Re:

THE APPLICATION OF CONOCOPHILLIPS ALASKA, INC. for Changes to Rule 3, Conservation Order 432B, which Affects Well Spacing within the Kuparuk River Oil Pool, Kuparuk River Unit, North Slope, Alaska

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Conservation Order No. 432C.000 Kuparuk River Field Kuparuk River Unit Milne Point Unit Kuparuk River Oil Pool November 2, 2004

IT APPEARING THAT:

1. By application dated August 24, 2004 and received by the Alaska Oil and Gas Conservation Commission (“Commission”) on August 25, 2004, ConocoPhillips Alaska, Inc. (“CPAI”) in its capacity as Unit Operator of the Kuparuk River Unit (“KRU”) requested an order from the Commission to remove the intra-pool well spacing requirements of Rule 3 of Conservation Order No. 432B applying to the Kuparuk River Oil Pool (“KROP”);

2. Notice of a public hearing was published in the Anchorage Daily News on August 30, 2004;

3. The Commission received no requests for public hearing;

4. The Commission received one favorable comment from BP Exploration (Alaska), Inc. (“BPXA”), operator of the Milne Point Unit, in favor of less restrictive spacing rules applying to the KROP;

5. The Commission also received one comment identifying corrections needed in CO 432B: the inadvertent omission of Sections 1, 2, 9, 10, 11, and 12 of T12N, R11E, Umiat Meridian (“UM”) and Sections 27 and 34 of T13N, R11E, UM from the affected area of CO 432B; and

6. Because CPAI provided sufficient information on which to make an informed decision, the Commission determined that it could issue an order without a hearing.

FINDINGS:

1. Operator

ConocoPhillips, Inc. (“CPA”) is the operator of the KROP within the Kuparuk River Unit. BP Exploration (Alaska), Inc. is the operator of the KROP within the Milne Point Unit.

2. Oil Pool

The Kuparuk River Oil Pool in the Kuparuk River Field is defined as the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 well between the depths of 6,474 and 6,880 feet.

3. Development Summary

Development drilling within the KROP began in 1978, and the field was brought on production in December of 1981. The pool is a mature development, with in excess of 1,500 development and service wells drilled to the pool. The operators are maximizing recovery by targeting smaller, un-drained portions of isolated fault blocks that cannot be reached by wells conforming to the governmental land grid.

4. Affected Area For The Kuparuk River Oil Pool Rules

1. Conservation Order 432B dated December 12, 2002 superseded Conservation Order 432A, dated August 11, 1999, and Conservation Order 349A, dated December 23, 1996. The findings, conclusions and administrative record for Conservation Orders 432A and 349A were adopted by reference and incorporated in that decision.
2. The affected area described in CO 432B inadvertently omitted Sections 1, 2, 9, 10, 11, and 12 of T12N, R11E, UM and Sections 27 and 34 of T13N, R11E, UM. CO 432B did not expressly exclude those sections. The affected area of preceding order CO 349A included those same sections.

5. Spacing Requirements for the KROP

1. Spacing within the KROP is currently governed by:
   1. Rule 3 of CO 432B, which states:
      “Not more than one well may be drilled on any governmental quarter section or governmental lot corresponding to it nor may any well be drilled on a governmental quarter section or governmental lot corresponding to it which contains less than 125 acres, nor may the pool be opened in a well bore that is closer than 500 feet to any property line nor closer than 1,000 feet to the pool opened to the well bore in another well except that in Sections 5, 6, 7, 8, 15, 16, 21, and 22, T11N, R10E, U.M., an unrestricted number of wells may be drilled.” (Source CO 173, modified by CO 182)
   2. Rule 1 of CO 205, amends Rule 3 of CO 173 by adding the following sentence: “…in the area described in CO 205, except for those governmental quarter sections adjacent to the Milne Point Unit boundary, four wells may be drilled per governmental quarter section.”
2. The original KROP spacing requirements specified in CO 173, 182, and 205 were developed in the 1983 and 1984:
   1. during the early stages of development of the KROP,
   2. before widespread use of 3D seismic, which allows more precise mapping of reservoir structure, and
   3. before the development of very high-angle, horizontal and coiled-tubing drilling techniques, which allow more effective recovery of reserves through precise placement of extended production and injection well bores and well bore segments within the individual blocks of a faulted reservoir.
3. Maximizing recovery of reserves from the KROP will require additional wells, sidetracked wells, and multilateral well segments that will not conform to the governmental land grid.

6. Sustained Casing Pressure Requirements for the KROP

1. CO 494, dated September 4, 2003, established sustained casing pressure rules for the KROP within the Kuparuk River Unit and the Milne Point Unit.
2. CO 494 amended the KROP rules in CO 432B.

CONCLUSIONS:

1. The omission of Sections 1, 2, 9, 10, 11, and 12 of T12N, R11E, UM and Sections 27 and 34 of T13N, R11E, UM from the affected area of CO 432B was a clerical error. It is appropriate to amend the affected area of CO432B to include these sections.

2. Less restrictive spacing requirements will help to maximize recovery from the faulted, compartmentalized KROP as development continues to mature, and reduce the administrative burden for the KROP Operators and the Commission.

3. A 500-foot setback from external property lines where ownership or landownership changes is necessary to protect correlative rights.

4. Revised spacing requirements for wells and well bore segments located more than 500 feet from external property lines where ownership or landownership changes will promote more efficient recovery of oil reserves and will not result in waste or jeopardize the correlative rights of adjoining or nearby owners.

5. It is appropriate to include the sustained casing pressure rules established by CO 494 within this order.

NOW, THEREFORE, IT IS ORDERED:

This Conservation Order supersedes CO 432B, dated December 12, 2002. The findings, conclusions and administrative record for CO 432B, CO 494, and CO 496 are adopted by reference and incorporated in this decision. In addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules or other conservation orders), the following rules apply to the Kuparuk Oil Pool within the following affected area:

Umiat Meridian T9N, R6E, U.M. SECS. 1,2,11,12,13, and 14. T9N, R7E, U.M. SECS. 1,2,3,4,5,6,7,8,9,10,11,12,13,14,15,16,17 and 18. T9N, R8E U.M. SECS. 1,2,3,4,5,6,7,8,9,10,11,12,13,14,15,16,17, and 18. T9N, R9E, U.M. SECS. 1,2,3,4,5,6,7,8,9,10,11,12,15,16,17and 18. T9N, R10E U.M. SECS. 1,2,3,4,5,6,7,8,9,10,11 and 12. T10N, R6E, U.M. SECS. 1,2,3,4,9,10,11,12,13,14,15,16,21,22,23,24,25,26,35 and 36. T10N, R7E, U.M. ALL. T10N, R8E, U.M. ALL. T10N, R9E, U.M. ALL. T10N, R10E, U.M. ALL T10N, R11E, U.M. SECS. 5,6,7,8,17,18,19 and 20. T11N, R6E, U.M. SECS. 25,26,35 and 36. T11N, R7E, U.M. SECS. 1,2,3,4,9,10,11,12,13,14,15,16,17,18,19,20,21,22,23,24,25,26,27,28,29,30,31,32,33,34,35 and 36. T11N, R8E, U.M. ALL T11N, R9E, U.M. ALL

T11N, R10E, U.M. ALL T11N, R11E U.M. SECS. 5,6,7,8,16,17,18,19,20,21,22,23,26,27,28,29,30,31, 32,33,34,35 and 36. T12N, R7E, U.M. SECS. 1,2,11,12,13,14,15,16,21,22,23,24,25,26,35 and 36. T12N, R8E, U.M. ALL T12N R9E U.M. ALL T12N, R10E, U.M. SECS. 1,2,3,4,5,6,7,8,9,10,11,12,14,15,16,17,18,19,20,21,22,23,25,26,27,28,29,30,31,32,33,34,35 and 36. T12N, R11E, U.M. SECS. 1,2,3,4,5,6,7,8,9,10,11,12 and 31. T13N, R8E, U.M. SECS. 13,14,23,24,25,26,27,28,33,34,35 and 36. T13N, R9E, U.M. ALL T13N, R10E, U.M. ALL T13N, R11E, U.M. SECS. 7,8,16,17,18,19,20,21,27, 28,29,30,31,32,33, and 34. T14N R9E U.M. SECS. 1,2,3,4,5,6,7,8,9,10,11,12,13,14,15,16,17,18,20,21,22,23,24,25,26,27,28,29,32,33,34,35 and 36. T14N, R10E U.M. SECS. 15,16,17,18,19,20,21,22,27,28,29,30,31,32,33,34 and 35. T15N, R9E U.M. State lands within SECS. 25,26,27,31,32,33,34,35, and 36.

Rule 1. Name of Field (Ref. CO 173)

The name of the field shall be the Kuparuk River Field. (Source CO 173)

Rule 2. Definition of Pool (Ref. CO 173)

The name of the pool in the Kuparuk River Field shall be the Kuparuk River Oil Pool and is defined as the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 well between the depths of 6,474 and 6,880 feet. (Source CO 173)

Rule 3 Well Spacing (This order)

There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to an external property line where ownership or landownership changes.

Rule 4. Casing and Cementing Requirements (Ref. CO 173, 190, 193, 203, 209, and 229)

1. Casing and cementing requirements are as specified in 20 AAC 25.030, CASING AND CEMENTING, except as modified below. (Source CO 173)
2. For proper anchorage and to prevent an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. (Source CO 173)
3. For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze back, a string of surface casing shall be set at least 500 measured feet below the base of the permafrost section but not below 2700 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. (Source CO 173, CO 193, 203, 209 & 229 – authorized depths of surface casing for various Drill Sites are detailed on following table)
   1) Drill Pad 2Z Kuparuk River oil pool wells may be drilled to a maximum depth of 3250 feet true vertical depth before surface casing is set so long as drilling fluid densities are monitored and maintained at 10.0 pounds per gallon. (Source CO 190, modified by AA 190.01 - 190.15)
   2) Drill Pad 2X and 2C Kuparuk River oil pool wells may be drilled to a maximum depth of 2975 feet true vertical depth before surface casing is set. (Source CO 190, modified by AA 190.01 - 190.15)
   3) In the event that geologic conditions are not as anticipated, the Commission may change the maximum depth for setting surface casing by administrative action, provided a request, in writing, is timely submitted. (Source CO 190)

   AA No.	Drill Sites	Authorized Surface CasingDepth Pursuant toRule 4(c) CO 190
   AA 190.1	1F	3350’ TVD
   AA 190.4	2Z	3450’ TVD
   AA 190.6	2K	3000’ TVD
   AA 190.7	2K	3452’ TVD
   AA 190.10	3G	3500’ TVD
   AA 190.11	1A	3900’ TVD
   AA 190.12	3R	4200’ TVD
   AA 190.13	1H	4100’ TVD
   AA 190.14	1H	4400’ TVD
   AA 190.15	1Y	4400’ TVD

   Conservation Order	Drill Sites	Authorized Surface Casing Depth Pursuant to CO 173 Rule 4(c) and 20 AAC 25.035(b)
   CO 193	2A, 2B, 2D, 2F, 2G, 2H, 2V	3200’ TVD
   CO 203	1L, 1Q, 1R, 2E, 2U, 2W, 3B, 3C	3800’ TVD
   CO 209	1R, 2A, 2H, 2T, 3A, 3B, 3C, 3F, 3J, 3K, 3M, 3N, 3O, 3Q	4150’ TVD
   CO 229	2M, 3H	3700’ TVD

4. The surface casing, including connections, shall have minimum post-yield strain properties of 0.9% in tension and 1.26% in compression. (Source CO 173)
   1) The only types and grades of casing, with threaded connections, that have been shown to meet the requirements in (d) above and have been approved for use as surface casing are the following:

   (A) 13 3/8 inch, 72 pounds/foot, L-80, Buttress;
   (B) 13-3/8 inch, 72 pounds/foot, N-80, Buttress;
   (C) 10-3/4 inch, 45.5 pounds/foot, K-55, Buttress;

   
   2) The Commission may approve other types and grades of surface casing upon a showing that the proposed casing and connection can meet the post-yield strain requirements in (d) above. This evidence shall consist of one of the following:

   (A) Full scale tensile and compressive tests,
   (B) Finite element model studies; or,
   (C) Other types of axial strain data acceptable to the Commission.

5. Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back may be approved by the Commission upon appliction. (Source CO 173)
6. The Commission may approve alternative completion methods (to 20 AAC 25.030(b)(4) and (5)) upon application and presentation of data that shows the alternatives are based on accepted engineering principles. Such alternative designs may include: (Source CO 173)
   1) Slotted liners, wire wrapped screen liners, or combinations thereof, landed inside of open hole and may be gravel packed;
   2) Open hole completions provided that the casing is set not more than 200 feet above the productive zone.

Rule 5. Automatic Shut-In Equipment (Ref. CO 173 & 348)

1. 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 and shutting down any artificial lift system where an over pressure of equipment may occur. (Source CO 348)
2. The safety valve system (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. (Source CO 348)
   1) 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. (Source CO 348)
   2) A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for Commission inspection on request. (Source CO 348)
3. A representative of the Commission shall be allowed to witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS is in proper working condition. (Source CO 348)

Rule 6. Safety Flares (Ref. CO 173) Repealed by 20 AAC 25.235.

Rule 7. Gas-Oil Ratio Tests (Ref. CO 173 & 262) Repealed by Conservation Order 262, dated October 23, 1990.

Rule 8. Pressure Surveys (Ref. CO 173, 230, 276 & 432)

1. A bottom-hole pressure survey shall be taken on each well prior to initial sustained production. (Source CO 230)
2. The operator shall obtain pressure surveys as needed to effectively manage hydrocarbon recovery processes subject to an annual plan outlined in (d) of this rule. (Source CO 432)
3. Bottom-hole pressures obtained by a static buildup pressure survey, a 24-hour shut-in instantaneous test, a multiple flow rate test or an injection fall-off test will be acceptable. Calculation of bottom-hole pressures from surface data will be permitted for water injection wells. (Source CO 230)
4. Data from the surveys required in this rule shall be filed with the Commission by April 1 of the subsequent year in which the surveys are conducted. Along with the survey submittal, the operator will provide a proposed survey plan for the upcoming year. Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys with attachments for complete additional data. Data submitted shall include, but are not limited to, rate, pressure, time, depths, fluid gradient, temperature, and other well conditions necessary for complete analysis of each survey being conducted. The pool pressure datum plane shall be 6,200 feet subsea. (Source CO 230, 432)
5. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (d) of this rule. (Source CO 230)
6. Upon application by the operator, the Commission in its discretion may administratively approve exceptions to this rule. (Source CO 230)

Rule 9. Productivity Profiles (Ref. CO 173, 276 & 432)

1. During the first year of production, a production survey shall be run in each well that has multiple sand intervals open to the well bore. (Source CO 173)
2. Subsequent surveys shall be run in wells that exhibit uncharacteristic changes in performance. Subsequent surveys shall also be required in wells which have had remedial work performed to change the production profile unless the remedial work results in only one sand interval being open to the well bore. (Source CO 173, 276)
3. All completed production surveys taken during a calendar year be filed with the Commission by April 1 of the subsequent year. The Commission may request data be provided in advance of an annual submittal if required. (Source CO 173, 432)
4. By administrative order, the Commission shall specify additional surveys should it be determined that the surveys submitted under (a) and (b) are inadequate. (Source CO 173)

Rule 10. Production Well Tests (Ref. CO 432A)

1. A well test must be performed on each active producing well at least once every 30 days.
2. Twinned production wells commingled through the same surface flowline, must be tested at least once every 30 days as a combined production stream and the individual wells must be tested separately at least once every six months or more often if the combined well test indicates uncharacteristic performance.

Rule 11 Sustained Casing Pressures (Ref. CO 494 and CO 496)

1. 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.
2. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection.
3. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (1) sustained inner annulus pressure that exceeds 2000 psig or (2) sustained outer annulus pressure that exceeds 1000 psig.
4. The AOGCC may require the operator to submit in an Application for Sundry Approvals (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 paragraph c 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 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.
5. 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 action. 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.
6. Except as otherwise approved by the AOGCC under paragraph (d) or (e) of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2000 psig and (2) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph (c), but not paragraph (e), of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph (c), unless the AOGCC prescribes a different limit.
7. 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 casing; “sustained pressure” means pressure that (1) is measurable at the casing head of an annulus, (2) is not caused solely by temperature fluctuations, and (3) is not pressure that has been applied intentionally.

Rule 12 Administrative Actions (This Order)

Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the confining zone.

DONE at Anchorage, Alaska and dated November 2, 2004.

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

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

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