STATE OF ALASKA

OIL AND GAS CONSERVATION COMMISSION

3001 Porcupine Drive

Anchorage, Alaska 99501-3192

Re: The Application of ARCO Alaska, ) Conservation Order No. 317
Inc. to present testimony for )
classification of new oil pools and to ) Pt. McIntyre Oil Field
prescribe pool rules for development of ) Pt. McIntyre Oil Pool
the Pt. McIntyre Oil Field. ) Stump Island Oil Pool
July 2, 1993

IT APPEARING THAT:

1. By letter dated January 15, 1993, ARCO Alaska, Inc. requested a public hearing to present testimony for establishing pool rules for development and operations in the Pt. Mcintyre oil field, located in T12N, R15E and T12N, R14E Umiat Meridian.

2. Notice of public hearing to be held on March 24, 1993 was published in the Anchorage Daily News on February 5, 1993.

3.A hearing concerning the matter of the applicant's request was held in conformance with 20 AAC 25.540 at the Fairview Community Recreation Center, 1121 East 10th Avenue, Anchorage, Alaska 99501 at 9:00 a.m. March 24, 1993. The hearing record remained open until the close of business May 14, 1993.

FINDINGS:

1. ARCO Alaska, Inc. has been designated operator of the Pt. McIntyre oil field by working interest owners ARCO Alaska, Inc., BP Exploration (Alaska), Inc., and Exxon Corporation.

2. Oil within the Pt. Mcintyre reservoir is trapped in the Kuparuk River and the Kalubik formations. The vertical limits of the Kuparuk River and Kalubik formations may be defined in the Pt. McIntyre No. 11 well, which appears to be a typical and representative well.

3. Oil within the Stump Island reservoir is stratigraphically trapped in discontinuous sandstones of the Seabee formation. The vertical limits of the Stump Island reservoir may be defined in the Pt. Mcintyre No. 3 well, which appears to be a typical and representative well.

4. The Kuparuk River formation is present throughout the Pt. Mcintyre area and is characterized by rapid changes in thickness, lithology, and degree of cementation.

5. The Kalubik formation exhibits abrupt changes in lithology and thickness with oil bearing sandstones restricted to the western portion of the Pt. McIntyre oil field.

6. The Stump Island reservoir is of limited and varied areal extent within the Pt. McIntyre oil field. Development of the Stump Island reservoir will initially be evaluated on a well-by-well basis in conjunction with Pt. McIntyre reservoir development.

7. Seabee sands are separated from the Kuparuk sands by a series of Cretaceous marine shales which range from approximately fifty to more than two hundred feet thick.

8. An oil column in the Stump Island reservoir overlies a gas cap and oil column in the Pt. McIntyre reservoir.

9. Insufficient subsurface data currently exists to accurately characterize the Stump Island reservoir or estimate the total volume of hydrocarbons in place. Known reserves are minor in relation to those of the Pt. McIntyre reservoir.

10. The Stump Island reservoir has been penetrated in four of the 21 wells drilled within the Pt. McIntyre oil field area to date. Only the Pt. McIntyre No. 3 well proved capable of hydrocarbon production from the Stump Island reservoir.

11. The productive interval in Pt. McIntyre No. 3 is thought to be an isolated occurrence. Subsurface information indicates a lack of continuity between the Stump Island reservoir interval in the Pt. McIntyre No. 3 well and adjacent wells.

12. Those wells encountering both Stump Island and Pt. McIntyre productive intervals will be completed to allow for independent testing of each interval.

13. The Pt. McIntyre reservoir is controlled by a north plunging anticline with fault closure to the south across the large displacement Pt. McIntyre fault, peripheral reservoir quality degradation and stratigraphic truncation of the reservoir along its eastern flank.

14. Numerous moderate displacement normal faults cut the Pt. McIntyre area reservoirs. Fluid contact and pressure data indicate these faults are non-sealing.

15. Net pay determination in the Pt. McIntyre reservoir is primarily controlled by 1) oil-water contact elevation, 2) distribution of lithologies and 3) degree of intergranular cementation.

16. The Pt. McIntyre owners propose development activities for those portions of the Pt. McIntyre reservoir with greater than five net hydrocarbon pore feet as delineated from presently available subsurface data.

17. Core data shows average horizontal permeabilities range from 50-300 millidarcies in the Upper Kuparuk and 100-600 millidarcies. in the Lower Kuparuk sands. Vertical permeabilities range from 1-50% of horizontal permeability.

18. The operators define net pay as reservoir rock with permeability less than 10 md. to air at reservoir conditions. Net pay to gross interval ratio ranges from 0.2-0.8 (0.55 average) in the Upper Kuparuk and from 0.7-0.96 (0.87 average) in the Lower Kuparuk.

19. Average porosity ranges from 19-25% in the Kuparuk River sands.

20. Initial water saturation ranges from 15-65% (33% average) in the oil column and less than 15% in the gas column.

21. Laboratory waterflood displacement and centrifuge tests indicate residual oil saturation will range from 10-30%.

22. Based on Amott tests on core from Pt. McIntyre No. 5 and No. 6, the Pt. McIntyre reservoir was determined to have intermediate wetability.

23. The gas-oil-contact (GOC) in Pt. McIntyre No. 3 is at 8582' TVDss and is considered to be planar throughout the Pt. McIntyre reservoir.

24. The OWC ranges from 9035-9122' TVDss and is subject to varying thickness of transition zone throughout the pool. The owners have arrived at a consensus planar contact at 9069' TVDss.

25. Initial reservoir pressure is 4377 psia calculated to a datum of 8800' TVDss. Initial reservoir temperature ranges from 176-184 deg F at 8800' TVDss.

26. Pt. McIntyre reservoir oil gravity is 27 deg API solution gas-oil-ratio is 806 SCF/STB, formation volume factor is 1.39 RB/STB, and viscosity is 0.9 centipoise at the bubble point pressure of 4308 psia and reservoir temperature.

27. Estimates of original oil in place (OOIP) in the Pt. McIntyre reservoir range from 750-800 MMSTBO, original gas in place (OGIP) from 750-870 BSCF of which 160-240 BSCF is non associated free gas.

28. Test rates range from 600-6000 BOPD from the Pt. McIntyre reservoir. Calculated productivity indices ranged from 0.5-13 BPD/PSI.

29. Primary drive mechanisms in the Pt. Mcintyre reservoir are gas cap expansion and solution gas drive.

30. Pressure maintenance and enhanced oil recovery plans in the Pt. McIntyre reservoir are to inject produced gas into the gas cap and waterflood the reservoir using an inverted nine spot pattern. Gas injection will begin with regular production and waterflood is expected to start within one year of initial production.

31. Each working interest owner developed an independent three dimensional model of the Pt. Mcintyre reservoir to study reservoir mechanisms, estimate recoveries and optimize facility design.

32. Results of model studies from the owners indicate primary depletion with gas cap injection would yield recovery of 20-25% OOIP. Enhanced recovery with pattern waterflood and gas injection increases recovery to 42-45% OOIP.

33. Sensitivity studies indicated no impact on ultimate recovery using field offtake rates from 50-160 MBD.

34. Perforation stand off from GOC and OWC will be determined based on rock quality and presence of flow barriers in order to mitigate gas and water coning.

35. Well spacing will depend on fault location, reservoir rock properties and estimates of sweep efficiency. Spacing of 40 acres per well may be required to accommodate localized conditions.

36. Fail safe surface safety valves (SSV) and subsurface safety valves (SSSV) will be installed in all wells capable of unassisted flow of hydrocarbons to the surface.

37. Certain well operations will require temporary removal of the SSSVs to allow passage of equipment and performance of operations.

38. Reservoir surveillance will consist of monitoring reservoir pressure in both the Pt. McIntyre and Stump Island reservoirs. Allocated production volumes, based on well test data will be reported monthly and used to track individual well oil, gas, water and GOR behavior as well as behavior of the entire reservoir. GOC and production profile programs have not been completed as yet

39. Production from the Pt. McIntyre and Stump Island pools will be commingled with production from other oil pools at the Lisburne Production Center (LPC). Process capacities at LPC will be increased from 100 to 135 MBPD oil and from 25 to 200 MBD water. Gas processing capacity is expected to remain at 460 MMSCF/D. Facility expansions are expected to be completed in 4th Quarter 1994. Produced gas from LPC will be injected into the Lisburne and Pt. McIntyre pools proportional to their produced volumes.

40. Monthly well tests will be used to allocate production to each producing well.

41. Well test facilities will be installed at Pt. McIntyre drill sites 1 and 2 to facilitate well tests for allocation purposes.

42. Optimum well test stabilization and duration times will vary from well to well and may change with time. Well testing guidelines for Pt. Mcintyre wells must be determined after start of production.

43. An NGL process simulator will be utilized to determine and allocate NGL volumes.

44. The Lisburne Data Gathering System (LDGS) will be expanded to accommodate the Pt. McIntyre drill sites. The LDGS will continuously monitor the flowing status, pressures and temperatures of producing wells.

45. H2S has been detected at low levels in well Pt. McIntyre well P2-55.

46. H2S levels are expected to rise over the life of the pool because of gas injection and water injection from the LPC. The operator plans to follow API RP 7G Section 8 to mitigate drill string corrosion and sulfide stress cracking.

47. The proposed area of development for the Pt. McIntyre oil field is not committed to a unit, nor has a participating area been approved for this field by the state.

48. The Pt. McIntyre working interest owners have applied for expansion of the Prudhoe Bay Unit to include the proposed area of development for the Pt. McIntyre oil field. This expansion, as proposed, would include the participating area(s) for the field.

49. The application for expansion of the Prudhoe Bay Unit and formation of the Pt. Mcintyre participation area is under review by the Department of Natural Resources, at date of this order.

50. Pt. McIntyre drill site 2 is located on a gravel extension from the man made East Dock causeway which extends into the Beaufort Sea.

51. Wells drilled from Pt. McIntyre drill site 2 during the course of delineation and development to date have had surface casing set at depths between 2612-4339' TVDss with conductors set between 75-116' MD.

52. No hydrocarbons or abnormal pressures have been encountered above 5000' TVDss in the Pt. McIntyre wells drilled to date.

CONCLUSIONS:

1. Pool rules for development of the Pt. McIntyre and Stump Island reservoirs are appropriate at this time.

2. The unitized management, operation and further development of the Pt. McIntyre and Stump Island oil pools is reasonably necessary to effectively carry on pressure maintenance and enhanced oil recovery operations to maximize ultimate recovery.

3. An integration of interest between the working interest owners and royalty owner appears to be in question as of this date.

4. Well spacing of 40 acres per well is reasonable to accommodate faulting, secondary recovery patterns and reservoir rock characteristics.

5. Waterflood and gas injection will enhance oil recovery for the Pt. McIntyre oil pool.

6. Oil recovery from the Stump Island oil pool cannot be quantified because of limited areal extent and variable characteristics.

7. Pt. McIntyre and Stump Island oil pools are not in hydraulic communication.

8. Development of known reserves in the Stump Island oil pool is not likely without wellbore commingling with Pt. McIntyre oil pool production.

9. Future drilling and production data are needed to adequately define size and extent of the Stump Island oil pool.

10. Fail safe surface safety valves (SSV) and subsurface safety valves (SSSV) are reasonable in wells capable of unassisted flow of hydrocarbons.

11. Exception to 20 AAC 25.240 governing gas-oil-ratios is appropriate because produced gas injection into the pool will start immediately and enhanced oil recovery operations are expected to begin within one year of initial production.

12. Surface commingling of the production from Pt. McIntyre oil field within the LPC will increase ultimate recovery, will not cause waste nor jeopardize correlative rights.

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

14. Conductor casing set at least 75 feet MD provides adequate anchorage for a diverter system, structural casing is not needed.

15. Surface casing can be set to a depth of 5000 feet TVDss because of the absence of shallow hydrocarbons and abnormal pressure zones.

NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth, in addition to state-wide requirements under 20 AAC 25 apply to the following affected area referred to in this order:

Umiat Meridian

T12N R15E Section 18 All.
Section 19 N1/2.
T12N R14E Section 13 All.
Section 14 All.
Section 23 N1/2 NW1/4, N1/2 NEl/4, SW1/4 NWl/4.
Section 24 Nl/2.
T12N R14E Section 15 All
Section 16 All
Section 21 Nl/2 NE1/4.
Section 22 N1/2.
T12N R14E Section 17 NE1/4, N1/2, SE1/4, E1/2 E1/2 NW1/4, E1/2 NE1/4 SW1/4.
T12N Rl4E Section 3 All.
Section 4 All.
Section 9 All.
Section 10 All.

Those Lands in Block 605 lying northerly of the north boundary of Section 3, TI2N, R14E, UM, AK. (Identical with line 4-5 on Block 605) and lying easterly of the west boundary of Sections 2 and 11, T12N, R14E, UM, AK (Identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, Rl4E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, RiSE, UM, AK (Identical with line 6-7 on Block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram," approved 12/9/79, containing 1457.32 hectares.

Rule 1 Integration of Interests

Regular production may not begin until the interests of the working interest and royalty owners are integrated in accordance with the provisions of 20 AAC 25.5 17.

Rule 2 Field and Pool Names

The field is the Pt. McIntyre oil field. Hydrocarbons contained within the Kuparuk River and Kalubik formations constitute a single associated gas and oil reservoir called the Pt. McIntyre oil pool. Hydrocarbons contained within the Seabee formation constitute a single associated gas and oil reservoir called the Stump Island oil pool.

Rule 3 Pool Definition

The Pt. McIntyre oil pool is defined as the accumulation of hydrocarbons common to and which correlates with the interval from 9908 to 10665 foot measured depth in the ARCO Pt. McIntyre No. 11 well.

The Stump Island oil pool is defined as the accumulation of hydrocarbons common to and which correlates with the interval from 8759 to 8930 foot measured depth in the ARCO Pt. McIntyre No. 3 well.

Rule 4 Well Spacing

The spacing unit shall be one producing well per 40 acres or quarter-quarter governmental section. No pay shall be opened in a well closer than 500 feet to the boundary of the affected area.

Rule 5 Casing and Cementing

a. A conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe. Cement to surface shall be verified by visual inspection. The Commission may administratively waive or approve other conductor setting depths and sealing methods that are supported by sound engineering principles.

b. Surface casing shall be set at least 500 feet MD below the base of the permafrost but not below 5000 feet TVDss. Sufficient cement shall be used to fill the annulus behind the casing to the surface; if complete fill-up is not obtained, a top job will be performed before proceeding with drilling operations.

c. Structural casing is not required.

Rule 6 Completion Practices

Wells completed for production may utilize casing strings or liners cemented through the productive intervals and perforated, slotted liners, screen-wrapped liners, gravel packs or open hole methods, or combinations thereof.

Rule 7 Drilling and Production Equipment

Drilling and production equipment must meet the requirements of API RP 7G, Section, "Drillstem Corrosion and Sulfide Stress Cracking," current edition.

Rule 8 Automatic Shut In Equipment

a. Upon completion, each well which is capable of unassisted flow of hydrocarbons to the surface 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 SSSVs.

c. SSSVs may be temporarily removed as part of routine well operations without specific notice to, or authorization by the Commission.

Rule 9 Wellbore Commingling

a. Production from the Pt. McIntyre and Stump Island oil pools may be commingled in the wellbore of the Pt. McIntyre No. 3 well.

i. Allocation to each pool may be determined by production profile surveys or separate zone well tests.

ii. The Commission may require additional production surveillance methods and may administratively accept alternative methods of allocation of wellbore commingled production upon application by the operator.

b. Additional wells may be approved administratively for wellbore commingling on a case-by-case basis upon application to the Commission.

Rule 10 Surface Commingling and Common Facilities

a. Production from the Pt. McIntyre and Stump Island oil pools may be commingled on the surface with production from other pools 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. NGLs 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 off 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.

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 11 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 12 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 run annually. The surveys in part a. of this rule may be used to fulfill the minimum requirements.

c. The datum for all surveys is 8800' 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. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. 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 special reservoir pressure monitoring techniques, tests, or surveys also shall be submitted in accordance with part 'e' of this rule.

Rule 13 Gas-Oil -Ratio Exemption

Wells producing from the Pt. McIntyre and Stump Island oil pools are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply.

Rule 14 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, jeopardize correlative rights, and is based on sound engineering principles.

DONE at Anchorage, Alaska and dated July 2, 1993.

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