3001 Porcupine Drive

Anchorage, Alaska 99501-3192

Re:The application of ARCO Alaska, Inc. ("AAI") to         )   Conservation Order No. 317B
amend AIO 4 to initiate a Miscible Gas Enhanced Oil        )   Pt. McIntyre Oil Field
Recovery Project in the Prudhoe Bay Unit, Point            )   Pt. McIntyre Oil Pool (amended)
McIntyre Oil Pool, North Slope, Alaska.                    )   Stump Island Oil Pool
                                                               April 19, 2000


1. By correspondence dated November 8, 1999, AAI requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to initiate a miscible gas tertiary recovery project in the Point McIntyre Oil Pool located in the Eastern Operating Area of the Prudhoe Bay Unit.

2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on November 20, 1999.

3. The Commission did not receive a protest or request for a public hearing.

4. The Commission held a hearing at the Commissionís offices on January 12 and 13, 2000.


1. The Commission has issued Conservation Order No. 317 dated July 2, 1993 (revised September 10, 1993) and Conservation Order No. 317A dated April 25, 1996 to govern development of the Pt. McIntyre Oil Pool.

2. The findings, conclusions and administrative records for the above listed Conservation Orders are incorporated by reference in this order.

3. AAI is the operator of the Eastern Operating Area of the Prudhoe Bay Unit including the Point McIntyre Oil Field and the West Beach Oil Pool. There are no other operators within a one-quarter mile radius of the proposed injection operations.

4. The State of Alaska is the only surface owner within one mile of the Point McIntyre Oil.

5. Facility modifications at the Lisburne Production Center (LPC) are designed to ensure that the volume of natural gas liquids extracted at the LPC will not be impacted by the manufacture of miscible injectant solvent.

6. AAI proposes to use hydrocarbons from the Pt. McIntyre, West Beach, North Prudhoe Bay, Niakuk and Lisburne Oil Pools processed in the LPC. Components from the natural gas liquid plant downstream from the feed flash drum will be added to enrich the miscible injectant (MI) stream to be used in the Point McIntyre enhanced recovery project.

7. Seventy-four producing and service wells were active in the Point McIntyre Oil Pool (PMOP) as of January 1, 2000. Fifteen water injectors and one gas injector were providing pressure support to the PMOP, maintaining average reservoir pressure near the original pressure of approximately 4370 psi.

8. The inverted nine-spot waterflood pattern in the PMOP is flexible and can be adapted to changes in reservoir performance as the enhanced recovery process matures.

9. The PMOP miscible gas injection project involves conversion of present and future waterflood injectors to water-alternating-gas (WAG) injection service.

10. A MI slug equivalent to approximately 35 percent hydrocarbon pore volume (HPV) will be placed over a twenty-three year period.

11. The maximum MI rate that can be manufactured from LPC residue gas is projected to be 50 MMSCFD at a minimum miscibility pressure of approximately 4350-psi.

12. An extensive performance history indicates that the Pt. McIntyre waterflood has been able to adequately balance voidage in the reservoir to maintain an average reservoir pressure of 4370 psi.

13. The minimum miscibility pressure is designed to be as close to average reservoir pressure as possible. This will maximize the volume of MI that can be manufactured at LPC.

14. Limited supply of MI will require phased implementation and conversion of patterns to WAG injection. Any volumes of MI in excess of the nominal 50 MMSCFD rate injected in the PMOP will have to be purchased from an external source.

15. The benefits of using additional MI, up to 100 MMSCFD purchased from an external source for this project, are being evaluated.

16. Modifications at LPC done in 1999 to manufacture MI included installation of an MI compressor, a new parallel chiller, new compressor coolers, blending station, and an upgrade of the natural gas liquid plant piping.

17. MI will be transported to the Point McIntyre drill sites by a new pipeline using existing vertical support members and new drill site distribution piping.

18. The geologic description of the injection and confining zones for both the PMOP miscible gas tertiary recovery project and the West Beach Oil Pool (WBOP) enhanced oil recovery project have been previously submitted in "Application for Modification to Area Injection Order No. 4" dated April 5, 1993.

19. Injection wells in the PMOP have been drilled, cased, cemented according to requirements of 20 AAC 25.005 and tested according to 20 AAC 25.412. Applications and completion records are on file at the AOGCC.

20. Seawater is currently injected in the Pt. McIntyre waterflood. It is possible that produced water will be used later in the project. Both water sources have previously been approved in Area Injection Order No. 4B.

21. Estimated average and maximum injection pressures (at pump discharge) for PMOP WAG wells are expected to be 4100 psi and 4500 psi respectively.

22. Surveillance and performance data for both water and gas injection in the PMOP indicates out of zone fractures have not occurred.

23. MI injection pressures are not likely to cause fracturing of the PMOP confining zones based on previous enhanced recovery injection performance.

24. Secondary recovery gas re-injection and pattern waterflood operations in the PMOP are projected to increase recovery to 42-45% of the original oil in place (OOIP).

25. The PMOP MI enhanced recovery project will increase oil recovery from the pool by 6% of the OOIP or by 32 MMSTB in the area where MI will be applied.


1. Conservation Order No. 317A should be amended to allow implementation of an enhanced recovery project within the area defined as the Pt. McIntyre Pool.

2. NGL required for the project will be manufactured from gas processed in the LPC.

3. Implementation of a miscible gas injection project in the PMOP will significantly increase ultimate recovery, will not cause waste nor violate correlative rights.

4. Surveillance activity associated with reservoir development, waterflood, and miscible injection operations reporting should be consolidated into one report documenting significant activity on an annual basis.

5. The record for this order should include the hearing record and administrative files related to Conservation Order No. 317 and Conservation Order No. 317A, including approvals issued under those orders.

6. The PMOP miscible gas injection project and the WBOP injection project will not cause waste, jeopardize correlative rights, or impair ultimate recovery.

NOW, THEREFORE, IT IS ORDERED THAT (1) Conservation Order No. 317B supersedes Conservation Order No. 317A dated April 25, 1996 and Conservation Order No. 317 dated July2, 1993. (2) The following rules, in addition to statewide requirements under 20 AAC 25, apply to the affected area described below:

Umiat Meridian



Section 18

Section 19





Section 13

Section 14

Section 23

Section 24



N1/2 NW1/4, N1/2 NE1/4, SW1/4 NW1/4.




Section 15

Section 16

Section 21

Section 22



N1/2 NE1/4.




Section 17

NE1/4, N1/2, SE 1/4, E1/2 E1/2 NW1/4,

E1/2 NE1/4 SW1/4.



Section 3

Section 4

Section 9

Section 10





Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, 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, R14E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, R15E, 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 Plan of Development and Operation

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 25.517, and the plan of development and operation has been approved by the Commission under the provisions of AS 31.05.030(d)(9).

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 8, "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 SSSVís.

c. SSSVís 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 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. 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 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 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.

    Rule 15 Pt. McIntyre Oil Pool Annual Reservoir Report

    An annual Pt. McIntyre Oil Pool surveillance report will be required by April 1 of each year. 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. Reservoir 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 and injection log surveys, tracer surveys and observation well data and surveys.

    e. Results of any special monitoring.

    f. Future development plans.

    g. Review of Annual Plan of Operations and Development.

    Rule 16 Pt. McIntyre Oil Pool Enhanced Oil Recovery Project

    a. Injection of miscible injectant for enhanced recovery operations is approved for the Pt. McIntyre Pool.

    b. An annual report must be submitted to the Commission detailing performance of the PMOP Enhanced Oil Recovery Project and outlining compositional information for the current miscible injectant necessary to maintain miscibility under anticipated reservoir conditions. The report should be submitted in conjunction with the PMOP Annual Reservoir Report.

    DONE at Anchorage, Alaska and dated April 19, 2000.

    Robert N. Christenson, P.E., Chair
    Alaska Oil and Gas Conservation Commission

    Camillé Oechsli Taylor, Commissioner
    Alaska Oil and Gas Conservation Commission

    Conservation Order Index