519-6168 MARATHON OIL CO, LAND BROCK RIDDLE P O BOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, P O BOX 196247 ANCHORAGE, AK 99519-6247 UNOCAL, KEVIN TABLER P O BOX 196247 ANCHORAGE, AK 99519-6247 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 1966O1 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, SUE MILLER P O BOX 196612 M/S LR2-3 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, PETE ZSELECZKY LAND MGR P O BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 P O BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, MR. DAVIS, ESQ P O BOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM O VALLEE PRES PO BOX 243O86 ANCHORAGE, AK 99524-3086 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE ClR EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER P O BOX 772805 EAGLE RIVER, AK 99577-2805 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 RON DOLCHOK P O BOX 83 KENAI, AK 99611 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P O DRAWER 66 KENAI, AK 99611 DOCUMENT SERVICE CO, JOHN PARKER P O BOX 1468 KENAI, AK 99611-1468 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN P O BOX 3029 KENAI, AK 99611-3029 NANCY LORD PO BOX 558 HOMER, AK 99623 PENNY VADLA P 0 BOX 467 NINILCHIK, AK 99639 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 , JAMES GIBBS P O BOX 1597 SOLDOTNA, AK 99669 PACE, SHEILA DICKSON P O BOX 2018 SOLDOTNA, AK 99669 KENAI NATL WILDLIFE REFUGE, REFUGE MGR P O BOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ PIONEER, P O BOX 367 VALDEZ, AK 99686 ALYESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK P O BOX 300 MS/701 VALDEZ, AK 99686 VALDEz VANGUARD, EDITOR P O BOX 98 VALDEZ, AK 99686-0098 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 RICK WAGNER P O BOX 60868 FAIRBANKS, AK 99706 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY P O BOX 70710 FAIRBANKS, AK 99707 C BURGLIN P O BOX 131 FAIRBANKS, AK 997O7 FRED PRATT P O BOX 72981 FAIRBANKS, AK 99707-2981 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 K&K RECYCL INC, P O BOX 58055 FAIRBANKS, AK 99711 ASRC, BILL THOMAS P O BOX 129 BARROW, AK 99723 RICHARD FINEBERG P O BOX 416 ESTER, AK 99725 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL P O BOX 755880 FAIRBANKS, AK 99775-5880 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 #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 0il & Gas Cons. Commission Anchorage Reference: Northstar - Application for Area 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)(10) 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. 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. Sincerely, Enc: Application (6 copies each of confidential and public information versions) cc: Jeff Walker, MMS (w/3 copies of each enclosure) Pat Pourchout, DNR (w/1 copy of each enclosure) Mark Meyers, DNR (w/3 copies of each enclosure) Buford Bates, Murphy (w/1 copy of each enclosure) Bob Gage, Murphy (w/1 copy of each enclosure) Greg Mattson, BPXA (w/1 copy of each enclosure) PUBLIC INFORMATION Northstar Unit, Beaufort Sea, Alaska Application To AOGCC For Approval Of Pool Rules And Area Injection Order BP Exploration (Alaska)Inc. June 25, 2001 PUBLIC 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 ................................................................................................................. 23 5. Well Operations ..................................................................................................... 27 6. Area Injection Order Application ............................................................................. 33 7. Proposed Area Injection Order Rules ..................................................................... 37 8. Proposed Pool Rules ............................................................................................. 39 PUBLIC INFORMATION Exhibit 1. Exhibit 2. Exhibit 3. Exhibit 4. Exhibit 5. Exhibit 6. Exhibit 7. Exhibit 8. Exhibit 9. Exhibit 10. Exhibit 11. Exhibit 12. Exhibit 13. Exhibit 14. Exhibit 15. Exhibit 16. Exhibit 17. Exhibit 18. Exhibit 19. Exhibit 20. Exhibit 21. Exhibit 22. Exhibit 23. Exhibit 24. Exhibit 25. Exhibit 26. Exhibit 27. Exhibit 28. Exhibit 29. Exhibit 30. Northstar Northstar Northstar Northstar Northstar Northstar Northstar Type Log Type Log Type Log Type Log Type Log Chemical Northstar Northstar Northstar Northstar Northstar Northstar Northstar List of Exhibits Pool Location Map (confidential) Injection Area Map Injection Area Description Type Log - Seal A-01 Isopach Map (confidential) Reservoir Structure and Development Well Location Map (confidential) Cross Sections (confidential) - Northstar 1 (confidential) - Seal A-01 (confidential) - Seal A-02A (confidential) - Seal A-03 (confidential) - Seal A-04 (confidential) composition of Seal A-01 Formation Water Sample Miscible Gas Flood 65 mbd Plateau Rate (confidential) W aterflood (confidential) Gas Cycling (confidential) Primary Depletion (confidential) Miscible Gas Flood 72 mbd Plateau Rate (confidential) Miscible Gas Flood 90 mbd Plateau Rate (confidential) Simplified Process Flow Diagram Northstar Facilities Seal Island General Layout Slimhole Producer Wellbore Diagram Bigbore Producer Wellbore Diagram 7" Injector Wellbore Diagram 5-1/2" Injector Wellbore Diagram Pre-produced Injector Wellbore Diagram Northstar Injection Fluid Compositions (confidential) Affadavit of Notice to Surface Owners Northstar Pressure Gradients (confidential) Northstar Oil and Gas Composition (confidential) 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 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 30CFR250.114 and enhanced oil recovery pursuant to 30CFR250.1107. 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 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° APl. Initial gas oil ratios ("GOR") 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 ("EOR") 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 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 ('q'VDss"). 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 ~ 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 ~ feet thick. The Shublik B lies below the Shublik A and consists of phosphatic limestones and is approximately ~ feet thick. The Shublik C lies below the Shublik B and consists of limestones grading downward into interbedded shales and siltstones and is approximately ~ feet thick. The Shublik D lies below the Shublik C and unconformably overlies the Ivishak formation. The Shublik D is approximately ~ 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 ~ 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 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 D 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. An isopach map of the Ivishak reservoir is shown as Exhibit 5. 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 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 6/25/2001 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-I, 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-I). 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 poro-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-I). 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 Iow 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 ~ 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 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 PUBLIC INFORMATION Property I Units I Sag RiverOil I Sag River Gas Bulk rock volume ft3 N/G ratio % sw % --/ l-- Porosity % --1 1- 1/Formation volume factor stb/rb --I l-- 1/Formation volume factor Bbl/mcf --I l-- Hydrocarbon pore volume ,n reservoir ft3 J~l_ _~l_ OOlP MMbbls OGIP 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 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 ~ Page 11 Northstar Pool Rules and Area Injection Order Application 6/25/2001 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 Iow 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 PUBLIC INFORMATION Conglomerates: Sw - Sandstones: Sw = Where: Sw -- Water saturation (v/v) 2~= 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 ~ g/cc. Page 13 Northstar Pool Rules and Area Injection Order Application 6/25/2001 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 PUBLIC INFORMATION Near Water-Oil Near Gas-Oil Fluid Property Contact Contact Oil APl Gravity (Degrees APl) ~ ~ 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) ~~ ~-- 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'D 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 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 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 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 I-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 ~ 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. Miscible Gas Injection Waterflood Gas Cycling Primary Depletion Oil NGL Total Liquid RF 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 PUBLIC INFORMATION either gas cycling or waterflood. The project is being implemented concurrent with field startup to deliver maximum benefit. Water alternating with gas ("VVAG") 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 ~ 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 O01P. 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 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 Iow 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 100% 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 PUBLIC INFORMATION year of the project we would like to maintain the option of exceeding 100% 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 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 Iow 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 Iow 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 6/25/2001 PUBLIC INFORMATION Plateau Rate 65 MBOPD 72 MBOPD 9O MBOPD Total Liquid Produced Produced Injected Gas Water Gas 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 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 Iow 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 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 Iow 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: I . . , . All wells will be tested monthly. The stabilization and duration of each test will be optimized by the operator to obtain a representative test. Well and field operating condition information required for the construction of a field production history will be maintained. Test separator meters and major gas system meters will be installed and maintained according to industry recommended practices or standards. 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 PUBLIC INFORMATION . . , . , Gas injection will be started prior to opening production chokes. This will minimize flaring of primary stage separation off gas during plant startup. Gas will be flared from Iow pressure separators only long enough for gas flows to stabilize at a rate sufficient for startup of the multistage LP Compressor. 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 250.1105(a)(2)(i). 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. 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 Sm 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 20AAC25.030(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 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 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 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 5Y2-inch L-80 tubing and liners. The sixteen production wells will be completed with 4~/~-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. APl 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 TD 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. 7th 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 PUBLIC INFORMATION Phillips Alaska, Inc. 700 G Street P.O. Box 100360 Anchorage, AK 99510-0360 AVCG 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 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. injection pressure at the wellhead is estimated to be 5000 psig. The average 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 m 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 37 Northstar Pool Rules and Area Injection Order Application 6/25/2001 PUBLIC 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 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 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 classification The field is the Northstar Oil Field and the pool is the Northstar Pool. classified as an Oil Pool. The Northstar Pool is 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 completed from a single well. is Page 39 Northstar Pool Rules and Area Injection Order Application 6/25/2001 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 TD 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 Obp ' NORTHSTAR POOL i i ii i i i i Exhibit 2 i ii <~]) Northstar Unit Tract Number '------ Norfl-~ar Unit Boundary (Ex:pansion .Applicafi(m Pending) Norlhstar Pool Area o I 2 Miles dE) T12N i 1 ADL355001 Ii' 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., Ri 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. Section 17 Section 18 Section 19 Section 20 Section 25 Section 26 Section 27 Section 28 Section 29 13 E., Umiat Meridian, Alaska Protracted, Protracted, Protracted, Protracted, Protracted, Protracted, Protracted, Protracted Protracted All, 640 acres; All, 631 acres; All, 633 acres; All, 640 acres; All, 640 acres; All, 640 acres; All, 640 acres; All, 640 acres; All, 640 acres. Exhibit 3 Federal Leases Description of Northstar Injection Area 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 nodheasterly 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 .,, I Mirrored Sonic Stratigraphy GR (APl) TVD ILM-DIL 94 59 59 94 ~ Confining zone I~~ Shales and silts. : ~~ .';..*;i.;, ,.;I~.; i::' Transgressive :!: I~~ Marine Sands, silts ~' :!'i and shales. Low -10700-i.e. 'e°. ~ [. ~ :?N ::! j_;_*;-_;.- ;_.;-_; permeability i ~ [':!:i~i/!.!. ~ Marine silts and shales. ~ :~;..'.;:'cl';~~~~..~ ~ ~. ~ ~ Phosphatic limestones. ~ i!?!:::~::i}i?:"~ ' '1 ~ Limestones, silts ::i..:'!:;::~i'.!.r:~:?; !;~~.:~,,.~.... I;__-.*-~-~.'_~:-'. .&,-, ~ ~ and shales. ::i!{:iii!:;i!{; :ii,!i:;,~'.~"lC~.~'I~RI~I~Pe~INP : '? I :,: Mixed gravel/sand & rned cong ; ;!i:~?,!i~ ::i::~:l:!~D Massive, pebble/ ::!?~iii.l:!~[ cobble dense cong. ~:'i?'''~ ,', ? i!i! ~, , Medium co..,omera,e I::,!ii;[9!:;:=!!~,~;~ ~ and variably pebbly :~ ;:"?,"~"'[:E?!!![ "*""'"*~" ,'.:',',,':~ 'I ~ ~ Medium . ~ ~?~.~?/,~C2 conglomerate ~ :?=?.~'?i?~l:~ and variably pebbly ~:,',:'=~:~;~I'~E C ~ ~ Medium ':~,,,~:~.,,:1 ~~ . ......... ~ co.~o~er~e i::::~:~f.'.l ~]~,~ and variably pebbly ,~: ,~.~ ~.. ,~. o ~ ,~::,~'~:,:1~{~ -' ~E??~ F-m sand w/occ. ~ :~;~,,,,~'::~i~,,~~ 0 -- ''~:' ...... ~'E~ ';~':~ pebbles ~ ,,:,>,,!~~ A2 ......... ~ne ~o ~e~u~ sa.~. -,, .... t ....... ,.,, , ~ ,~'~, ~,,' ..... '~'" ~:*~'~ I.' ' ' ' ~ . I ~'~~ ~ I:~.,~a~: Ve~ fine to fine sands. '*'"'?~c':~;?:'~l*'.~'J~i~;~ '~12.,~ Prodel~a shales. ~,,, ,,~ = [~ ',~, ~ ~ ,. ,,~ ~ . ...... ~, ~ =~ E~. v~ Fa. -.. ::~;~,~~ I~~ Sand, silt and shale. Lisburne I~ r~'""'" ~oup l~ ~ ' , ' , ,~ Carbonates Exhibit 13 Chemical Composition of Seal #1 Formation Water Sample Component Concentration (mgll) Ca 575 Mg 12 Na 7540 Fe 115 Ba 1 CI 11800 HO03 1425 S042 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 20 Northstar Simplified Process Flow Diagram INCOMING loo rrrrscfd GAS~=,~..PIPELINE3a,F I .1 FUEL , ~ ~ ~ ~ "~' "~' ~: SEPA~TOR 5 GAS INJECTORS ~. -- ,... r~OO~R, r-~l_ ~-~--L_lr~ ~ I f GLYCOL INLET ~ I~- SCRUBBER :i/ / ~ :'i OLYCOLINLET i ~ L FILTER/SEP · ~. ~ 16 OIL PRODUCERS · SLOP OIL , _~:L___ ~ 8' 5 mbd r--~. j WELL CLEAN ',, SKIMMER UP TANK I 3000 psi % ~.--_ ,, £_..) ~ i -,,:, :-..-.: ~,'~ I """"~" ~'~,~-'"' i WATER , , ,, , r'._- ~--~-.'-,~ ;-:,'~. I ', .--~ .? -.-' ~' o '~I 2950 p~l , .. : ; ' SURGE TANK CLASS 1 DISPOSAL WELL GRIH~ AHD INJECT FACILITY TEMPERA1TIR~ F PRE~SURE ~ OIL GAS WATTR NGLs DRAINS/SLOPS GLYCOL IMPORT~$ E--" i SEWAGE i' ~( '.-'-'~ ~ TREATMENT! , Disharge ~ sea [NORm DRAINAGE SUMP t' '.,,, L_MODULE! ..... ,, PROCESS MODULE [ STOP~.GE PLATFORM !. (40 CONNEX UNITS) "' .. PUMP HOUSE ] !'UTIUT~' MODULE t [L._t,¥!NG Q__U~A, RTE RS JHELiPAD J ................................................................................................... "" j 's~.^W^T~ ! '"" tNTAKE j {DRILL RiG ...... SERVICE ", ~BUILDtNGS i /DRILL RIG & ,-~ SERVICE t BUILDINGS Northstar Facilities Seal Island General Layout Exhibit 21 TREE: WELLHEAD: Exhibit Slimhole Producer !v,~IGINAL KB. ELEV = BF. ELEV = CB. ELEV = @2000' 13 3/8", 68#/ft, L-80. BTC @ 4.5" GLM 3.813" ID @ 3000' ~6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 4.5", 12.6#/ft, 13-Cr, Vam Ace TUBING ID: 3.958" CAPACITY: .0152 BBL/FT 9-5/8" 47#/ft, L-80, BTC-M @ DATE 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 COMMENTS Baker S3 PACKER 3.875" ID @ 4.5" LINER TOP @ 4.276" ID 4.5", 12.6#, 13-Cr Vam Ace Northstar APl NO; BP Exploration (Alaska) TREE: _~,IGINAL KB. ELEV = WELLHEAD: Exhibit Big Bore Producer BF. ELEV= "'-- "~ .... CB. ELEV = ~ [----'--'] SSSV @2000' ! i 4.5" GLM I I, ID @2200' _ [__ !__.6.8PPG DIESEL FREEZE I PROTECTION AT +/- 2200 13 3/8", 68#/ft, L-80, BTC (~ 4.5", 12.6#/ft, 13-Cr, TUBING ID:" CAPACITY: BBL/FT I 4.5" X NIPPLE, (~ I_I iI "ID (OTIS) 4.5" X NIPPLE, (~' PACKER "ID (OTIS) ~ II 4.5" XN NIPPLE, (~ ~ "ID (OTIS) 4.5" WLEG, @ ~ _.~1 I "ID (OTIS) 9 5/8", 47#/ft L-80, BTC-M (~ , PBTD (~ -- ~ '~ 4.5", 12.6#, 13-Cr TD @ DATE REV. BY COMMENTS I Northstar ...................................................I WELL: ., /~PI NO: Bp Exploration (Alaska) i ~) ~' ,.,P, IGINAL KB. ELEV = TREE: Exh ,[24 Big Bore Injector WELLHEAD: BF. ELEV = I CB. ELEV = SSSV @2000' ~ 7" HRQ SVLN 5.963" ID I .... 6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 13 3/8", 68#/ft, - L-80, BTC @ I I 7", 29#/ft, L-80, TUBING ID: 6.184" CAPACITY: 0.037 BBL/FT i I I i I i 7" R NIPPLE, (~ 5.963" ID (OTIS) I I 7" RNIPPLE,(~'~~ ~'~ Baker SABL-3 PACKER, 5.963" ID (OTIS) 7" RN NIPPLE, @ ~ ~! I 5.5" ID (OTIS) 7" WLEG, @ ~ ~__~1 I~i~ 7" LINER TOP (OTIS) 6.188" ID 9 5/8", 53.5#/ft L-80, BTC-M (~ , ! i , i ; ' I PBTD@ TD @ : 7", 26#, L-80 DATE REV. BY COMMENTS Northstar APl NO: BP Exploration (Alaska) I I TREE: WELLHEAD: Exhibit(' Slimhole Injector dGINAL KB. ELEV = BF. ELEV = CB. ELEV = @2000' 10 3/4", 45.5#/ft, L-80, BTC @ ~.6.8PPG DIESEL FREEZE PROTECTION AT +/- 2200 5.5", 17#/ft, L-80, TUBING ID:" CAPACITY: BBL/FT 5.5" X NIPPLE, @ "ID (OTIS) 5.5" X NIPPLE, @' "ID (OTIS) ~ 5.5" XN NIPPLE, (~ "ID (OTIS). 5.5" WLEG, (~ "ID (OTIS) 7 5/8", 29.7#/ft L-80, BTC-M @ PBTD @ TD @ PACKER ID@ 5.5" LINER TOP ~ 5.5", 17#, L-80 DATE REV. BY COMMENTS Northstar .~/Y_E,L ~,; ..... APl NO; BP Exploration (Alaska) 2 Pre-Produced Big Bore !. ,_,~IGINAL KB. ELEV = TREE: Exhibit b Ini~f~r WELLHEAD: BF. ELEV CB. ELEV = L"'--'--. .SSSV @2000' I 7" HRQ SVLN 5.963" ID __.6.8PPG DIESEL FREEZE i ~' PROTECTION AT +/- 2200 13 3/8", 68#/ft. ~-- L-80, BTC (~iI i i 7", 29#/ff, 13Cr, i -- TUBING ID: 6.184" I I CAPACITY: 0.037 BBL/FT : , i i 7" R NIPPLE, (~ 5.963" ID (OTIS) I I 7" R NiPPlE, @' ~ ~ ~ PACKER 5.963" ID (OTIS) 7" RN NIPPLE, @ 5.5"1D (OTIS) 7" WLEG, "ID (OTIS) I 6.184" ID 9 5/8", 53.5#/ft L-80, BTC-M ~;~~ ~ [ I i I TD @ 7", 29#, 13Cr , DATE I REV. BY COMMENTS Northstar AP! NO- BP Exploration (Alaska) 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 June,~', 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. 7th Avenue, Suite 800 Anchorage, AK 99501 Mark Meyers, Director Division of Oil & Gas Department of Natural Resources State of Alaska 550 W. 7th 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 E. P. Zseleczky, Land Manager BP Exploration (Alaska) Inc. 900 E. Benson Blvd. Anchorage, AK 99508 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: Buford Bates Murphy Exploration (Alaska) Inc. 550 WestLake Park Bivd'., Suite 1000 Houston, TX 77079 Affidavit of K. Crandall Page 1 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. Managing Partner AVCG LLC 225 N. Market, Suite 300 Wichita, KS 67202 Jim Ruud, Land Manager Phillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 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. Krissell Crandall STATE OF ALASKA THIRD JUDICIAL DISTRICT th~s 4:::>~5 '~ fJun 20 SUBSCRIBED AND SWORN to before me 'o ,..- --.- ].~y,,., e, 01. Notary Public in and for Alaska My Commission Expires:. Affidavit of K. Crandall Page 2 :tEA- LEASE STATUS EFFECTIVE MARCH 31, 2001 Exhibit 28 1 !oo,oo ~ !oo~oo 6,000 12.000 Melem ALEERS EQUAL AREA/NAD27 ~ lOO.~O alex loo. o0 R 'Too. IX) 13-31-04 10-31439 ~ l(]~x] ~ 1o0~0 10-e14~, -;': .. AD~388610 · . j.-'.:'Y~ ede-:>:' .... 100.00
