3001 Porcupine Drive
Anchorage, Alaska 99501-3192

Re: The Application of BP Exploration (Alaska) Inc.       )Conservation Order No. 329
    to present testimony for classification of a new      )
    oil pool and to prescribe pool rules for development  )Prudhoe Bay Field
    of the Niakuk Oil Pool within the Prudhoe Bay Field.  )Niakuk Oil Pool

                                                           January 11, 1994


1. By letter dated September 22, 1993, BP Exploration (Alaska) Inc. requested a public hearing to present testimony for establishing pool rules for development and operations in the Niakuk reservoir.

2. Notice of public hearing to be held on October 28, 1993 was published in the Anchorage Daily News on September 28, 1993.

3. A hearing concerning the matter of the applicant's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 3001 Porcupine Dr. Anchorage, Alaska 99501 at 9:00 am October 28, 1993.

4. ARCO Alaska, Inc. requested the areal limits of the pool be expanded beyond the limits proposed by BP Exploration (Alaska) Inc. (see addendum decision).

5. The hearing was reconvened on November 15, 1993 at 9:00 am.

6. Testimony was offered by BP Exploration (Alaska) Inc., ARCO Alaska, Inc., Exxon Company, U.S.A. and the Alaska Department of Natural Resources, Division of Oil and Gas.

7. The hearing record was closed December 3, 1993.


1. The area planned for development by BP Exploration (Alaska) Inc. and described as the Niakuk reservoir underlies portions of ADL leases 34625, 34630, 34634, and 34635. BP Exploration (Alaska) Inc. is operator and 100% working interest owner of these leases. The State of Alaska is the lessor and 100% owner of the royalty interests.

2. ARCO Alaska, Inc. requested that the pool rules area include portions of ADL 34626 and ADL 34629, to which BP Exploration (Alaska) Inc. objected. The Commission's decision concerning ARCO Alaska, Inc.'s request is an addendum to this order.

3. The Niakuk 5 and Niakuk 6 wells, drilled on ADL 34635, tested hydrocarbon production from the Kuparuk River Formation at oil rates between 1800 and 4800 BO/D.

4. The Niakuk 1 and 1A wells, drilled on ADL 34630, encountered measurable hydrocarbon saturation in the Kuparuk River Formation, but the wells were not tested.

5. The Niakuk 6 well contains the entire stratigraphic interval for the Kuparuk River Formation, which occurs between 9351 feet TVD subsea and 9842 feet TVD subsea.

6. The Prudhoe Bay Unit encompasses the BP Exploration (Alaska) Inc. leases proposed for development.

7. Lateral heterogeneity and abrupt facies change characterize the Kuparuk River Formation in the area planned for development by BP Exploration (Alaska) Inc.

8. Numerous moderate displacement normal faults cut the Niakuk reservoir.

9. The Niakuk reservoir contains two elongated, oil-bearing segments that do not appear to be in hydraulic communication. Normal faults bound the two segments on the north and south.

10. The western segment (Segment 1) contains approximately 545 acres. An inferred depositional pinch out marks the eastern limit of Segment 1. The western limit of the oil accumulation is uncertain.

11. The eastern segment (Segment 2) contains approximately 1,310 acres. Structural dip and the oil-water contact controls the eastern limit of Segment 2. A depositional pinch out of the reservoir marks the western limit of Segment 2.

12. The following are rock properties for the Kuparuk River Formation determined by analysis of log, core and test data from the Niakuk 1, Niakuk 1A, Niakuk 2, Niakuk 2A, Niakuk 5, and Niakuk 6 wells.


Segment 1




Oil Saturation

Zone 3


6-1250 md



Zone 4


6-1250 md




Segment 2


Zone D


1-1169 md.



Zone F


1-3008 md



13. Fluid properties are based on reservoir fluid samples from Niakuk 5 in Segment 2. Initial reservoir pressure is 4461 psia at 8900' TVD subsea. Bubble point pressure is estimated at 3835 psia. Reservoir temperature is 181oF. Oil gravity measures 24.9o API, viscosity 1.4 centipoise and oil formation volume factor 1.31 RB/STB at bubble point pressure.

14. A gas-oil-contact (GOC) has not been identified in the Niakuk wells.

15. The oil-water contact (OWC) is estimated at 9244' TVD subsea in Segment 1 and at 9520' TVD subsea in Segment 2.

16. Estimated original oil in place (OOIP) for the Niakuk reservoir is 137.4 MMSTB (56.1 MMSTB in Segment 1 and 81.3 MMSTB in Segment 2) and original gas in place (OGIP) is 90.9 BSCF.

17. The Niakuk reservoir will be developed from a drill site constructed at Heald Point. Well testing facilities will be installed at the Niakuk drill site.

18. The operator proposes to set conductor casing to 80 feet below pad level in compliance with 20 AAC 25.030.

19. The operator proposes to set surface casing no deeper than 5000 feet TVD in compliance with 20 AAC 25.030.

20. Permafrost is present in the Heald Point area to a depth of 1900 feet.

21. No hydrocarbons or abnormal pressures have been encountered above 5000' TVD subsea in the Niakuk wells drilled to date.

22. The operator proposes to install fail-safe, automatic surface and subsurface safety valves (SSV's & SSSV's) in all wells capable of unassisted flow of hydrocarbons.

23. The Commission may require SSV's and SSSV's in wells capable of unassisted flow of hydrocarbons in areas deemed appropriate under 20 AAC 25.265.

24. In certain cases, the SSSV's must be removed temporarily to allow passage of certain equipment and performance of well maintenance.

25. A total of 9 producers and 5 injectors are currently planned for the Niakuk reservoir.

26. The operator proposes to commingle production from Niakuk wells with production from other oil pools for processing at the Lisburne Production Center (LPC).

27. The Commission has previously approved surface commingling of Lisburne, Pt. McIntyre, Stump Island and West Beach production for processing through the LPC.

28. The operator testified that commingling production and utilizing existing production facilities extends field life and reduces capital investments and per barrel operating costs for small hydrocarbon accumulations.

29. The operator estimates that 100 million additional barrels of oil will be recovered by allowing commingled production from Niakuk, Pt. McIntyre, Stump Island, West Beach and Lisburne reservoirs.

30. BP has reached agreement with the Lisburne working interest owners to commingle Niakuk production with production from the Lisburne, Pt. McIntyre, West Beach and other fields within the area defined as the "Greater Pt. McIntyre Area" (GPMA).

31. Monthly well tests will be used to allocate production to each producing well. The operator proposes to test each well twice monthly, conditions permitting. Optimum well test stabilization and duration times will vary from well to well and may change with time.

32. NGL's will be allocated based on gas volume produced and computer simulated process yields.

33. The Lisburne Data Gathering System (LDGS) will be utilized to monitor the flowing status, pressures and temperatures of Niakuk wells.

34. Process capacities at LPC will be increased from 100 to 135 MB/D oil and from 25 to 200 MB/D water. Gas processing capacity is expected to remain at 460 MMSCF/D. Facility expansions are expected to be completed in 4th Quarter 1994.

35. Initial share of process capacity at the LPC among commingled pools will be based on producing gas-oil ratios.

36. The operator proposes to determine reservoir pressure with initial and periodic surveys on each well using a datum of 9200' TVD subsea.

37. The operator will use production logs, including flow meters, temperature and other diagnostic tools, to study reservoir performance.

38. Produced gas allocated to Niakuk, less gas sold or used for lease purposes, will be injected into the Lisburne oil pool.

39. The operator proposes to initiate waterflooding within one year after commencement of regular production.

40. The operator does not expect to create moveable gas saturations before commencement of waterflood.

41. Primary recovery mechanism for the Niakuk reservoir is solution gas drive. Model studies indicate expected recovery for primary depletion is 4% of OOIP.

42. Estimated recovery with waterflooding is 40% of OOIP.

43. The operator's model indicates that delaying waterflood one year after regular production will not harm ultimate recovery.

44. The operator proposes initial waterflood injection rates greater than voidage rate to provide pressure support and increase reservoir pressure above bubble point pressure.

45. Initially, produced water will be injected in the LPC Cretaceous disposal wells.

46. Regular production is expected to start in April 1994, at approximately 15 MB/D and rise to 23 MB/D in April 1995.

47. Offtake rate and waterflood sensitivity studies indicate no impact on ultimate recovery using rates from 15-20 MB/D and starting waterflood within one year of initial production.

48. BP Exploration will operate the Niakuk reservoir, conducting facility construction, drilling, well operations and reservoir management. ARCO Alaska, Inc., as operator of the LPC, will provide well testing and production allocation support functions.


1. Commercially exploitable hydrocarbons are present within two separate segments in an area planned for development by the operator and described as the Niakuk reservoir.

2. Pool rules for the development of the Niakuk reservoir are appropriate at this time.

3. An integration of interests for the area contemplated for development by the operator exists between the working interest owner and royalty owner.

4. The vertical limits of the Niakuk reservoir may be defined in the Niakuk 6 well which appears to be a typical and representative well.

5. Optimum well spacing will depend on reservoir properties and sweep efficiency.

6. Statewide well spacing does not allow sufficient latitude in the selection of well locations because of the elongate shape, small size, and structural and stratigraphic complexity of the reservoir.

7. Other than establishing setting depths, the operator is not requesting variance from statewide casing and cementing requirements.

8. The Heald Point drillsite is an onshore location.

9. Because of the proximity of the Heald Point drillsite to the Beaufort Sea, the use of fail-safe, automatic surface and subsurface safety valves are appropriate and may contribute to safe production operations

10. Surface commingling of Niakuk production with Lisburne, Pt. McIntyre, Stump Island and West Beach production will increase ultimate recovery, will not cause waste nor jeopardize correlative rights.

11. Well tests are an appropriate means to allocate produced fluids back to the originating field for revenue and reservoir management purposes.

12. Periodic review of production allocation procedures is appropriate to evaluate techniques and to revise procedures if warranted.

13. Initial management of process capacity at the LPC using producing GOR is appropriate, however, in the event of capacity proration each producing field should be equitably handled.

14. Appropriate reservoir surveillance data will be obtained to plan and optimize primary development, secondary recovery, and reservoir management plans.

15. Exception to gas-oil-ratios is not appropriate at this time because produced gas is not being returned to the reservoir and no additional recovery project is scheduled for the first year of regular production.

16. An exception to 20 AAC 25.240 may be considered in conjunction with waterflood or if production at more than twice original solution GOR is necessary for acquisition of pool performance data.

17. Waterflood will enhance oil recovery from the Niakuk reservoir.

18. Water injection may not commence until 20 AAC 25.402 and .460 are satisfied.

19. Subject to the rules below and statewide requirements, production from the Niakuk 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.

NOW, THEREFORE, IT IS ORDERED THAT the plan of development submitted by BP Exploration (Alaska) Inc. is approved, subject to rules hereinafter set forth and state-wide requirements under 20 AAC 25, for the following affected area.

Umiat Meridian

T12N R15E Section 23 S/2

Section 24 SW/4

Section 25 All

Section 26 All

Section 36 NE/4

T12N R16E Section 28 All

Section 29 All

Section 30 All

Section 31 N/2

Section 32 N/2

Rule 1 Field and Pool Name

The field is the Prudhoe Bay Field. Hydrocarbons underlying the affected area and contained within the Kuparuk River Formation constitute a single associated gas and oil reservoir called the Niakuk oil pool.

Rule 2 Pool Definition

The Niakuk oil pool is defined as the accumulation of oil and gas that correlates with the interval between 12,318 feet and 12,942 feet measured depth in the Niakuk 6 well.

Rule 3 Well Spacing

Upon application of the operator, the Commission may administratively approve the drilling of any well to a bottom hole location greater than 500 lineal feet from the external boundary of the affected area. No well bore may be open to the Niakuk oil pool within 500 feet of the external boundary of the affected area nor within 1000 feet of another well capable of producing from the same pool.

Rule 4 Casing and Cementing

a. A conductor casing shall be set at least 75 feet below the surface. If cemented, cement to surface shall be verified by visual inspection.

b. Surface casing shall be set at least 500 feet MD below the base of the permafrost but not below 5000 feet TVD subsea.

c. Surface casing must have minimum axial strain properties of .5% in tension and .7% in compression to withstand forces generated by thaw subsidence and freeze back in permafrost.

Rule 5 Automatic Shut In Equipment

a. Upon completion, each well shall be equipped with:

i. a fail-safe automatic surface safety valve (SSV) capable of preventing uncontrolled flow.

ii. a fail-safe automatic subsurface safety valve (SSSV), unless other types of subsurface valve are approved by the Commission, shall be installed in the tubing string below the base of the permafrost and be capable of preventing uncontrolled flow.

b. A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no flow" performance test witnessed by a Commission representative, is not required to have fail-safe automatic SSSV's.

c. Safety valves may be temporarily removed for not more than 15 days as part of routine well operations or repair without specific notice to, or authorization by the Commission. The SSV and SSSV may not be simultaneously out of service without specific authorization from the Commission.

i. Wells with SSV's or SSSV's removed shall be identified by a sign on the wellhead stating that the valve has been removed and the date of removal.

ii. A list of wells with SSV's or SSSVs removed, removal dates, reasons for removal, and estimated re-installation dates must be maintained current and available for Commission inspection on request.

d. The Low Pressure Sensor (LPS) systems shall not be deactivated except during repairs to the LPS, while engaged in active well work or if the pad is manned. If the LPS cannot be returned to service within 24 hours, the well must be shut-in at the well head and at the manifold building.

i. Wells with a deactivated LPS shall be identified by a sign on the wellhead stating that the LPS has been deactivated and the date it was deactivated.

ii. A list of wells with the LPS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for Commission inspection on request.

Rule 6 Surface Commingling and Common Facilities

a. Production from the Niakuk oil pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer.

b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats.

i. Conduct well tests to determine production rates for each well.

ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production.

iii. Sum the TMP volume for all wells in all pools.

iv. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP)

v. Calculate each well's actual monthly production (AMP) volume as:

AMP = TMP x Allocation Factor

c. NGL's will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the Commission.

d. Each producing well will be tested at least twice each month. Wells that have been shut in and cannot meet the twice monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing.

e. Optimum test duration and stabilization time will be determined on a well by well basis by the operator.

f. Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission.

g. API gravity will be determined for each producing well annually by an API/MPMS approved method.

h. Gas samples will be taken and analyzed for composition from each non gas lifted producing well yearly.

i. Quarterly allocation process reviews will be held with the Commission.

j. This rule may be revised or rewritten after an evaluation period of at least one year.

Rule 7 Production Anomalies

In the event of oil production capacity proration at or from the LPC, all commingled pools produced at the LPC will be prorated by an equivalent percentage of oil production recognizing mechanical limitations and operational constraints.

Rule 8 Reservoir Pressure Monitoring

a. Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure.

b. A minimum of one bottom hole pressure survey per producing governmental section shall be obtained annually. The surveys in part 'a' of this rule may be used to fulfill the minimum requirements.

c. The datum for all surveys is 9200' TVDss.

d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period.

e. The pressure surveys will be reported to the Commission quarterly on form 10-412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted upon request.

f. Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part 'e' of this rule.

Rule 9 Niakuk Oil Pool Annual Reservoir Report.

A surveillance report will be required within one year of regular production and annually thereafter. The report shall include but is not limited to the following:

a. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters.

b. Voidage balance by month of produced fluids and injected fluids.

c. Analysis of reservoir pressure surveys within the pool.

d. Results and where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys.

e. Results of any special monitoring.

f. Future development plans.

Rule 10 Offtake rate

The offtake rate for the Niakuk oil pool shall not exceed 23 MB/D of oil averaged monthly.

Rule 11 Additional Recovery Project

Within one year of regular production, a waterflood or other Commission approved secondary recovery project must commence.

Rule 12 Administrative Action

Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights or compromise ultimate recovery, and is based on sound engineering principles.

DONE at Anchorage, Alaska and dated January 11, 1994.

David W. Johnston, Chairman
Alaska Oil and Gas Conservation Commission

Russell A. Douglass, Commissioner
Alaska Oil and Gas Conservation Commission

Tuckerman Babcock, Commissioner
Alaska Oil and Gas Conservation Commission

Conservation Order Index