|Re: THE APPLICATION OF BPXA||)||Conservation Order No. 457|
|EXPLORATION (ALASKA) INC.||)|
|for an order to establish pool rules for||)||Prudhoe Bay Field|
|development of the Aurora Oil Pool,||)||Aurora Oil Pool|
|Prudhoe Bay Field, North Slope,||)||(formerly Kuparuk River Oil Pool)|
|September 7, 2001|
1. By letter and application dated June 15, 2001, BPXA Exploration (Alaska) Inc. ("BPXA") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") to define a proposed Aurora Oil Pool encompassing the Aurora Participating Area ("APA") of the Prudhoe Bay Unit and to prescribe rules governing the development and operation of the pool.
2. Notice of opportunity for public hearing was published in the Anchorage Daily News on June 22, 2001.
3. The Commission did not receive a protest.
4. A hearing concerning BPXA's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 333 W. 7th Avenue, Suite 100, Anchorage, Alaska 99501 on July 24, 2001. Concurrently, the Commission heard testimony concerning proposed injection of fluids for enhanced recovery from the proposed pool. BPXA submitted a revised application "Aurora Pool Rules and Area Injection Application-July 23, 2001". This application included supplemental information requested by the Commission.
5. Additional information and data were requested by the Commission at the hearing and have been provided to the Commission. This supplemental information was submitted by letter from BPXA dated July 31, 2001.
1. The proposed Aurora Oil Pool ("AOP") encompasses portions of Township 12N-R12E, and T11N-R12E, Umiat Meridian, on which are located Alaska State Leases ADL-28255, ADL-28256, ADL-28257, ADL-28258, ADL-28259, and ADL 28261. The known extent of the proposed pool is located within the current boundaries of the Prudhoe Bay Unit ("PBU"), North Slope, Alaska.
2. The Department of Natural Resources, Division of Oil and Gas ("Division"), approved an expansion of the Prudhoe Bay Unit ("PBU") and formation of an initial Aurora Participating Area on December 20, 2000. The Aurora Participating Area was delineated by drilling within the Kuparuk River Formation in the vicinity of S Pad. The Division's decision provided that the participating area will be automatically expanded when and if BPXA drills "Qualified Wells" within defined expansion areas. Attachment 1 shows an outline of the participating area and the expansion areas. In this order, the term "APA" means the Aurora Participating Area including the expansion areas when and if the initial Aurora Participating Area is expanded to include them.
3. The area proposed to be covered by the requested AOP pool rules corresponds to the APA and expansion areas.
4. BPXA is the operator of the APA. BPXA, Phillips Petroleum, Co., ExxonMobil Corporation, and Forest Oil are working interest owners ("WIOs") in the APA. The State of Alaska is the landowner.
5. The reservoir interval of the proposed AOP is the Kuparuk River Formation. The proposed pool is an accumulation of hydrocarbons that is common to, and correlates with, the interval between 6859' and 7254' measured depth in Prudhoe Bay Unit well V-200.
6. Conservation Order No. 98-A (CO 98-A) defined the Kuparuk River Oil Pool within the Prudhoe Bay Field ("PBKROP") and prescribed rules governing the development and operation of the pool. The PBKROP was defined as the accumulation of oil that is common to and correlates with the accumulation found in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12 well between the depths of 6,765 and 7,765 feet. This is the same accumulation that the applicant proposes to be defined as the Aurora Oil Pool. The Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12 well is located within the APA, as is Prudhoe Bay Unit well V-200.
7. Conservation Order No. 349A amended CO 98-A by reducing the extent of the area to which the rules prescribed in CO 98-A applies.
8. The area proposed to be covered by the requested pool rules is encompassed within the area to which the rules prescribed in CO 98-A, as amended by Conservation Order No. 349A, apply.
9. Data submitted by BPXA cast doubt on whether the PBKROP extends into the entire area to which the rules prescribed in CO 98-A, as amended by Conservation Order 349A, apply.
10. Only limited drilling activities, preliminary to pool development, are occurring outside the APA in the area to which the rules prescribed in CO 98-A, as amended by Conservation Order No. 349A, apply.
11. The Kuparuk River Formation in the AOP was deposited as Early Cretaceous marine shoreface and offshore sediments, and is composed of very fine to medium grained quartz rich sandstone, interbedded with siltstone and mudstone.
12. The Kuparuk River Formation in the AOP is stratigraphically complex, characterized by multiple uncomformities, changes in thickness and sedimentary facies, and local diagenetic cementation.
13. The AOP Kuparuk River Formation reservoir is divided into three stratigraphic intervals, from the base to the top of the formation, the A, B and C.
14. The A Zone, the stratigraphically lowest zone, contains two reservoir quality sub-intervals; the A-4 and A-5 sands, which are typically 30 and 20 feet thick respectively.
15. The B zone is dominated by siltstone and sandy mudstone with numerous discontinuous thin sandstone lenses, the thickest of which are three feet thick.
16. The uppermost unit, the Kuparuk C interval, contains the primary reservoir sands of the AOP. The C interval is characterized by thick amalgamated sands, with high net to gross ratios.
17. The Kuparuk River Formation in the AOP is highly faulted with displacements ranging to hundreds of feet.
18. Fluid contacts (oil/water and gas/oil) appear to be variable across the AOP.
19. The stratigraphic character of the Kuparuk River Formation and style of structural deformation typical in the AOP is similar to that documented in the adjacent Kuparuk River Unit and the Milne Point Unit.
20. Fault related compartmentalization of the AOP may be reasonably anticipated.
21. The distribution and frequency of pressure measurements required for reservoir management of the AOP will be dependent on the degree of pressure compartmentalization determined by development drilling.
22. Porosity and permeability measurements were based upon routine core analysis of Kuparuk Formation wells in the area. Average layer properties range between 16% for the A sand net pay interval, and 25% for C sand net pay intervals. The average permeabilities for these layers range from 12 md to 158 md.
23. Five exploratory wells in the area have been tested in the Kuparuk Formation. The V-200 appraisal well drilled from an ice pad in 1999, tested at a rate of 1915 bopd with a GOR of 718 scf/stb, with 29.6 API gravity oil. The V-200 has been plugged and abandoned.
24. With successful test of the V-200 well, the WIOs proceeded with evaluation and development of the Kuparuk Formation from Well Pad S in the PBU. Phase 1 drilling in year 2000 included three wells drilled from S Pad, S-100, S-101, and S-102. Phase II development will include six to eight producers and three to four injectors. Six wells have been drilled or planned for 2001. BPXA presented results of three of these wells, S-103, S-104 and S-105.
25. Based upon current well control and seismic information, BPXA estimates 110 to 146 MMSTB original oil in place.
26. Model studies conducted suggest primary oil recovery of approximately 12% and waterflood recovery of 34%. Waterflood is part of BPXA current development plans.
27. Production rate peak for the proposed development plan is estimated at 14,000-17,000 bopd with a maximum water injection rate of 20,000-30,000 bwpd.
28. BPXA is concurrently requesting conversion of S-101 to water injection for support of current producers (S-100 and S-102).
29. BPXA plans to fully replace and balance voidage with waterflood. Initially, an injection to production ratio greater than 1:1 may be required to restore reservoir pressure.
30. BPXA requested 80 acres minimum spacing. The Commission asked BPXA if 40 acre minimum spacing would cause any problems, to which they stated, no. As long as adequate pressure maintenance is effected, 40 acre well spacing will not adversely affect ultimate recovery.
31. Reservoir PVT studies were conducted from recombined surface test separator samples and RFT downhole samples obtained from V-200. The API gravity was 29.1( API, with a solution gas oil ratio of 717 scf/stb. Formation volume factor of 1.345 RVB/STB and oil viscosity of 0.722 cp at reservoir pressure and temperature.
32. The API oil gravity measured from wells in the AOP, range from 25.2( to 29.1( API. One well, S-101, had an initial API gravity of 47( API, however, the elevated API was due to the production of gas condensate liquids.
33. Initial reservoir pressure based upon RFT data from V-200 is 3433 psi at 6700' tvdss. Reservoir temperature is approximately 150 degrees Fahrenheit at 6700' tvdss.
34. The development of the APA is planned entirely from the PBU drill site, S-Pad and will utilize existing Prudhoe Bay Unit facilities and pipelines for production and water injection. Production will be processed at Gathering Center 2 (GC2). A 24" low-pressure pipeline, a 10" gas lift supply line, and a 14" water injection supply line are also in place.
35. Additional facilities expansions are as follows:
a. A gravel expansion of S Pad to accommodate additional wells at S-pad, completed in April, 2000.
b. A new production manifold system to accommodate up 20 Aurora wells.
c. An extension of an existing 6" water injection supply line.
36. Estimated water injection available for proposed AOP is 28,000 BPXA at a pressure of 2000-2100 psig. Local water injection booster pumps may be added if injection pressures and rates are insufficient to support the waterflood.
37. Gas lift will be utilized for artificial lift in the AOP wells. Estimated gas lift supply available for production wells is 30 MMscfd at 1800 psig.
38. Wells will be drilled according to AOGCC regulations. Horizontal and vertical wells are anticipated. Fracture stimulation may be necessary. A 20" conductor will be set at 80' below pad level, and surface hole will be drilled to 2300 ft tvdss, minimum. Production hole will be drilled below surface casing to the Kuparuk Formation. Liners may be used in certain instances.
39. BPXA plans to install Surface Safety Valves Systems on all wells per AOGCC regulations.
40. BPXA requested that sub-surface safety valves not be included. This requirement was a stipulation of CO 98-A. All wells will be equipped with SSSV nipples, should the need arise to install subsurface storm chokes or pressure operated safety valves. BPXA intends to install such flow control devices in wells utilized for gas or miscible gas injection.
41. The development plan proposed by BPXA for the AOP is based on analysis of large volumes of recent geologic and engineering data and differs materially from development scenarios anticipated when CO 98-A was issued.
42. BPXA provided a letter summarizing the draft PBU Satellite Production Metering Plan dated July 23, 2001. BPXA proposes this plan be adopted for the AOP. The Commission has not received a final copy of this plan.
1. The existing PBKROP pool rules established in CO 98-A are no longer suitable in their entirety for pool development and operation in the APA.
2. The existing PBKROP pool rules established in CO 98-A add little to the statewide requirements of the current Commission regulations, 20 AAC 25. Given the limited extent of the activities that are occurring in portions of the area covered by CO 98-A, as amended by Conservation Order No. 349A, outside the APA, and given that the data that have become available since CO 98-A was issued suggest that those portions may be largely outside the PBKROP, it is not essential to maintain the pool rules in effect for those portions.
3. 40 acre spacing should be adopted for the AOP . This spacing will not cause waste, compromise ultimate recovery, or jeopardize correlative rights.
4. No reason appears why the setback requirements established in statewide well spacing rules, 20 AAC 25.055(a)(1)and (2), should not apply to the exterior boundary of the APA.
5. Monitoring of reservoir performance by measurement of production and reservoir pressure using standard industry practices on a regular basis will help ensure proper management of the pool.
6. Surface commingling of AOP fluids produced from the APA with produced fluids from other pools and tract operations within the PBU is appropriate provided there are adequate well tests to assure accurate production allocation.
NOW THEREFORE IT IS ORDERED:
1. CO 98-A is amended, and to the extent inconsistent with the provisions of this order is superseded, by this order.
2. The name of the pool defined in CO 98-A is changed to the Aurora Oil Pool.
3. The rules set out below replace Rules 2 through 8 as established in CO 98-A and apply (in addition to the statewide requirements under 20 AAC 25 to the extent not superseded by these rules) to the following described area:
|T11N||R12E||N 1/2 Sec. 3|
|T12N||R12E||S 1/2 Sec 17; SE 1/4 Sec 18; E 1/2 Sec 19; All Sec 20; All Sec 21;|
|W 1/2 NW 1/4,S 1/2 Sec 22; SW 1/4 Sec 23; SW 1/4 Sec 25; All Sec 26;|
|All Sec 27; All Sec 28; N 1/2, SE 1/4 Sec 29; E 1/2 Sec 32; All Sec 33;|
|All Sec 34; All Sec 35; N 1/2, SW 1/4 Sec 36|
Rule 1 Well Spacing
Spacing units within the pool shall be a minimum of 40 acres. 20 AAC 25.055(a)(1) and (2) shall not apply to property lines within the external boundaries of the APA.
Rule 2 Casing and Cementing Practices
a) In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75 feet below the surface.
b) In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500' tvdss below the permafrost.
Rule 3 Automatic Shut-in Equipment
a. All wells must be equipped with a fail-safe automatic surface safety valve system capable of detecting and preventing an uncontrolled flow.
b. The wells must be equipped with a landing nipple at a depth below permafrost, which is suitable for the future installation of a downhole flow control device to control subsurface flow. The Commission may require such installation by administrative action.
c. Safety Valve Systems must be maintained in good working order at all times and must be tested at maximum six-month intervals or other schedule prescribed by the Commission.
Rule 4 Common Production Facilities and Surface Commingling
a) The operator shall submit to the Commission for approval the finalized PBU Western Satellite Metering Plan or other plan for allocation of production from the Aurora Oil Pool .
b) The PBU Western Satellite Metering Plan must satisfy the well testing requirements of 20 AAC 25.230 and 20 AAC 25.275.
c) Each producing well must be tested a minimum of twice per month.
d) Until the Prudhoe Bay Unit Western Satellite Metering Plan or other allocation plan is approved and implemented, the Aurora Oil Pool allocation factor shall be 1.0.
e) The Commission may require more frequent or longer tests if the allocation quality deteriorates.
f) The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation.
g) The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report.
Rule 5 Reservoir Pressure Monitoring
a) Prior to regular production or injection, an initial pressure survey must be taken in each well.
b) The minimum number of bottom-hole pressure surveys acquired each year shall equal the number of governmental sections within the Aurora Oil Pool that contain active wells. A minimum of four surveys will be required each year in representative areas of the Aurora Oil Pool. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement.
c) The reservoir pressure datum will be 6,700 feet TVDss.
d) Pressure surveys may be stabilized static pressure measurements at bottom-hole or extrapolated from surface (single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests.
e) Data and results from all relevant reservoir pressure surveys must be reported quarterly on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but must be available to the Commission upon request.
f) Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule.
Rule 6 Gas-Oil Ratio Exemption
Wells producing from the Aurora Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC25.240(b) are met.
Rule 7 Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations
Enhanced oil recovery or reservoir pressure maintenance operations must be initiated within six months after this order is issued.
Rule 8 Reservoir Surveillance Report
An annual reservoir surveillance report for the prior calendar year will be required after 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 implementation and reservoir management summary including results of reservoir simulation techniques.
b) Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval.
c) Summary and analysis of reservoir pressure surveys within the pool.
d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring.
e) Review of pool production allocation factors and issues over the prior year.
f) Future development plans.
g) Review of Annual Plan of Operations and Development.
Rule 9 Production Anomalies
In the event of oil production capacity proration at or from the Prudhoe Bay Unit facilities, all commingled reservoirs produced through the Prudhoe Bay Unit facilities will be prorated by an equivalent percentage of oil production, unless this will result in surface or subsurface equipment damage.
Rule 10 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 or jeopardize correlative rights, and is based on sound engineering and geoscience principles.
DONE at Anchorage, Alaska and dated September 7, 2001.
Cammy Oechsli Taylor, Chair
Alaska Oil and Gas Conservation Commission
Daniel T. Seamount, Jr., Commissioner
Alaska Oil and Gas Conservation Commission
Julie M. Heusser, Commissioner
Alaska Oil and Gas Conservation Commission