STATE OF ALASKA

ALASKA OIL AND GAS CONSERVATION COMMISSION

3001 Porcupine Drive

Anchorage, Alaska 99501-3192

Re:	THE REQUEST OF MARATHON              )   Disposal Injection Order No. 8
OIL COMPANY to dispose of Class II           )
oil field fluids by underground injection    )   Beaver Creek Unit No. 3
in the Beaver Creek Unit No. 3 well.         )   Beaver Creek Unit

                                                 May 13, 1993

IT APPEARING THAT:

1. Marathon Oil Company by correspondence dated March 15, 1993 made application to the Alaska Oil and Gas Conservation Commission (Commission) for authorization to inject Class II waste fluids into the Beaver Creek Unit No. 3 well.

2. Notice of an opportunity for public hearing was published in the Anchorage Daily News on April 1, 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 Beaver Creek Unit No. 3 well (BCU 3).

2. U.S. Bureau of Land Management and U.S. Fish and Wildlife Service are surface owners within a one-quarter mile radius of the BCU 3 and have been duly notified of the proposed plans.

3. Marathon Oil Company is the operator of the Beaver Creek Unit, no other operators are present within a one-quarter mile radius of the proposed BCU 3 disposal injection project.

4. BCU 3 was drilled to a total depth of 6387 feet measured depth.

5. The Sterling Formation, consisting of Pliocene age, massively bedded, predominately coarse grained, fluvial deposits is present within BCU 3 from approximately 2300 feet measured depth to total depth.

6. The proposed disposal injection zone consists of two permeable sandstones with calculated porosities of approximately thirty (30) percent which are present from 5804 to 5945 feet measured depth (4825 to 4938 feet subsea) in BCU 3 .

7. All aquifers (TDS <10,000ppm and >3000ppm) at depths greater than 1650 feet below ground level and extending one-quarter mile beyond the boundaries of the Beaver Creek Field are exempt pursuant to 40 CFR 147.102(b)(1)(ii).

8. Approximately 235 true vertical feet of impermeable confining zones composed predominately of claystones with minor interbedded coals and discontinuous siltstones separate the top of the proposed disposal injection zone in BCU 3 from the base of the non-exempt USDWs in the Beaver Creek Field.

9. Thirteen and 3/8-inch surface casing was set at 533 feet MD, cemented to surface and tested to 1000 psi. Intermediate 9 5/8-inch casing was set at 1569 feet MD, cemented to surface and tested to 1000 psi. The 7-inch production casing was set at 6380 feet MD, cemented to approximately 3300 feet MD and tested to 1000 psi.

10. Analysis of cement bond logs indicate casing strings have adequate cement behind casing to prevent vertical migration of disposal fluids.

11. The operator estimates the disposal rate will average 1000 B/D with a maximum up to 7200 B/D during drilling operations.

12. Average surface operating pressure is estimated to be 1600 psi during water disposal operations. Maximum surface disposal pressure will be less than 5000 psi, the maximum pressure rating of the casing head.

13. Results of a three-dimensional hydraulic fracture simulator run of a worst case scenario (i.e., injection pressures exceeding the anticipated formation parting pressure and using volumes of drill cuttings which surpass those expected for the BCU 3 project) indicate induced fractures will not propagate through the confining zone.

14. A casing mechanical integrity test will be performed in accordance with 20 AAC 25.412 prior to initiation of disposal operations.

15. The operator plans to monitor the 7-inch casing by 3 1/2-inch tubing annulus pressure daily and report the results on the Monthly Injection Report.

CONCLUSIONS:

1. The approval of disposal injection operations at BCU 3 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 5804 to 5945 feet measured depth in BCU 3.

3. Adequate confining zones exist above the receiving zone which assure injected fluids will not endanger USDWs.

4. Cement bond logs indicate the casing strings are adequately cemented to prevent vertical migration of disposal fluids behind casing.

5. Disposal fluids injected at BCU 3 will consist exclusively of Class II waste generated from drilling, completion and production operations.

6. BCU 3 was 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 BCU 3.

8. Operational parameters will be monitored routinely at BCU 3 for disclosure of possible abnormalities in operating conditions.

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 Sterling Formation interval from 5804 to 5945 feet measured depth in BCU 3.

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 May 13, 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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