IT APPEARING THAT:

1. By correspondence dated October 24, 1997, AAI requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to inject Class II waste fluids into three Prudhoe Bay wells located at the Surfcote pad as part of a continuing Grind and Inject (G&I) waste disposal project.

 
2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on November 14, 1997.

 
3. The Commission did not receive protest or a request for a public hearing.

1. The Commission has issued the following Area Injection Orders and approvals for the Eastern Operating Area of the Prudhoe Bay Unit: Area Injection Order 4 on July 11, 1986, Administrative Approval 4.1 on October 28, 1996, Area Injection Order 4A on August 12, 1993, revised October 4, 1993, and a letter approval on July 5, 1994.

 
2. The hearing records and administrative files for the above listed Area Injection Orders and approvals remain valid for the Eastern Operating Area of the Prudhoe Bay Field, and are incorporated by reference into this order.

 
3. AAI proposes the Surfcote disposal injection project as a replacement for disposal injection in the Drill Site 4-19 well. The DS 4-19 well is no longer approved for disposal injection under Commission letter dated April 15, 1997.

 
4. AAI is the operator of the Eastern Operating Area of the Prudhoe Bay Unit. There are no other operators within a one-quarter mile radius of the proposed Surfcote disposal injection project.

 
5. The State of Alaska is the only surface owner within one mile of the proposed Surfcote disposal injection project.

 
6. AAI proposes to complete the Surfcote wells with 20" conductor casing, 13 3/8" surface casing set at about 3900' TVD and cemented to surface, 9 5/8" injection casing set at about 7000' TVD and cemented to within 50 feet of the surface casing shoe, and 7" tubing and packer set at about 4000' TVD.

 
7. Material intended for slurry injection will consist of Class II wastes as follows: 1) excavated material from existing reserve pits in the Prudhoe, Kuparuk, and Lisburne fields, commingled with seawater from the Seawater Treatment plant, treated produced water from Flow Station 2, or water produced from the Tertiary/Cretaceous formations in the Drill Site 4vicinity; 2) waste drilling muds and cuttings from development and exploratory drilling operations on the North Slope; 3) other Class II solid wastes, including but not limited to materials as oily solid waste removed from oil processing and treating facilities; and 4) other Class II fluids, such as reserve pit water from snowmelt, workover fluids, contaminated crude, produced water, diesel, gel, and glycol associated with well production operations.

 
8. The maximum G&I Plant injection capacity is approximately 40,000 barrels per day, with a target slurry density between 9.5 and 11 pounds per gallon.

 
9. Estimated average surface injection pressure for slurry disposal will be between 1,300 and 2,000 psi, depending on the density of the fluid and the injection rate.

 
10. AAI proposes to operate the Surfcote wells concurrently or on a revolving schedule to evenly distribute the volume of waste being injected into the three wells.

 
11. Fracture propagation within the disposal interval is an integral part of the process of placing waste slurries into the disposal interval. Fractures will be created as disposal zone porosity and permeability is occluded by the deposition of solids in pore spaces. Fractures provide pathways to transport waste fluids to unfilled areas within the disposal zone.

 
12. Fracture propagation caused by large-scale injection of solids in loosely consolidated formations is not fully understood at this time.

 
13. AAI will run cement quality logs within the surface casing and long string of each Surfcote well to determine the adequacy of the cement to isolate disposal intervals.

 
14. AAI will test tubing and casing integrity according to 20 AAC 25.412 prior to initiation of slurry injection operations and every two years thereafter

 
15. A fluid broach occurred in March 1997 at the DS4-19 well. Data collected confirmed the existence of thaw bulbs around wellbores on the pad.

 
16. AIO#4 approved disposal injection into strata that correlates with strata found in the ARCO Sag River State Well No. 1 between the measured depths of 1900 feet and 6750 feet.

 
17. AIO#4A found this interval to be overlain with Tertiary shale and mudstone beds, between 10 and 50 feet thick, and approximately 1,800 feet of permafrost, which isolates the disposal interval from surface waters.

 
18. No Class II injection has occurred in an interval shallower than 4500 feet in the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre field.

 
19. A layer of confining shale lithology, which correlates with the interval between 3505 feet and 3607 feet measured depth in the ARCO Sag River No. 1 well, exists throughout the Eastern Operating Area of the Prudhoe Bay Unit and Pt. McIntyre field.

 
20. Periodic surveillance of slurry injection operations will ensure waste fluids are contained within the disposal interval. Surveillance methods include temperature surveys, pressure transient tests, step rate tests, thermal decay time logs, disposal rate and pressure monitoring, mechanical integrity tests and tagging effective depth to determine fill buildup.

 
21. Reservoir surveillance techniques will also be used for tracking near wellbore fluid movement, estimating dimensions of disposal fracture or disposal storage volume and detecting changes in disposal zone characteristics in slurry injection wells.

 
22. AAI will evaluate operational performance and reservoir surveillance to aid in preventing fracturing of the confining zones.

1. The requirements of 20 AAC 25.252 have been met for the AAI proposed Surfcote pad disposal injection project.

 
2. It is reasonable to issue a revised area injection order for the Eastern Operating Area of the Prudhoe Bay Unit and Pt. McIntyre fields to include the Surfcote disposal injection project. The record for this order should include the hearing record and administrative files from AIO#4, AIO#4A, AA4.1 and approval letter dated July 5, 1994.

 
3. Permafrost is not an appropriate barrier to fluid flow after thaw bulbs develop around producing wells.

 
4. It is reasonable to redefine the approved interval for disposal injection in the Eastern Operating Area of the Prudhoe Bay Unit and Pt. McIntyre field to an interval overlain by confining shale, and not rely in any manner on the presence of permafrost to confine disposed fluids.

 
5. No underground sources of drinking water are known to exist in the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field.

 
6. Waste fluids authorized for disposal under this order will consist exclusively of Class II waste generated from drilling, completion, workover, production and reserve pit closure operations.

 
7. Permeable strata which reasonably can be expected to contain the total volume of disposal fluid anticipated for this project are present in the West Sak, Ugnu and Sagavanirktok formations.

 
8. Movement of waste fluids will be confined within the appropriate receiving intervals by confining lithology, cement isolation of the wellbore and appropriate operating conditions.

 
9. It is reasonable to require a deeper injection zone for grind and inject operations because of the reliance on fracturing to place waste slurry into the disposal zone

 
10. Surveillance of disposal material movement, monitoring of operating parameters and demonstration of mechanical integrity every two years will ensure the slurry disposal materials are contained within the disposal interval. Changes from initial conditions may be an indication that fluid is escaping beyond the designated confining zone.

 
11. Prudhoe Bay Unit disposal wells will be constructed and demonstrate mechanical integrity in accordance with the requirements of 20 AAC 25.412.

 
12. Disposal injection operations in the Prudhoe Bay Unit will not cause waste, jeopardize correlative rights, or impair ultimate recovery.

UMIAT MERIDIAN

T12N R14E Sections 3, 4, 9, 10, 13, 14, 15, 16,
Section 17: NE ¼, N ½ SE ¼, E ½ E ½ NW ¼, E ½ NE ¼ SW ¼,
Section 21: N ½ NE ¼,
Sections 22, 23, 24, 25, 26, 35, and 36.

T12N R15E Sections 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30,
31, 32, 33, 34, 35, and 36.

T12N R16E Sections 28, 29, 30, 31, 32, 33, and
Section 34: W ½ NW ¼, SW ¼, SW ¼ SE ¼

T11N R14E Sections 1, 2, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23,
24, 25, 26, 27, 28, 33, 34, 35, and 36.

T11N R15E Entire Township.

T11N R16E Section 2: SW ¼ NW ¼, SW ¼, S ½ SE ¼,
Sections 3, 4, 5, 6, 7, 8, 9, 10, 11,
Section 12: NW ¼, S ½ NE ¼, SE ¼, SW ¼
Sections 13, 14, 15, 16, 17, 18, 19, 20, 21, 28, 29, 30,
31, 32, and 33.

T10N R14E Sections 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 21,
22, 23, 24, 25, 26, 27, 28, and 36.

T10N R15E Entire Township.
 
T10N R16E Sections 4, 5, 6, 7, 8, 9, 16, 17, 18, 19, 20, 29, 30, and 31.
 
Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM AK (identical with line 4-5 on block 605) and lying easterly of the west boundary of sections 2 and 11, T12N, R14E, UM, AK (identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, R14E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, R15E, UM, AK (identical with line 6-7 on block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram," approved 12/9/79, containing 1457.32 hectares.

Rule 1 Authorized Injection Strata for Enhanced Recovery

Within the affected area, Class II fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to the formations found in the ARCO Prudhoe Bay State No. 1 well between the measured depths of 8,110-8,680 feet for the Prudhoe oil pool and between the measured depths of 8,790-10,440 feet for the Lisburne oil pool and in the Pt. McIntyre No. 11 well between the measured depths of 9,908-10,665 feet for the Pt. McIntyre oil pool.

Rule 2 Authorized Injection Strata for Disposal

Within the affected area, Class II waste fluids may be disposed by injection into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured depths of 3,607-6,750 feet.

Class II slurry injection from the Grind and Inject processes may be disposed into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured depths of 4,270-6,750 feet.

Rule 3 Fluid Injection Wells

The injection of fluids must be conducted: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the date of this order.

Rule 4 Monitoring the Tubing-Casing Annulus Pressure Variations

The tubing-casing annulus pressure of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength.

Rule 5 Reporting the Tubing-Casing Annulus Pressure Variations

Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission.

Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity

A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. For slurry injection wells, the tubing/casing annulus must be tested every two years for mechanical integrity. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength must be held for at least a 30 minute period with decline no more than or equal to 10% of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests.

Rule 7 Well Integrity Failure

Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue injection and submit a plan of corrective action on Form 10-403 for Commission approval.

Rule 8 Plugging and Abandonment of Injection Wells

An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105.

Rule 9 Administrative Action

Upon proper application, 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, is based on sound engineering principles, and will not result in an increased risk of fluid movement into an USDW.

Rule 10 Surveillance

For slurry injection wells, a baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. Operating parameters including disposal rate, disposal pressure, annuli pressures and volume of slurry pumped must be monitored and reported according to the requirements of 20 AAC 25.432.

Also for slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before July 1.

DONE at Anchorage, Alaska and dated April 13, 1998.
______________________________________________
David W. Johnston, Chairman
Alaska Oil and Gas Conservation Commission
______________________________________________
Robert N. Christenson, Commissioner
Alaska Oil and Gas Conservation Commission
______________________________________________
Camille Oechsli, Commissioner
Alaska Oil and Gas Conservation Commission