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 Pool, ) Northstar Oil 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 by 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."

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 Prudhoe 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.

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%.

20. 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.

21. 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.

22. Permeability derived from Ivishak Formation drill stem tests is higher than the average permeability derived from core analysis.

23. 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.

24. 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.

25. The NOP OWC is 11,100 feet TVDss, based on core, RFT, MDT and well test data.

26. 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.

27. Well test and core fluorescence data in Northstar #1 Well suggest the Shublik Formation may be gas bearing at that location.

28. 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.

29. 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.

30. 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.

31. 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.

Oil
MMSTB
NGL
MMSTB
Total Liquid
MMSTB
Recovery
Factor
% 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

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.

Fluid Property Near Water-Oil
Contact
Near Gas-Oil
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 0.51
Oil Viscosity (cp) 0.15 0.13
Gas Viscosity Estimated (cp) 0.06 0.07
Water Viscosity Estimated (cp) 0.25 0.26

39. 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.

40. 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.

41. Slim tube simulations indicate the oil compositional gradient has a negligible impact on minimum miscibility pressure ("MMP").

42. Based on initial reservoir simulation results, the Operator's reservoir management strategy during miscible injection is for 100% voidage replacement and to maintain reservoir pressure within +/- 50 psi of the current pressure level, 5180 psi at 11,100 feet TVDss.

43. 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.

44. 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.

45. 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.

46. 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.

47. 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.

48. 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.

Plateau Rate Total
Liquid
(MMSTB)
Produced
Water
(MMBW)
Produced
Gas
(TCF)
Injected
Gas
(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. 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.

50. 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.

51. Production will be allocated to producing wells based on monthly individual well tests and actual plant oil sales volume.

52. The NOP will be accessed by wells directionally drilled from Seal Island.

53. 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.

54. 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.

55. 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).

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 alternative 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.

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 Northstar 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:

STATE LEASES

Umiat Meridian

Township Range Sections
T14N T13E 30 through 35: All State lands
T13N R13E 2 through 18, 20 through 24: All State lands
T13N R14E 17 through 20, 29 and 30: All State lands

The affected area is more particularly described as follows:

ADL 312798

Consists of Tract C30-46 (BF-46), a portion of Blocks 470 and 514 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79, more particularly described as follows:

Those lands located easterly of the west boundary of T.13N., R.13E., and T.14N., R.13E., Umiat Meridian, Alaska, being the north-south line intersecting the north and south boundary of Block 470, within the offshore three-mile arc lines listed as State area of Block 470 "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lands in Block 514 easterly of the west boundary of T.13N., R.13E., Umiat Meridian, Alaska (being identical with line 1-2 of Block 514) and lying northerly of the south boundary of Sections 7 and 8, T.13N., R.13.E, Umiat Meridian, Alaska (being identical with line 2-3 of Block 514) and that portion of Section 16, T.13N., R.13E., Umiat Meridian, Alaska, within the N1/2 S1/2 (being easterly of line 3-4 of Block 514), being a portion of the listed State area of Block 514 on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79.

ADL 312799

Consists of Tract C30-47 (BF-47), a portion of Blocks 471 and 515 as shown on the "Leasing and Nomination map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79, more particularly described as follows:

Those lands located in Block 471 within the offshore three-mile arc lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram", approved 10/4/79, and those lands in 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 of T.13N., R.13E.; Umiat Meridian, Alaska, (being those lands lying easterly of line 3-4 on Block 514), a portion of the state area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, and those lands in S1/2 S1/2 of Block 515, being a portion of the State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lands within Block 558 located in Section 21, T.13N., R.13E.; Umiat Meridian, Alaska, (being the portion easterly of line 1-2 and northerly of line 2-3 block 558), listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, and those lands in Block 559 lying northerly of the south boundary of Sections 21, 22, 23, and 24, T.13N., R.13E.; Umiat Meridian, Alaska, (being the northerly portion of Block 559), listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79.

ADL 312809

Consists of Tract C30-57 (BF-57), a portion of Block 516 and 560 as shown on the "Leasing and Nomination Map" for the Federal/State Beaufort Sea Oil and Gas Lease Sale, dated 1/30/79, more particularly described as follows:

Those lands located in Block 516 within the offshore three-mile arc lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, containing 227.02 hectares, and those lands in Block 560 located within Section 24, T.13N., R.13E., Umiat Meridian, Alaska, and those lands in Block 560 located within Sections 19, 20, 29 and 30 of T13N, 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 of T.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.

OCS-Y-0179

That portion of Block 470 lying east of the line marking the western boundary of parcel "1" and between two lines bisecting Block 470, identified as parcel "1", containing approximately 94.30 hectares, and parcel "2", containing approximately 15.27 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975; and that area lying between the two lines bisecting Block 471, containing approximately 611.95 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975; and that area lying northeasterly of the line bisecting Block 515, containing approximately 189.83 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975.

OCS-Y-0181

That area lying northeasterly of the line bisecting Block 516, containing approximately 2076.98 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975; and that area lying northeasterly of the line bisecting Block 560, located in the northeast corner of Block 560, containing approximately 44.65 hectares, as shown on the Supplemental Official OCS Block Diagram, revised and dated 12/9/79 based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975.

Rule 1: 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 of preventing an uncontrolled flow, unless another type of subsurface valve with that capability is approved by the Commission.

b) 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.

c) 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:

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 hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles and will not result in an increased risk of fluid movement into freshwater.

DONE at Anchorage, Alaska and dated October 9, 2001.

Cammy Oechsli Taylor, Chair
Alaska Oil and Gas Conservation Commission

Daniel T. Seamount, Jr., Commissioner
Alaska Oil and Gas Conservation Commission

Julie M. Heusser, Commissioner
Alaska Oil and Gas Conservation Commission

Conservation Order Index