STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7th Avenue, Suite 100
Anchorage Alaska 99501

Re: THE APPLICATION OF Marathon Oil Company for disposal of Class II oil field wastes by underground injection in the Sterling Formation in the Sterling Unit No. 43-9 Well, Section 9, T5N, R10W, S.M. )
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Disposal Injection Order No. 25

Sterling Unit Gas Field
Sterling Unit No. 43-9 Well

Originally Issued April 3, 2003, and Corrected June 15, 2004

IT APPEARING THAT:

1. By correspondence dated January 24, 2003 to the Alaska Oil and Gas Conservation Commission (“AOGCC”), Marathon Oil Company (“Marathon”) requested authorization to allow the underground injection of non-hazardous Class II oil field waste fluids into the Sterling Formation within the Sterling Unit No. 43-9 (“SU 43-9”) well bore. The SU 43-9 well is located in the Sterling Gas Field, Kenai Peninsula Borough, Alaska.

2. Notice of opportunity for public hearing was published in the Anchorage Daily News on February 7, 2003 in accordance with 20 AAC 25.540.

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

4. The original Disposal Injection Order No. 25 contained an omission. Finding No. 11 of the original order omitted the date that Aquifer Exemption No. 9 was issued and this corrected order is issued to clarify the omission.

FINDINGS:

1. Location of adjacent wells (20 AAC 25.252 (c)(1)

There are three wells with surface locations within a one-quarter mile radius of the SU 43-9 well, the Sterling Unit 32-9 and 41-15 production wells and a Marathon operated water well. There are 1,026 water wells located in the 36 square miles of T5N, R10W Seward Meridian. The average depth of these wells is 91’ measured depth (“MD”), the minimum depth is 6’ MD and the maximum depth is 451’ MD.

2. Notification of Operators/Surface Owners (20 AAC 25.252 (c)(2) and 20 AAC 25.252 (c)(3))

Marathon is the operator of the Sterling Unit. There are no other operators within a one-quarter mile radius of the proposed disposal injection well. The sole surface owner within a one-quarter mile radius of the SU 43-9 well is the Salamatof Native Association, Inc. The Salamatof Native Association, Inc. was provided with a copy of Marathon’s application for disposal injection in the SU 43-9 well prior to February 4, 2002.

3. Geologic information on disposal and confining zones/ Potential impact on an adjacent producing well. (20 AAC 25.252 (c)(4))

Marathon proposes to conduct disposal operations in the SU 43-9 well in the Sterling Formation B-4 Sandstone interval between 5,015’ subsea and 5113’ subsea, (5262’ and 5360’ MD). The disposal interval is a depleted gas sand in the Pliocene aged Sterling Formation. The proposed B-4 sandstone disposal interval in the SU 43-9 well has estimated porosities of up to 35%, permeabilities in excess of 200 millidarcies and a net vertical thickness of 100’. The lithologies of the Sterling Formation were deposited in fluvial environments and are composed primarily of very permeable and porous, very fine to coarse-grained sandstones and conglomerates interbedded with coals, shales, and siltstones. Approximately 50’ of confining lithologies (shale and siltstone) directly overly the proposed disposal zone in SU 43-9. Of the 1,000’ of the Sterling Formation in the SU 43-9 well overlying the proposed disposal interval, approximately 40 percent is composed of laterally continuousconfining lithologies.

An adjacent well, the SU 32-9 well is currently producing from the B-4 sandstone. The horizontal separation between the two wells in the B-4 sand is 1,700’. Marathon used reservoir simulation to assess the potential recovery impacts of disposal injection in the B-4 sandstone through SU 43-9 on the SU 32-9 well. The model incorporated all current subsurface information on the B-4 sand including historic production and pressure data. An acceptable history match was obtained. Marathon modeled a daily average of 500 barrels per day of disposal injection through the year 2016. Results indicate that water injected into the existing perforations in SU 43-9 falls rapidly through the reservoir and causes the overall gas-water contact to rise uniformly, rather than creating a piston-like waterflood displacement moving toward producer SU 32-9. The simulation indicates the proposed SU 43-9 disposal injection project will not have an appreciable impact on gas recovery from the Sterling Formation B-4 Sandstone.

4. SU 43-9 Logs (20 AAC 25.252 (c)(5))

The logs of the SU 43-9 well are on file at the AOGCC.

5. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252 (c)(6))

No cement quality log is available for SU 43-9. An injectivity test was conducted on the B-4 interval in 43-9 on February 25, 2000. The test employed a suite of logs designed to detect any significant out of zone leakage. These tools included; a borax activation log, an oxygen activation log, a temperature, and a pressure log. The test was conducted at 3.2 barrels per minute (over 4,000 barrels per day) a rate that exceeds anticipated disposal injection rates. The results of this test demonstrate the B-4 completion in SU 43-9 is appropriately isolated.

The SU 43-9 well met the mechanical integrity requirements of 20 AAC 25.412 during a test witnessed by an AOGCC inspector on October 23, 2002. Marathon has proposed a pressure testing procedure for SU 43-9 that will satisfy the mechanical integrity requirements of 20 AAC 25.412. This procedure will be used for mechanical integrity testing after authorization is given for disposal injection. The test of October 23, 2002 is sufficient to allow Marathon begin disposal service.

6. Casing Description Well SU 43-9 (20 AAC 25.252 (c)(6)(A))

There are two strings of casing as follows:

7. Disposal Fluid Type, Source, Volume and Compatibility with Disposal Zone (20 AAC 25.252 (c)(7))

The primary disposal fluid planned for this well is produced water from the Sterling Unit. Additionally, Class II fluids from other Marathon operated properties on the Kenai Peninsula will be injected. Typical Class II wastes planned for this disposal project are drilling, completion, workover and produced fluids, glycol dehydration wastes, rig wash, drilling mud slurries, tank bottoms, NORM scale, precipitation within containment areas, and other approved Class II wastes generated from drilling, completion, workover, and production operations. Current projections estimate that a maximum of 1,000 barrels per day of fluid will be injected with daily average volume of less than 500 barrels. Compatibility of the proposed disposal fluids with the formation waters of this depleted portion of a gas reservoir is not likely to affect the storage capacity of the B-4 sandstone adjacent to well SU 43-9.

8. Estimated Injection Pressure (20 AAC 25.252 (c)(8))

The estimated average injection pressure will be 1,800 psig and the maximum injection pressure will be 3,000 psig.

9. Evaluation of Confining Zones (20 AAC 25.252 (c)(9))

A correlative interval in well SU 32-9 was evaluated to determine the fracture potential of the B-4 Sandstone in SU 43-9. Marathon drilled SU 32-9 in 1998 and obtained a modern petrophysical log suite. The B-4 interval lithology is similar in these wells that are approximately 1700’ apart. The SU 32-9 data was used to estimate lithologic parameters such as Poisson’s Ratio, Young’s Modulus and closure stress used for fracture analysis. The lithologic parameters were adjusted to SU 43-9 thickness and depths.

A commercial fracture model was used to evaluate the fracture potential of two operational scenarios representative of SU 43-9 disposal. The first simulation was assumed constant injection of 1,440 barrels per day of 4% KCL water with .10 pounds per gallon (“ppg”) 100-mesh solid load for one year. The inclusion of a small solid load represents a realistic estimate for produced water disposal where small amounts of solids tend to plug permeable layers and cause fracture growth.

The second simulation represented conditions observed during disposal of drilling mud and cuttings at Marathon’s Kenai Gas Field. The simulation assumed 1,440 barrels per day of 4% KCL with 5.50 ppg 100-mesh solids load for two weeks. A 100-mesh solid load is a worst-case scenario where fine solids plug the formation and make fractures more likely to propagate. The simulation replicated conditions at the Marathon Kenai Field disposal operation where slurry injection is generally conducted in batches during periods when drilling is active. Batches of solids are injected over limited periods to allow fluids to leak off and fractures to heal.

In both cases fractures were confined by the shale interval at the top of the B-4 Sandstone.

10. Standard Laboratory Water Analysis of the Disposal Zone (20 AAC 25.252 (c)(10))

A 1995 laboratory water analysis of B-4 Sandstone formation water from well SU 43-9 yielded 1,931 parts per million (“ppm”) TDS and 1,615 ppm NaCl equivalent.

11. Freshwater Exemption (20 AAC 25.252 (c)(11))

Aquifer Exemption Order No. 9, dated April 3, 2003 exempts aquifers below 1750’ MD and within ¼ mile of well SU 43-9.

12. Mechanical Condition of Wells Penetrating the Disposal Zone within ¼ Mile of SU 43-9 (20 AAC 25.252 (c)(12)

There are three wells with surface locations within a one-quarter mile radius of the SU 43-9 well, the Sterling Unit 32-9 and 41-15 production wells and a Marathon operated water well. The Marathon operated water well does not penetrate the B-4 Sandstone. Wells SU 32-9 and 41-15 are directionally drilled and do not penetrate the B-4 sandstone within ¼ mile of the SU 43-9 well.

CONCLUSIONS:

1. The application requirements of 20 AAC 25.252(c) have been met.

2. No wells penetrate the disposal zone within ¼ mile of the SU 43-9 well.

3. Aquifer Exemption Order No. 9 exempts aquifers below 1750’ MD and within ¼ mile of well SU 43-9.

4. Waste fluids will be contained within appropriate receiving intervals by the confining lithologies in the Sterling Formation, cement isolation of the well bore and operating conditions.

5. Disposal injection operations in the SU 43-9 well will be conducted at rates and pressures below those estimated to fracture the confining zone.

6. Evaluation of surveillance and operational performance data will reasonably assure there is no fracturing of the confining zone.

7. Surveillance of disposal volumes, daily monitoring of operational parameters, and demonstration of mechanical integrity will reasonably ensure continued mechanical integrity of the well and that waste fluids are contained within the disposal interval.

8. Disposal injection of Class II wastes into well SU 43-9 will not cause waste, jeopardize correlative rights, or impair ultimate recovery.

NOW, THEREFORE, IT IS ORDERED THAT:

RULE 1: Authorized Injection Strata for Disposal
Injection of authorized fluids for purposes of underground disposal of oil field wastes is permitted into the Sterling Formation between 5260’ and 5360’ MD in the SU 43-9 well, in the Sterling Unit.

Other disposal zones in the SU 43-9 may be approved for disposal following a demonstration that the requirements of 20 AAC 25.252(c) and Aquifer Exemption Order No. 9 have been satisfied. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata.

RULE 2: Authorized Fluids
Fluids authorized for injection in the SU 43-9 well are:


1. produced water
2. drilling, completion and workover fluids
3. drilling mud
4. Norm scale
5. tank bottoms
6. rig wash
7. glycol dehydration wastes
8. precipitation accumulating within containment areas
9. Other fluids suitable for disposal in a Class II well and approved by the commission on a case-by-case basis.

RULE 3: Demonstration of Tubing/Casing Annulus Mechanical Integrity
Within 180 days of initiating disposal service, the Commission must be contacted to allow a representative of the Commission to witness an additional mechanical integrity test in SU 43-9.

In addition to the requirements of 20 AAC 25.252 (d), mechanical integrity of the disposal well must be demonstrated at least once every two years.

RULE 4 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, or a lack of disposal zone isolation, the operator must immediately notify the Commission, obtain Commission approval to continue injection and submit a plan for corrective action for Commission approval.

RULE 5: Surveillance
Operating parameters including disposal rate, disposal pressure, annulus pressures, step rate test results and volume of fluids and solids pumped must be monitored and reported according to requirements of 20 AAC 25.432(1). The operator shall obtain a baseline temperature log and a baseline step rate test prior to initial injection. An initial report of operations must be provided after one month of injection. An annual report for the calendar year evaluating the performance of the disposal operation must be submitted by July 1 of each year.

RULE 6: Notification of Improper Class II Injection
The operator must immediately notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators’ responsibility.

RULE 7: Administrative Action
Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule 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 an increased risk of fluid movement into freshwater.

RULE 8: Other Conditions
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless specifically superseded by Commission order. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order may result in the revocation or suspension of this authorization.

DONE at Anchorage, Alaska and dated April 3, 2003.
Corrected June 15, 2004

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

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

Disposal Injection Order Index