333 West 7th Avenue, Suite 100

Anchorage, Alaska 99501

Re: THE APPLICATION OF ) Conservation Order No. 432B
ConocoPhillips Alaska, Inc. for an )
order to expand the affected area for ) Kuparuk River Field
pool rules for development of the ) Kuparuk River Unit
Kuparuk River Oil Pool, Kuparuk ) Milne Point Unit
River Field, North Slope, Alaska ) Kuparuk River Oil Pool
December 12, 2002


1. By application dated September 4, 2002 ConocoPhillips Alaska, Inc., formerly known as Phillips Alaska, Inc., seeks to expand the affected area of Conservation Order No. 432A and Area Injection Order 2A, to accommodate Kuparuk River Oil Pool development at Drill Site 3S in the Kuparuk River Unit ("KRU").

2. Notice of opportunity for public hearing was published in the Anchorage Daily News on September 27, 2002.

3. No comments concerning the application or timely requests for a public hearing were received.


1. Operator ConocoPhillips, Inc. ("CPA") is the operator of the Kuparuk River Oil Pool within the Kuparuk River 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. The justification for the expansion of the pool centers on the discovery in the exploration wells Palm #1 and #1A, which were drilled during the 2001 winter season.

3. Affected Area For The Kuparuk River Oil Pool Rules

a. Conservation Order 349A dated December 23, 1996 describes the affected area to which the Kuparuk River Oil Pool rules apply.

b. Conservation Orders 432 and 432A (dated July 22, 1998 and August 11, 1999 respectively) incorrectly referred to the affected area described in CO 349 (dated December 16, 1994 and repealed by CO 349A on December 23, 1996). The correct reference should have been to CO 349A.

c. Conservation Order 471, dated May 29, 2002 defines the Borealis Oil Pool in the Kuparuk River Formation within the Prudhoe Bay Unit ("PBU"). CO 471 contracted the following sections from CO 349A:

T12N-R10E Sections 13, 24;

T12N-R11E Sections 18, 19, 20, 29, 30, 32, and 33;

T11N-R11E Sections 3,4,9,10,11,14,15,24, and 25.

4. Proposed Expansion CPA requests expansion of the affected area to include the following sections:

T12N, R7E Sections 1,2,11,12,13,14,15,16,21,22,23, and 24.

5. Stratigraphy The Kuparuk River Formation is a sequence of clastic sediments deposited on a shallow marine shelf during Neocomian (Early Cretaceous) time, about 140-120 million years ago. The formation is divided into Upper and Lower Members. These two Members are comprised of 4 Units, in ascending order, Units "A", "B", "C", and "D". The "A" and "C" units are the pay-bearing intervals in a major portion of the field.

The Kuparuk River "C" Unit is composed of sandstones with subordinate conglomerates and lesser shales. "C" sediments were deposited in a variety of marginal marine environments. In general, conditions were marine to the east, within and beyond the KRU. In the west, evidence from secondary cements as well as trace fossils suggests a nearby source of fresh water and a shoreline. The Unit is divided into four intervals, "C1" through "C4". Intervals are successively younger upward, and axes of deposition shift successively southwest with time. Throughout the larger part of the KRU, "C" sand deposition and trends are controlled by syndepositional, northwest-trending normal faults.

Within the DS 3S area, the Palm #1 and #1A wells penetrated reservoir quality sands in the Hauterivian Kuparuk River "C4" interval at a depth of approximately 5750-5800 feet TVD. The Kuparuk River "A" Sand was found to be absent through truncation by the Lower Cretaceous Unconformity (LCU) and the "C1" through "C3" intervals are absent because of non-deposition in the area.

The Kuparuk "C4" sand reservoir is comprised of bioturbated, fine to medium-grained sandstone with variable amounts of glauconite, clay pellets, and siderite cement. It is separated from the underlying Miluveach mudstones by the regional LCU. A transgressive surface of erosion marks the contact between "C4" sandstones and overlying mudstones of the Kalubik Formation. The "C4" interval in the area is interpreted to represent transgressive shoreface deposits on the flank of the Kuparuk trough. Accommodation and preservation of these shoreface deposits was created in part by deep-seated northwest-southeast trending normal faults.

The gross reservoir thickness logged in the Palm #1 and 1A wells ranges from 30 feet to 35 feet, with a corresponding net-to-gross ratio of approximately 0.73. A 15% porosity cutoff from wire line log derived porosity data Log model is used to count net pay. Average pay porosity ranges from 19% to 21%. Calculated log model water saturations for the Palm #1 and #1A wells are 12% and 13% respectively. Permeability ranges from less than 1 md to almost 1000 md. Fine scale (inches) changes in siderite composition and concentration play a dominant role in determining sandstone reservoir quality. Average permeability determined from well testing at Palm #1A is approximately 100 md.

Seismic mapping indicates that the gross thickness of the "C4" reservoir ranges from 7.5 feet to 35 feet in the DS 3S area.

6. Structure The top reservoir lies at a depth of 5750' to 5800' TVD subsea in the DS 3S area. The oil-water contact in the main Kuparuk reservoir is at -6570' subsea and is approximately 800' down structure from the Drill Site 3S area. The DS 3S extension of the Kuparuk River Oil Pool is largely located west of a series of closely spaced north-south trending normal faults that, prior to the drilling of the Palm and Palm 1A exploratory wells, had coincided with the western limit of Kuparuk River Unit production. The western portion of the DS 3S extension of the Kuparuk River Oil pool is moderately faulted and gently dipping.

7. Pool Limits The western, northern and southern limit of the "C4" sand in the DS 3S area is based on seismic mapping techniques. Additional drilling will be required to more accurately define the boundaries. The thickness and areal extent of the "C4" sand towards the east is also uncertain. However, pressure communication between the "C4" in the DS 3S area and the main Kuparuk reservoir located approximately three miles apart is suggested because of the existence of similar reservoir pressures- approximately 650 psi above original.

8. Fluid Contacts There is no evidence of free gas accumulation or an oil water contact within the DS 3S extension of the Kuparuk River Unit, Kuparuk River Oil Pool.

9. Fluid Properties Reservoir fluid properties are estimated from fluids recovered during RFT sampling on the Palm #1 well and a cased-hole test of the Palm #1A well. The range of API gravities from these samples is 24-26 and solution GOR is approximately 485 SCF/STB. Paraffin and asphaltene content is low. The fluid sample measurements show similarities to crude properties in the main Kuparuk River Field, Kuparuk River Oil Pool.

10. Hydrocarbon Recovery CPA estimates approximately 74 million barrels oil ("MMBO") originally in place ("OOIP") in the Drill Site 3S area that will be developed with 20 wells. An enhanced recovery process will be initiated within six months after first production. Studies conducted by CPA resulted in selecting the alternating cycling of water and miscible gas ("MWAG") process. The MWAG process yielded greater recoveries than other processes evaluated which included primary, waterflood, miscible injection ("MI") and lean gas flood. Recovery is expected to be 36 MMBO or about 48% of the OOIP including primary, waterflood and enhanced recovery. Estimated recoveries from simulation studies of the DS 3S area are primary - 20%, waterflood - 20% and MWAG - 6-8%. As a comparison, ongoing MWAG processes in the main Kuparuk reservoir "C" sands to the east have experienced incremental oil recovery of 8%-12% OOIP over base waterflood recoveries.

The miscible injectant will initially be the same as that currently used in the KRU Large Scale EOR Project. It is manufactured at Kuparuk Central Production Facility ("CPF-1") and CPF-2 by blending lean gas from the KRU's production facilities with solvent (i.e., light hydrocarbon liquid streams) from the PBU and KRU.

The final phase, lean gas injection, is expected to maximize recovery of the light hydrocarbon liquids that were injected into the reservoir as part of the MWAG stream. The source of the lean gas will likely be KRU's CPF-2. However, other potential gas sources will be considered.

11. Development Plan DS 3S development involves the addition of one new drill site to the Greater Kuparuk Area ("GKA"), along with required ancillary and support facilities. The drill site is designed to accommodate a total of 26 wells on 20-foot centers. Plans to develop the DS 3S area on nominally a 160-acre well spacing are consistent with Rule 3 of Conservation Order No. 432A dated August 11, 1999. The project will include 12 producer and 8 injector wells. The Palm 1A exploration well will be completed as a producer.

The Drill Site will tie into the existing GKA infrastructure at DS 3G and utilize existing Central Production Facility 3 (CPF-3) to process produced fluids. A new 8-inch water injection line runs from DS 3G to 3S and an 8-inch MI injection line runs from KRU DS 3F past DS 3G to DS 3S.

The facilities are designed for daily operations to require minimal operator presence. All data gathering and routine operations are to be accomplished remotely from CPF 3 or DS 3S control room. Facilities to be installed at the drill site include production, test, water injection and MI injection lateral piping and headers; test separator for well testing; and instrumentation, control, and communication equipment. Testing can take place remotely through a divert valve system, which redirects the flow from the production header to the test separator.

A 4.8 mile road will connect the new drill site to the existing road system is routed from DS 3G to DS 3S.

Production is currently scheduled for start-up during 4th quarter 2002. Initial injection support would commence no later than six months after first production.

12. Well Design and Completion CPA will construct two types of wells to develop the Drill Site 3S area. Injectors and producers will be constructed with either long string or top set completions. A long string completion will employ 30" conductor casing to approximately 75 feet, 9-5/8" surface casing set below the base of the West Sak Formation, 7" production casing run from surface through the Kuparuk River Formation. Top set completions will employ 30" conductor casing to approximately 75 feet, 9-5/8" surface casing set below the base of the West Sak Formation, with 7" intermediate casing run from surface to just above the Kuparuk River Formation with a 3-1/2" production liner set through the production interval. Production wells will be equipped with 3-1/2" tubing and completions will include down hole "jewelry" that will allow the use of artificial lift, including hydraulic jet pump, hydraulic piston pumps, lift gas, or plunger lift systems to be installed as needed. Initially, gas lift is planned.

13. Reservoir Surveillance Plans Reservoir surveillance plans adhere to the requirements of CO 432A.


1. The Kuparuk River Oil Pool rules apply to the affected area described in CO 349A, as modified by CO 471.

2. There is sufficient data to support expansion of the affected area for Kuparuk River Oil Pool rules to include the Drill Site 3S area. Expansion under this order will prevent waste, protect fresh water, protect correlative rights, and ensure greater ultimate recovery.

3. It is appropriate to incorporate the affected area into this order.


1. This Conservation Order supersedes 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 are adopted by reference and incorporated in this decision.

2. The affected area of this conservation order is expanded to include T12N, R7E Sections 1,2,11,12,13,14,15,16,21,22,23, and 24.

3. 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:

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.

T10N, R8E, U.M.

T10N, R9E, U.M.

T10N, R10E, U.M.

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,
30,31,32,33,34,35 and 36.

T11N, R8E, U.M.

T11N, R9E, U.M.

T11N, R10E, U.M.

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.

T12N R9E U.M.

T12N, R10E, U.M.
SECS. 1,2,3,4,5,6,7,8,9,10,11,12,14,15,16,17,
34,35 and 36.

T12N, R11E, U.M.
SECS. 3,4,5,6,7,8, and 31.

T13N, R8E, U.M.
SECS. 13,14,23,24,25,26,27,28,33,34,35 and 36.

T13N, R9E, U.M.

T13N, R10E, U.M.

T13N, R11E, U.M.
SECS. 7,8,16,17,18,19,20,21,28,29,30,
31,32, and 33.

T14N R9E U.M.
SECS. 1,2,3,4,5,6,7,8,9,10,11,12,13,14,
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 (Ref. CO 173, & 182)

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: (Source CO 173)

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 182)

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

(a) Casing and cementing requirements are as specified in 20 AAC 25.030, CASING AND CEMENTING, except as modified below. (Source CO 173)

(b) 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)

(c) 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 Casing
Depth Pursuant to
Rule 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
CO 193 2A, 2B, 2D, 2F, 2G, 2H, 2V 3200' TVD
CO 203 1L, 1Q, 1R, 2E, 2U, 2W, 3B,
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

(d) 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.

(e) 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 application. (Source CO 173)

(f) 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)

(a) 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)

(b) 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)

(c) A representative of the Commission will 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)

(a) A bottom-hole pressure survey shall be taken on each well prior to initial sustained production. (Source CO 230)

(b) 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)

(c) 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)

(d) 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)

(e) 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)

(f) 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)

(a) 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)

(b) 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)

(c) 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)

(d) 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)

(a) A well test must be performed on each active producing well at least once every 30 days.

(b) 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.

DONE at Anchorage, Alaska and dated December 12, 2002.

Cammy Oechsli Taylor, Chair
Alaska Oil and Gas Conservation Commission

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

Michael L. Bill, P.E., Commissioner
Alaska Oil and Gas Conservation Commission

Conservation Order Index