STATE OF ALASKA

ALASKA OIL AND GAS CONSERVATION COMMISSION

333 West Seventh Avenue, Suite 100

Anchorage Alaska 99501

Re:

THE APPLICATION OF CONO-COPHILLIPS ALASKA, INC. for an order to expand the affected area of Alpine Oil Pool, Colville River Unit, North Slope, Alaska.

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Conservation Order No. 443A

Colville River Unit
Alpine Field
Alpine Oil Pool

October 7, 2004

IT APPEARING THAT:

1. By application dated July 22, 2004, and received by the Alaska Oil and Gas Conser-vation Commission ("Commission") on July 22, 2004, ConocoPhillips Alaska, Inc. (“CPAI”) in its capacity as Unit Operator of the Colville River Unit (“CRU”) re-quested an order from the Commission to expand the affected area established in Conservation Order 443 that governs the development and operation of the Alpine Oil Pool. Concurrently, CPAI requested an expansion of the affected area established in Area Injection Order 18A, which governs injection operations to enhance recovery from this pool and disposal of wastes.

2. CPAI provided supplemental information at the Commission’s request on September 1, 2004.

3. Notice of a public hearing was published in the Anchorage Daily News on July 30, 2004.

4. The Commission received no comments or requests for public hearing.

5. Because CPAI provided sufficient information on which to make an informed deci-sion, the Commission determined that it would issue an order without a hearing.

FINDINGS:

1. Development of the Alpine Oil Pool

a. Operator: CPAI is the Operator of the Alpine Oil Pool (“AOP”) in the Colville River Unit.

b. Unit Owners and Landowners: As proposed to be expanded, the affected area for the AOP pool rules is totally encompassed within the third expansion of the Col-ville River Unit (“CRU”), which expansion was approved by the Alaska Depart-ment of Natural Resources on April 22, 2004. This unit includes State of Alaska lands, ASRC lands and land jointly owned by State of Alaska and ASRC. The unit lies along the eastern boundary of the National Petroleum Reserve-Alaska on Alaska’s North Slope. Working interest owners of the CRU are CPAI, Phillips Al-pine Alaska, LLC, and Anadarko Petroleum Corporation. BLM tract AA 084140 lies within the external boundaries of the CRU, but is not part of the CRU or the area covered or proposed to be covered by the AOP pool rules. The CRU work-ing interest owners have agreed to integrate their respective interests to provide for the unitized management, development and operation of the AOP under the Colville River Unit Agreement.

c. Delineation History: Oil was discovered in the AOP in 1994 with the Bergschrund No. 1 exploratory oil well. Currently, over 100 exploration, devel-opment and service wells have penetrated the Alpine Sandstone of the Kingak Formation (“Alpine Sandstone”) in the AOP. CPAI utilized data from these wells in conjunction with a 3-D seismic survey to estimate the extent of the oil accumu-lation. Recent drilling in the northwest portion of the AOP indicated thicker sand than original interpreted. Evaluation of the data indicated an opportunity to in-crease developed OOIP with up to six new wells.

d. Pool Identification: The AOP was defined in Conservation Order No. 443 (“CO 443”) as the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths (“MD”) of 6,876 feet and 6,976 feet in the Bergschrund No. 1 well. The AOP is contained within the Alpine Sandstone, and the currently known productive limits of the AOP lie entirely within the expanded CRU.

e. Stratigraphy: The Alpine Sandstone is a Late Jurassic-aged, informal member of the Kingak Formation. It is stratigraphically the highest sandstone unit within the Kingak Formation in the Colville River Delta area. The Alpine Sandstone is an Ellesmerian, shallow marine sand deposited on a southerly prograding shelf, elongated in an east-west direction. The interval consists of very fine to fine-grained, moderately to well sorted, quartz-rich sandstone with variable glauconite and clay content.

Gross thickness of the combined Alpine Sandstone layers varies across the AOP, generally ranging from more than 100 feet near the center of the pool to 0 feet near its periphery. Within the proposed addition to the affected area, gross reser-voir sand thickness is estimated between 30 feet and 0 feet.

f. Structure: The general structure at the top of the Alpine Sandstone in the AOP is a homocline that dips to the southwest at a rate of approximately 100 feet per mile. This homocline is broken by several minor, northwest trending, down-to-the-west, normal faults that average less than 30 feet in vertical displacement.

g. Trapping Mechanism: The AOP appears stratigraphically trapped by pinch-out of the Alpine Sandstone into time equivalent shales of the Kingak Formation.

h. Reservoir Compartments: None of the structural discontinuities currently identi-fied in the AOP appear to have caused any compartmentalization of the reservoir. Given the observed, extensive pressure continuity within the AOP, the reservoir within the proposed addition to the affected area is expected to be in pressure communication with the developed portions of the pool.

2. Rock and Fluid Properties

a. Porosity/Permeability: In the current pool area, porosity of the Alpine Sandstone ranges 15% to 23%, and averages 19%; permeability ranges from 1 to 160 milli-darcies, and averages 15 millidarcies. In the additional area proposed to be cov-ered by the AOP pool rules, porosity is estimated between 17% and 21%, and permeability is estimated to range from less than 10 millidarcies to nearly 60 mil-lidarcies.

b. Initial Reservoir Pressure and Temperature: Initial reservoir pressure of the AOP was 3215 psia at 7000 feet true vertical depth subsea (“TVDss”). Current average reservoir pressure is approximately 3020 psia at 7000’ TVDss. Average reservoir temperature is 160° F.

c. Fluid PVT Data: Fluid samples indicate the AOP reservoir is undersaturated, with a bubble point pressure of 2454 psia. Solution GOR is 850 SCF/STB. Oil gravity and viscosity at reservoir conditions are 40° API and 0.46 centipoise, respec-tively.

3. Pool Limits No oil-water or gas-oil contacts have been observed to date in the AOP. Ongoing op-erations will provide additional information about the productive limits of the AOP.

4. Hydrocarbons in Place Current estimated original oil in place (“OOIP”) within the AOP is 650 to 750 MMSTB million stock tank barrels, of which an estimated 31 to 55 MMSTB are within the proposed addition to the affected area.

5. Development Plans Reservoir models have been used to evaluate primary depletion, waterflood, and other enhanced recovery options for development of the AOP. Reservoir predictions are based on fine scale, three-dimensional, compositional models. Surveillance com-bined with model studies performed to date show about 10 to 15% recovery of OOIP under primary production and an additional 45 to 50% under miscible water alternat-ing gas (“MWAG”) injection.

The development of the pool will continue using horizontal wells arranged in a line-drive pattern. Spacing between wells will vary based on drilling and modeled recov-ery efficiency, but distance between well bores open to the AOP will exceed 500 feet.

6. Facilities

Development and service wells in the proposed addition to the affected area will be drilled from the existing CD2-Pad. This pad is designed to accommodate 60 wells on 10-foot centers. No additional gravel construction is anticipated.

Production will be processed at the Alpine CD1-Pad facility to maximize use of exist-ing infrastructure, minimize environmental impacts, reduce costs, and maximize re-covery. Existing low-pressure oil, water injection, gas lift and possibly miscible in-jectant lines will be shared. Existing power facilities will accommodate additional wells needed to develop the proposed addition to the affected area.

Several phases of upgrades to the Alpine processing facilities are in various stages of planning and implementation. These upgrades will improve throughput capacity and reduce water and gas handling bottlenecks at Alpine.

7. Drilling

AOP drilling will continue to utilize drilling procedures, well designs, and casing and cementing programs that conform to Commission regulations and to the following drilling and completion practices established in Rule 4 of Conservation Order 443.

8. Well Completion Design

Horizontal wells and horizontal multi-lateral well bores may be drilled within the proposed addition to the affected area. The horizontal well sections may be com-pleted with perforated casing, slotted liner, open-hole section, or a combination. Frac-ture stimulation may be necessary to maximize well productivity and injectivity.

a. Surface Safety Valves: Fail-safe automatic surface safety valves (“SSV”) are included in the wellhead equipment for all wells.

b. Subsurface Safety Devices: All wells capable of unassisted flow are equipped with a surface-controlled subsurface safety valve (“SSSV”).

c. Producers: Gas lift remains the preferred mechanism for artificial lift for AOP producers.

d. Injectors: Injection wells are equipped with a double check valve arrangement or a single check and surface safety valve. The subsurface safety valve is also installed on every gas injection well.

e. Stimulation Methods: Lower quality reservoir rock is possible within the pro-posed addition to the affected area. CPAI may evaluate the use of propped hydraulic fracturing stimulation techniques.

9. Reservoir Surveillance Plans

Monitoring of reservoir performance and reporting on a regular basis will help en-sure proper management of the AOP.

a. Well Testing: All wells are tested at least twice per month. CPAI optimizes stabilization and test duration of each test to ensure representative tests. CPAI records well and field-operating conditions to maintain accurate field produc-tion history records. Separator meters and gas system meters have been in-stalled and maintained in conformance with the API Manual of Petroleum Measurement Standards. CPAI maintains records to allow verification of ap-proved production allocation methodologies.

b. Reservoir Pressure Measurements: Initial pressure surveys have been taken in each injection well, and a minimum of six bottom-hole pressure surveys has been measured annually. These pressure surveys of the AOP have been con-ducted using the following techniques: stabilized static pressure measurements at bottom-hole; stabilized static pressure measurements extrapolated from sur-face, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests. Pressure survey results have been corrected to a da-tum of 7000 feet TVD subsea, and have been reported to the Commission an-nually.

c. Reservoir Surveillance Reporting: Information from the proposed addition to the affected area will be integrated into the annual surveillance report for the AOP. These annual reports consist of project progress and reservoir manage-ment summaries including: engineering and geotechnical parameters; voidage balance by month of produced and injected fluids; analysis of reservoir pres-sure surveys within the pool; results and analysis of production log surveys, tracer surveys, and observation well surveys; and a discussion of future devel-opment plans.

10. Sustained Casing Pressure Rules

CO 495, dated September 8, 2003, amended CO 443 by adding new rules regarding sus-tained casing pressures in development wells within the AOP.

CONCLUSIONS:

1. The reservoir interval within the proposed addition to the affected area is equivalent to, and in communication with, the AOP reservoir interval.

2. It is appropriate to amend CO 443 for the AOP to expand the affected area of the pool rules to include Sections 20, 21, 22, 23, 28, 29, 30, 31, and 32 of Township 12N, Range 4E, Umiat Meridian (“UM”) and Sections 25 and 36 of Township 12N, Range 3E, UM. Section 27 of Township 12N, Range 4E, UM was included in the original affected area of CO 443.

3. The AOP is not compartmentalized. A minimum well bore spacing of 500 feet is ap-propriate for efficient development of the pool.

4. The central portion of the AOP is nearly developed. Further delineation of the AOP will determine reservoir volume, thickness and quality.

5. The full extent of the AOP was unknown at the time CO 443 was adopted.

6. A well standoff of 500 feet minimum from the external boundaries of the expanded affected area is appropriate, and is consistent with statewide regulations.

7. Reservoir performance will be monitored through pressure measurements, production tests and normal surveillance activity to ensure proper management of the pool. Con-tinued annual reports and technical review meetings will keep the Commission ap-prised of reservoir performance and will ensure that future development plans pro-mote greater ultimate recovery.

8. Injection of water and miscible gas into the AOP will preserve reservoir energy and increase ultimate recovery from the pool.

9. Exception from the gas-oil-ratio limitations of 20 AAC 25.240 is appropriate pro-vided enhanced recovery operations maintain reservoir pressure above the bubble point pressure.

10. It is appropriate to consolidate sustained casing pressure rules from CO 495 into this order to promote administrative efficiency.

NOW, THEREFORE, IT IS ORDERED:

This Conservation Order supersedes CO 443 dated March 15, 1999 and CO 495 dated September 8, 2003. The findings, conclusions and administrative record for CO 443 and CO 495 are adopted by reference and incorporated in this decision, except where incon-sistent with this Conservation Order. The following rules, in addition to statewide re-quirements under 20 AAC 25, to the extent not superseded by these rules, apply to the AOP within the following affected area:

Umiat Meridian
T11N R4E Section 1, 2, 3, 4, 5, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27.
T11N R5E Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 29, 30.
T12N R4E Sections 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36.
T12N R3E Sections 25, 36.

Rule 1 Field and Pool Name (Restated from CO 443)

The field is the Colville River Field. The pool is the Alpine Oil Pool (“AOP”).

Rule 2 Pool Definition (Restated from CO 443)

The AOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6876 feet and 6976 feet in the Bergschrund No. 1 well.

Rule 3 Well Spacing (Restated from CO 443)

Development wells may not be completed within 500 lineal feet of another AOP devel-opment well nor closer than 500 feet from the exterior boundary of the affected area.

Rule 4 Drilling and Completion Practices (Restated from CO 443)

a. After drilling no more than 50 feet below a casing shoe set in the AOP, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure.

b. Casing and completion designs may be approved by the Commission upon applica-tion and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles.

c. Permit(s) to Drill deviated wells within the AOP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b).

d. A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the re-quirements of 20 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite.

Rule 5 Automatic Shut-in Equipment (Restated from CO 443)

a. All production and gas injection wells must be equipped with a fail-safe automatic surface safety valve (“SSV”) and a surface controlled subsurface safety valve (“SSSV”).

b. Water injection wells must be equipped with either a double check valve arrangement or a single check valve and SSV.

c. Safety Valve Systems (“SVS”) must be tested on a six-month frequency. Sufficient notice must be given so that a representative of the Commission can witness the tests.

d. Subsurface safety valves may only be removed after demonstrating to the Commis-sion that the well is not capable of unassisted flow of hydrocarbons. Sufficient no-tice must be given so that a representative of the Commission can witness the tests.

Rule 6 Reservoir Pressure Monitoring (Restated from CO 443)

a. Prior to regular injection, an initial pressure survey shall be taken in each injection well.

b. A minimum of six bottom-hole pressure surveys shall be measured annually. Bot-tom-hole surveys in paragraph (a) may fulfill the minimum requirement.

c. The reservoir pressure datum shall be 7000 feet TVD 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 shall be reported annually 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 shall be made 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 part (e) of this rule.

Rule 7 Gas-Oil Ratio Exemption (Restated from CO 443)

Wells producing from the AOP 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 8 Reservoir Surveillance Report (Restated from CO 443)

A surveillance report is required after one year of regular production and annually there-after. 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. 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 log surveys, tracer surveys, and observation well surveys.

e. Future development plans

Rule 9 Well Testing (Restated from CO 443)

a. All wells must be tested at least twice per month.

b. The operator shall optimize stabilization and test duration of each test to obtain a rep-resentative test.

c. The operator shall record well and field-operating conditions appropriate for main-taining an accurate field production history.

d. The operator shall install and maintain test separator meters and gas system meters in conformance with the API Manual of Petroleum Measurement Standards.

e. The operator shall maintain records to allow verification of approved production allo-cation methodologies.

Rule 10 Sustained Casing Pressure (Restated from CO 495)

a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety.

b. The operator shall monitor each development well daily to check for sustained pres-sure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection.

c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 psig.

d. The AOGCC may require the operator to submit in an Application for Sundry Ap-provals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in para-graph 3 of this rule. The AOGCC may approve the operator’s proposal or may require other corrective action or surveillance. The AOGCC may require that corrective ac-tion be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to al-low AOGCC to witness the tests.

e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well’s production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well’s surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective ac-tion. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator’s proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests.

f. Except as otherwise approved by the AOGCC under paragraph 4 or 5 of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3, but not paragraph 5, of these rules may reach an annulus pressure at operating temperature that is de-scribed in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit.

g. For purposes of these rules, “inner annulus” means the space in a well between tubing and production casing; “outer annulus” means the space in a well between production casing and surface cas-ing; “sustained pressure” means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally.

Rule 11 Administrative Action (Restated from CO 443)

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, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles.

DONE at Anchorage, Alaska and dated October 7, 2004.

John K. Norman, Chair
Alaska Oil and Gas Conservation Commission

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


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