|Re:THE REQUEST of ARCO ALASKA INC||)||Conservation Order No. 311|
|to present testimony to prescribed pool||)|
|rules for operation and development of||)||Prudhoe Bay Field|
|the West Beach Oil Pool||)||West Beach Oil Pool|
|February 25, 1993|
IT APPEARING THAT:
1. By letter dated December 7, 1992, ARCO Alaska, Inc. requested a public hearing to present testimony for establishing pool rules for development and operation of the West Beach Oil Pool in the Prudhoe Bay Field.
2. Notice of public hearing to be held on January 13, 1993 was published in the Anchorage Daily News on December 10, 1992.
3. A hearing concerning the matter of the applicant's request was held in conformance with 20 AAC 25.540 at the office of the Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 a.m. January 13, 1993.
4. The hearing record was held open an additional 30 days to allow the Commission to consider and ask additional questions.
1. Gas was discovered in sands of the Kuparuk River formation through drilling of the ARCO/Exxon well West Beach #3B (WB#3B) in 1976. Approximately 12 feet of hydrocarbon bearing sand were tested at a rate of 2.4 MMCF/D of natural gas and 208 B/D of condensate.
2. West Beach #4, drilled approximately 1.2 miles east of WB#3B in 1991, penetrated 199' of oil column in the Kuparuk River formation. Following fracture stimulation, the well tested 2459 B/D of oil with a minor amount of water.
3. No oil-water or gas-oil contact was encountered in either well.
4. Reservoir pressure in WB#3B, corrected to a reference datum of 8,800 feet true vertical depth subsea (TVDss), was 4,437 psig when measured in 1976. Reservoir pressure in WB#4 was 4,257 psig at 8,800 feet TVDss in 1991. Initial reservoir pressure of the adjacent (to the north) Pt. McIntyre oil accumulation is approximately 4,355 psig and for the Lisburne oil pool (to the south) is approximately 4445 psig, both corrected to 8,800 TVDss.
5. Three dimensional seismic data and subsurface well data support an interpretation that wells WB#3B and WB#4 penetrated a single fault block, which appears to be in partial fault contact with the Pt McIntyre oil accumulation to the north and with the Lisburne Oil Pool to the south.
6. Reported reservoir properties in the West Beach oil accumulation are 12.1% to 25.8% porosity, 25 to 189 millidarcies permeability, and 35% to 41% water saturation.
7. Volumetric estimates range between 12 to 65 MMB oil in place and 10 to 56 BCF gas originally in place.
8. Additional production and reservoir pressure tests are needed to evaluate reservoir size, oil and gas in place, and development and depletion plans.
9. The estimated size of the West Beach accumulation precludes stand alone production facilities. Development options envisioned at this time range from a single production well (WB#4) with no reinjection of produced gas to 11 wells, consisting of five oil producers, five water injectors and one gas injector.
10. Under the single well development scenario, ultimate recovery may be constrained by the gas-oil ratio limitations 20 AAC 25.240.
11. Under the phased development scenario, ultimate recovery will be improved if voidage replacement through waterflooding and gas reinjection is implemented within two years of production startup.
12. Future West Beach development wells, if viable, will be directionally drilled utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in other North Slope fields.
13. All West Beach wells are planned as single zone completions.
14. A fail-safe automatic surface safety valve (SSV) and a subsurface safety valve (SSSV) will be installed in wells capable of unassisted flow of hydrocarbons.
15. Certain well operations will require temporary removal of the SSSV's.
16. Reservoir pressure measurements will be taken during the first year of production to analyze reservoir performance. Long term pressure surveillance plans will depend on the type of reservoir development and depletion program ultimately selected for this reservoir.
17. West Beach production will be commingled with Lisburne production at the Lisburne Production Center (LPC). Produced gas from WB#4 will be reinjected into either the Pt McIntyre or the Lisburne reservoir during the initial development phase.
18. The LPC will not reuqire modification to accommodate West Beach production.
19. Monthly well tests will be used to allocate production to each producing well. Plans are to test West Beach and Lisburne wells at least twice per month, except for individual wells that cannot meet the twice monthly test schedule for operational reasons.
20. Metering equipment and facilities at the LPC have been upgraded to enhance allocation accuracy.
21. West Beach production wells will be manifolded into the DS-L1 test separator.
22. Current well test separator utilization at Lisburne facilities varies between 80 and 90 percent.
23. Optimum well test stabilization and duration times vary from well to well and may change with time. Well testing guidelines for West Beach wells must be determined after start up of production.
24. An NGL process simulator will be utilized to determine and allocate NGL volumes.
25. The Lisburne Data Gathering System at the LPC records and maintains oil water and gas rates, gas lift rates, choke settings, flowing tubing pressure and temperature, plant inlet pressure, separator pressure and termperature, and an event history for each well.
1. Pool rules for initial development of the West Beach oil accumulation are appropriate at this time.
2. Additional reservoir testing will be necessary to understand reservoir size, rock quality, depletion mechanisms, appropriate spacing and design of enhanced recovery/pressure maintenance projects. Results may require modification of these pool rules.
3. Plans for field development including number of production and injection wells, well spacing, expected offtake rates and depletion mechanisms are uncertain at this time.
4. Ultimate recovery cannot be determined at this time and will only be meaningful with additional information from comprehensive reservoir pressure and production tests planned in the coming year.
5. The pressure difference between the WB#3B and WB#4 is not fully understood at this time.
6. Pressure data from Point McIntyre, Lisburne and West Beach wells is inconclusive regarding communication between the three accumulations.
7. Fail-safe surface safety valves (SSV) and subsurface safety valves (SSSV are appropriate in wells capable of unassisted flow to the surface.
8. The need for an exception to 20 AAC 25.240 (gas-oil ratios) can be considered when depletion mechanisms and development options have been determined.
9. Surface commingling of the production streams from Lisburne and West Beach is necessary.
10. Production allocation procedures will need to be reviewed periodically in the early stages to evaluate techniques and to revise procedures if warranted.
11. The goal of allocation process review and evaluation will be to confirm volumetric accounting and modify procedures where necessary.
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 described area referred to in this order:
|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
State-wide 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) Upon completion, each well which is capable of unassisted flow of hydrocarbons shall be equipped with:
i a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow.
ii. a fail-safe automatic subsurface safety valve (SSSV), unless another type of subsurface valve is approved by the Commission, installed in the tubing string below the base of the permafrost capable of preventing an 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 or by other means, is not required to have fail-safe automatic SSSVs.
(c) For projects receiving Commission administrative approval, the requirements for fail-safe SSSV equipment may be waived.
(d) SSSVs may be temporarily removed as part of routine wellwork operations without specific notice to, or authorization by, the Commission.
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 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.
(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.
(h) 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 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 submittted 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, jeoparidze correlative rights, and is based on sound engineering principles.
DONE at Anchorage, Alaska and dated February 25, 1993.
David W. Johnston, Chairman
Alaska Oil and Gas Conservation Commission
Russell A. Douglass, Commissioner
Alaska Oil and Gas Conservation Commission