STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
3001 Porcupine Drive
Anchorage Alaska 99501-3192

Re:THE APPLICATION OF BP EXPLORATION         ) Conservation Order No. 449
  (ALASKA) INC.for an order defining         )
  and classifying the Eider Oil Pool and     ) Endicott Field
  establishing rules for its operation       ) Eider Oil Pool
  and development.                           )                 
                                               July 21, 2000

IT APPEARING THAT:

1. By letters dated January 27 and 28, 2000, BP Exploration (Alaska) Inc. ("BPXA") requested a public hearing to present testimony to define the Eider Oil Pool in the Duck Island Unit and establish pool rules for development and production of the reservoir. Supplemental information was also provided by letters dated February 3, 2000 and February 17, 2000, and electronic mail dated June 12, 2000. On April 17, 2000, BPXA substituted an amended Eider pool rules application.

2. Notice of opportunity for public hearing was published in the Anchorage Daily News on February 5, 2000. A second public hearing notice changing the date of public hearing was published in the Anchorage Daily News on March 3, 2000. A third public hearing notice for a continuance of the hearing was published in the Anchorage Daily News on April 15, 2000.

3. The Commission did not receive a protest.

4. BPXA presented testimony at hearings convened in conformance with 20 AAC 25.540 at the Commission's offices on April 6, 2000 and May 25, 2000.

FINDINGS:

1. The Eider Oil Pool (EOP) is the name proposed to describe a common accumulation of hydrocarbons trapped within the Sag River, Shublik and Ivishak Formations in the S1/2 of Township 12 North and Range 16 East Umiat Meridian.

2. The Duck Island Unit has been expanded and the Prudhoe Bay Unit has been contracted to accommodate development of the EOP.

3. BPXA is the operator and owner of the current Eider Participating Area (PA) contained within Alaska State Lease ADL-034634 in the Duck Island Unit.

4. BPXA has drilled a total of two completed wells, the 2-56A/EI01 and the 2-30A/EI02, and five additional plugbacks into the EOP.

5. EOP development wells have been drilled and completed in accordance with Alaska Oil and Gas Conservation Regulations 20 AAC 25 and Conservation Order (CO) 202 as amended by CO 216 and CO 334.

6. The proposed development plan does not include additional drilling at this time.

7. Well and 3-D seismic data are adequate to characterize the accumulation within the Eider PA.

8. The vertical limits of the EOP are defined by the accumulation in the BP Exploration 2-56A/EI01 well between the measured depths of 16,785 and 17,928 feet, which appears to be typical and representative of the pool.

9. Within the EOP, producible oil is known to exist only within the Ivishak Formation, which occurs in the BP Exploration 2-56A/EI01 well between the measured depths of 17,338 and 17,928 feet.

10. Petrophysical log, RFT and production data have been used to determine the EOP reservoir properties.

11. The currently delineated EOP is trapped within a fault controlled anticlinal structure, which is truncated by the Lower Cretaceous Unconformity and has an areal extent of approximately 300 acres.

12. Estimate of the original oil-in-place (OOIP) is 13.2 MM STB for the EOP. A significant gas cap is present and has approximately 40 BSCF of gas-in-place.

13. Area Injection Order 19 authorized enhanced recovery water injection in the EOP Ivishak Formation.

14. The EOP Ivishak Formation is composed of three stratigraphic units named, in stratigraphic order, the Lower Sand, Middle Shale, and Upper Sand.

15. The EOP Ivishak Formation is interpreted by BPXA to represent a regressive sequence of depositional environments, ranging from upper shoreface or marine influenced fluvial and distributary sands in the Lower Sand, floodplain or bay fill in the Middle Shale, and a predominantly fluvial environment in the Upper Sand.

16. The Lower Sand gross thickness ranges from 80 to 125 feet, net to gross ratio is 0.8, average porosity is 21% and average permeability is 30 millidarcies.

17. The Middle Shale gross thickness ranges from 75 to 90 feet, net to gross ratio is 0.5, average porosity is 16% and average permeability is 300 millidarcies.

18. The Upper Sand gross thickness ranges from 60 to 125 feet, net to gross ratio is 0.8, average porosity is 20% and average permeability is 300 millidaries.

19. The three stratigraphic units constitute a single flow unit due to vertical permeability enhancement by faulting and fracturing.

20. The oil column average porosity is 21% and average permeability is 134 millidarcies.

21. The degree of pressure communication between the sandstones of the Ivishak and Sag River Formations is unknown at present.

22. Eider crude oil gravity ranges from 23.1 to 23.8 deg API, solution gas-oil ratio is 769 SCF/STB, formation volume factor is 1.36 RB/STB, viscosity is 1.0 centipoise, gas gravity is 0.778 and bubble point pressure is 4365 psia.

23. BPX recorded an initial reservoir pressure of 4635 at 9,700 feet subsea datum. Water saturation calculated from open-hole logs averaged 36% using the Archie equation.

24. BPX proposes to measure reservoir pressure at one single point annually in the field, rather than once per every governmental section.

25. BPX estimates primary recovery at about 15% of OOIP.

26. Predictive runs with a full field simulation model indicated that water injection is preferred to gas injection or primary depletion to maximize ultimate recovery. BPXA's studies indicate incremental recovery increase of 12-23%, up to 27-38% of total OOIP from waterflood.

27. Enhanced recovery injection will use seawater and/or produced water from Eider, Sag Delta North or Endicott. A formation water analysis will be conducted prior to initiating injection operations to ensure compatibility of the injected water with formation water.

28. BPXA plans to commingle Eider production with Endicott and Sag Delta North production in Duck Island Unit surface process facilities. Production from each pool will be allocated by using individual well production tests in a common test separation facility.

29. BPXA submitted confidential supplemental exhibits and information with their letters to the Commission dated February 3, 2000 and February 17, 2000.

30. BPXA presented testimony during the confidential portion of the hearing held at the Commission's offices on May 25, 2000.

31. BPXA representatives agreed during the hearing held at the Commission's office on May 25, 2000 to release all confidential exhibits, information and testimony submitted to the Commission in support of establishment of the EOP on the date the well information from 2-30A/EI02 is publicly released.

CONCLUSIONS:

1. Pool rules for the initial development of the EOP are appropriate at this time.

2. Development of the EOP will occur within the proposed expanded portion of the Duck Island Unit.

3. Two EOP wells have been drilled and completed as stipulated in Commission statewide regulations and three Conservation Orders for the Duck Island Unit, Endicott Oil Pool.

4. Well spacing units of 160 acres will allow the operator sufficient flexibility to locate wells to accommodate geologic, stratigraphic and structural factors throughout the project area.

5. Implementation of an enhanced recovery operation to support reservoir pressure will preserve reservoir energy and enhance ultimate recovery.

6. Eider production will be allocated using existing test facilities and methods applied to the Endicott and Sag Delta North pools.

7. Reservoir pressure will be measured using standard industry practices on a regular basis to manage production and monitor reservoir performance.

8. Exception from the gas-oil-ratio limitations of 20 AAC 25.240 is appropriate provided a pressure maintenance project starts concurrent with regular production.

9. A minimum of two well tests per month will help ensure that accurate well test data are available for reservoir management and production allocation.

NOW, THEREFORE, IT IS ORDERED THAT the following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), apply to the affected area described below:

Umiat Meridian

T12N R16E Sections 27: All state lands
Sections 28: NE 1/4 of SE 1/4

Rule 1 Field and Pool Name and Classification

The field is the Endicott Field. Hydrocarbons underlying the affected area within the Sag River, Shublik and Ivishak Formations constitute a single oil and gas reservoir classified as an oil pool and called the Eider Oil Pool (EOP).

Rule 2 Pool Definition

The EOP is defined as the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 16,785 feet and 17,928 feet in the Duck Island Unit 2-56A/EI01 well.

Rule 3 Spacing Units

Spacing units within the pool will be 160 acres. The pool shall not be opened in any well closer than 500 feet to an external boundary of the affected area.

Rule 4 Casing and Cementing Practices

a) Structural casing is required. However, conductor casing is not required.

b) Surface casing adequate to provide for proper anchorage, for preventing uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and/or freeze-back loading, shall be set at least 500 measured feet below the base of the permafrost, but not below 4,500 feet true vertical depth.

c) Surface casing shall be cemented to surface. Surface casing cement may be washed out or displaced to a depth not exceeding the structural casing shoe to facilitate casing removal upon well abandonment.

d) Alternate means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back may be administratively approved by the Commission upon application and presentation of data which show the alternatives are appropriate, based upon accepted engineering principles.

e) Formation leak-off tests are not required below structural casings.

Rule 5 Diverter System

A diverter system is not required on the structural casing.

Rule 6 Completion Practices

Wells completed for production or injection in the EOP may utilize casing strings or liners cemented through the productive intervals and perforated, slotted liners, screen wrapped liners or open hole methods, or a combination thereof. The commission may administratively approve alternate completion methods where appropriate.

Rule 7 Automatic Shut-in Equipment

a.) All wells must be equipped with a fail-safe automatic surface safety valve capable of preventing an uncontrolled flow.

b.) All wells capable of unassisted flow of hydrocarbons must be equipped with a fail-safe surface-controlled subsurface safety valve (SSSV) system capable of preventing an uncontrolled flow. This valve must be in the tubing string and located above or below the permafrost.

c.) Injection wells must be equipped with a double check valve arrangement.

d.) Surface safety valves and surface-controlled subsurface safety valves must be tested at six-month intervals.

e.) Low-pressure sensor (LPS) trip pressure must be at least 50% of the primary separator pressure or 25% of the flowing tubing pressure, whichever is greater.

Rule 8 Common Production Facilities and Surface Commingling

a) Production from the EOP may be commingled with production from the Endicott and Sag Delta North oil pools in surface facilities prior to custody transfer.

b) The allocation factor for the EOP will be 1.00 for the first year of production to evaluate the allocation method, testing frequency and quality.

c) Each producing Eider well must be tested a minimum of twice per month.

d) The Commission may require more frequent or longer tests if the allocation quality deteriorates.

e) The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation.

f) The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report.

Rule 9 Reservoir Pressure Monitoring

a) Prior to regular production or injection, an initial pressure survey must be taken in each well.

b) At least one bottom-hole pressure survey per four producing or injecting governmental sections shall be measured annually. No less than four reservoir pressures will be measured annually. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement.

c) The reservoir pressure datum will be 9,700 feet subsea.

d) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or extrapolated from surface, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests.

e) Data and results from 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 10 Gas-Oil Ratio Exemption

Wells producing from the EOP are exempt from the gas-oil-ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply.

Rule 11 Pressure Maintenance Project

A pressure maintenance project must be initiated concurrent with regular production.

Rule 12 Reservoir Surveillance Report

An annual reservoir surveillance report for the prior calendar year will be required on or about April 1. The report shall include but is not limited to the following:

a) Progress of enhanced recovery project implementation and reservoir management summary including engineering and geotechnical parameters.

b) Voidage balance by month of produced fluids and injected fluids and cumulative status.

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 surveys.

e) Review of pool production allocation factors and issues over the prior year.

f) Future development plans.

Rule 13 Production Anomalies

In the event of oil production capacity proration at or from the Duck Island Unit facilities, all commingled reservoirs produced through the Duck Island Unit facilities will be prorated by an equivalent percentage of oil production, unless this will result in surface or subsurface equipment damage.

Rule 14 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 July 21, 2000.

Camillé Oechsli Taylor, Commissioner
Alaska Oil and Gas Conservation Commission

Daniel T. Seamount, Jr., Commissioner
Alaska Oil and Gas Conservation Commission

Conservation Order Index