STATE OF ALASKA

ALASKA OIL AND GAS CONSERVATION COMMISSION
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
Re: The REQUEST OF STEWART 		)	Disposal Injection Order No. 7      
    PETROLEUM COMPANY to dispose	)
    of Class II oil field fluids by     )       West McArthur River D-l well
    underground injection in the West	)
    McArthur River D-l well.      	)
                                 	        April 19, 1993
IT APPEARING THAT:

1. Stewart Petroleum Company by correspondence dated March 3, 1993 made application to the Alaska Oil and Gas Conservation Commission (AOGCC) for authorization to inject Class II waste fluids into the West McArthur River D-l well.

2. Notice of an opportunity for public hearing was published in the Anchorage Daily News on March 5, 1993.

3. No protest or request for a public hearing was timely filed.

FINDINGS:

1. No wells penetrate the proposed injection zone within a one-quarter mile radius of the West McArthur River D-l well (WMR D-l).

2. Cook Inlet Region, Inc., State of Alaska, Salamatof Native Association, Inc., and Phillips Petroleum Company are offset operators and surface owners within a one-quarter mile radius of the WMR D-l and have been duly notified of the proposed plans.

3. CIRI has designated Stewart Petroleum as operator of the WMR D-l.

4. The WMR D-l was drilled to the subsurface estate of Cook Inlet Region, Inc. (CIRI) to a total depth of 4502 feet measured depth.

5. The Tyonek Formation consisting of Lower Tertiary aged, massively bedded, fluvial deposits is present within the WMR D-l from approximately 3000 feet measured depth to total depth.

6. A highly porous and permeable sandstone with calculated porosity and permeability of 32 percent and 1600 millidarcies respectively is present from 4283 to 4351 feet measured depth (4120 to 4188 feet subsea).

7. Formation water with total dissolved solid (TDS) content of at least 11,800 parts per million (ppm), as determined by EPA method 160.1, is present in the sandstone occurring from 4283 to 4351 feet measured depth.

8. An impermeable confining zone composed of shale, coal and minor discontinuous sands and siltstones is present in WMR D-l from 4184 to 4282 feet measured depth.

9. Openhole wireline log analyses and EPA-approved laboratory analyses of formation water samples indicate underground sources of drinking water (USDWs) are present (TDS < 10,000 ppm) to 4184 feet measured depth (4021 feet subsea) in WMR D-l.

10. Openhole wireline log analyses indicate the deepest non-exemptable aquifer (TDS < 3000 ppm) occurs at a measured depth of 1335 feet.

11. Nine and 5/8-inch surface casing string is set at 1361 feet measured depth, cemented to the surface and tested to 2500 psi.

12. Seven-inch casing is set at 4500 feet measured depth and cemented to at least 2000 feet above its base.

13. Two and 7/8-inch tubing with packer is installed, with the packer set at 4197 feet measured depth.

14. With tubing and packer in place, the 7-inch casing was pressure tested to 1000 psi.

15. Cement evaluation tools run in WMR D-l indicate good to excellent cement bond over most of the cemented interval of the 7-inch casing string.

16. The operator estimates that the injection rate will not exceed 6000 bbl/day.

17. The estimated average operating pressure will be 800 to 1000 psi and the maximum anticipated surface injection pressure will be 1115 psi.

18. A three-dimensional hydraulic fracture simulator run at rates and pressures exceeding those planned in the WMR D-l, due to wellhead and equipment limitations, indicates induced fractures will not propagate through the overlying confining zone.

19. A mechanical integrity test has not been performed on WMR D-l.

20. The operator plans to monitor the 7-inch casing by 2 7/8-inch tubing annulus pressure and report the results on the Monthly Injection Report.

21. Prior to commencing injection operations in WMR D-l, the operator plans to perform a step rate test in order to determine the formation fracture gradient and optimum injection rate.

CONCLUSIONS:

1. The approval of disposal injection operations at WMR D-l will not jeopardize correlative rights.

2. Permeable strata which reasonably can be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata are present in the interval from 4283 to 4351 feet measured depth in WMR D-l.

3. The interval from 4283 to 4351 feet measured depth in WMR D-l does not qualify as a USDW.

4. An impermeable confining zone is present in WMR D-l from 4184 to 4282 feet measured depth.

5. Disposal fluids injected at WMR D-l will consist exclusively of Class II waste generated from drilling, completion and production operations.

6. WMR D-l is constructed in conformance with the requirements of 20 AAC 25.412.

7. Well integrity must be demonstrated in accordance with 20 AAC 25.412 prior to initiation of disposal operations in WMR D-l.

8. Operational parameters will be monitored routinely at the WMR D-l for disclosure of possible abnormalities in operating conditions.

9. No application for a freshwater aquifer exemption is required in conjunction with the proposed disposal injection project in WMR D-l because TDS content exceeds 10,000 ppm for the formation fluids within the proposed disposal zone.

10. Disposal injection operations in the WMR D-l will be conducted routinely at pressures less than disposal zone parting pressure.

NOW, THEREFORE, IT IS ORDERED THAT:

Rule 1 Authorized Injection Strata for Disposal.

Class II oil field fluids may be injected in conformance with Alaska Administrative Code Title 20, Chapter 25, for the purpose of disposal into the Tyonek Formation interval from 4283 to 4351 feet measured depth in WMR D-l.

Rule 2 Demonstration of Tubing/Casing Annulus Mechanical Integrity

Prior to initiating injection and at least once every four years thereafter the tubing/casing annulus must be tested for mechanical integrity in accordance with 20 AAC 25.412.

Rule 3 Well Integrity Failure

Whenever 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 of a plan for corrective action and obtain Commission approval to continue injection.

Rule 4 Step Rate Test

Prior to sustained injection the operator shall perform a step rate test to determine a formation fracture gradient and optimum injection pressure.

Rule 5 Administrative Action

Upon request, the Commission may administratively revise and reissue this order upon proper showing that any changes are based on sound engineering practices and will not result in an increased risk of fluid movement into an underground source of drinking water.

DONE at Anchorage, Alaska and dated April 19, 1993.

David W. Johnston, Chairman
Alaska Oil and Gas Conservation Commission

Russell A. Douglass, Commission
Alaska Oil and Gas Conservation Commission

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