STATE OF ALASKA

ALASKA OIL AND GAS CONSERVATION COMMISSION

3001 Porcupine Drive

Anchorage Alaska 99501-3192

Re: The application of ARCO Alaska, Inc. ("AAI") to            ) Conservation Order No. 311B
amend AIO 4B to initiate a Miscible Gas Enhanced Oil           ) 
Recovery Project in the Point McIntyre Oil Pool and a          ) Prudhoe Bay Unit
Water and Gas Injection Enhanced Oil Project in the            ) West Beach Oil Pool
West Beach Oil Pool.
                                                                 April 19, 2000
IT APPEARING THAT:

1. By correspondence dated November 8, 1999, AAI requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to approve a waterflood enhanced oil recovery project in the West Beach Oil Pool.

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 Commission’s offices on January 12 and 13, 2000.

FINDINGS:

1. The Commission has issued Conservation Order No. 311 dated February 25, 1993 and Conservation Order No. 311A dated December 20, 1996 to govern development and depletion of the West Beach Oil Pool ("WBOP").

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

3. The WBOP is estimated to contain 15 to 25 MMSTB of oil in place.

4. Recent WBOP reservoir simulation studies, incorporating all well and seismic data, indicated a peripheral waterflood could increase recovery over primary depletion by an incremental 10-15% of the OOIP, about 2 MMSTB. Gas injection to recover "attic" oil along the southern boundary fault is being evaluated and may be implemented in the future.

5. After production tests of wells WB-05B and WB-06, a peripheral waterflood will be implemented by converting either WB-04 or WB-06 to water injection.

6. Potential injectors, WB-04 and WB-06, have been drilled, cased, cemented and tested according to requirements of 20 AAC 25.005. Applications and completion records are on file at the AOGCC. Whichever well is converted will be tested according to 20 AAC 25.412 prior to initiation of injection.

7. Facilities have been installed to accommodate additional production and injection wells if evaluation of field performance indicates additional reserves can be recovered.

8. The waterflood will be managed to replace reservoir voidage and injection rates will be modified in response to well performance.

9. The WBOP waterflood will utilize water produced from a dedicated source well drilled to the Tertiary Sagavanirktok Formation. Pump design capacity is expected to be 10,000 barrels per day.

10. No Sagavanirktok Formation water samples have been obtained from a West Beach pad well. Wireline log analyses of the West Beach State #1 well indicate Sagavanirktok Formation water samples from adjacent wells are representative of the interval in the West Beach Pad area.

11. Laboratory testing, core analyses and geochemical modeling indicate no significant problems are likely due to clay swelling or in-situ fluid compatibility problems between WBOP and Tertiary formation waters.

12. WBOP waterflood source water from the Sagavanirktok Formation is expected to have excess barium ion that could precipitate barium sulfate scale if mixed with PMOP produced water. WBOP produced water will be inhibited upstream of the commingling point with Pt. McIntyre Oil Pool fluids to prevent scale precipitation.

13. Estimated average and maximum injection pressures (at the pump discharge) for WBOP water injectors are 2100 and 2850 psi respectively.

14. Injection pressures are not likely to fracture the WBOP confining zones based on previous injection performance in similar stratigraphy in the adjacent PMOP.

15. Potential benefits of gas injection in WBOP are being studied. Preliminary evaluation of gas injection estimates maximum gas injection of 25 MMSCFD with average and maximum injection pressures (at the pump discharge) of 4100 and 4500 psi respectively. No compatibility issues are anticipated between WBOP fluids and LPC residual gas.

CONCLUSIONS:

1. It is appropriate to issue Conservation Order No. 311B consolidating Conservation Order No. 311 and Conservation Order No. 311A with rules to allow waterflood in the WBOP.

2. A waterflood in the WBOP will result in significant additional hydrocarbon recovery.

3. The WBOP water injection project will not cause waste, jeopardize correlative rights, or impair ultimate recovery.

4. A plan to inject gas in the WBOP is being evaluated and is not complete.

5. Reissuing Conservation Order No. 311B in its entirety and adding Rules 12 and 13 will maintain continuity in the administrative record and keep all orders affecting the WBOP in one Conservation Order.

NOW, THEREFORE, IT IS ORDERED THAT

(1) Conservation Order No. 311B supersedes Conservation Order No. 311 dated February 25, 1993 and Conservation Order No. 311A dated December 20, 1996.

(2) The following rules, in addition to statewide requirements under 20 AAC 25, apply to the affected area described below:

UMIAT MERIDIAN
T12N R15E Section 19 S½
Section 20 S½
Section 21 SW¼
Section 28 N½
Section 29 N½
Section 30 N½
T12N R14E Section 24 S½
Section 25 N½, SE¼

Rule 1 Field and Pool Name

The field is the Prudhoe Bay Field. Hydrocarbons contained within the Kuparuk River Formation constitute a single associated gas and oil reservoir called the West Beach Oil Pool.

Rule 2 Pool Definition

The West Beach Oil Pool is defined as the accumulation of oil and gas which is common to and correlates with the accumulation found in the West Beach No. 4 well between the depths of 14, 548' MD and 14,781' MD.

Rule 3 Well Spacing

Statewide 160-acre drilling units are in effect until such time as data or circumstances warrant the Commission to approve a change.

Rule 4 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 5 Drilling and Production Equipment

Drilling and production equipment must meet the requirements of API RP 7G, Section 8, "Drillstem Corrosion and Sulfide Stress Cracking," Eighth Edition, April, 1978, or subsequent editions.

Rule 6 Automatic Shut-in Equipment

(a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead.

(b) The SVS shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building.

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

(ii) A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated reactivation dates must be maintained current and available for the Commission on request.

(a) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working order.

Rule 7 Common Facilities and Surface Commingling

(a) Production from the West Beach Pool may be commingled on the surface with production from other pools prior to custody transfer.

(b)Production from each pool will be determined by the following well test allocation method. 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.

(g) API gravity will be determined for each producing West Beach well monthly.

(h) Gas samples will be taken for each non-gas lifted producing well yearly.

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

(j) Prior to installing separate test facilities (if required by future development) at West Beach, Commission approval of the facilities must be obtained.

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

Rule 8 Production Anomalies

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

Rule 9 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 8,800' TVD SS.

(d) Pressure survey will be 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 on 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 10 Development and Depletion Plan

Within one year after start of regular production, the operator shall present to the Commission a more definitive development and depletion plan for this pool.

Rule 11 Administrative Action

Upon request by the operator or upon its own motion, the Commission may administratively amend this order if the revision does not promote waste, jeopardize correlative rights, and is based on sound engineering principles.

Rule 12 West Beach Waterflood Project

Water injection for additional oil recovery is approved for the West Beach Oil Pool.

Rule 13 West Beach Oil Pool Annual Reservoir Report

An annual West Beach 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 the waterflood project implementation, progress on enhanced recovery evaluation and a 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.

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