|Re:The application of ARCO Alaska, Inc.("AAI")||)||Area Injection Order No. 4C (Corrected)|
|to amend AIO 4 to initiate a Miscible Gas||)||Eastern Operating Area|
|Enhanced Oil Recovery Project in the Point||)||Prudhoe Bay Unit|
|McIntyre Oil Pool and a Water and Gas Injection||)||Prudhoe Oil Pool|
|Enhanced Oil Recovery Project in the West||)||Lisburne Oil Pool|
|Beach Oil Pool.||)||Pt. McIntyre Oil Pool (amended)|
|)||Stump Island Oil Pool|
|)||West Beach Oil Pool (new)|
|March 23, 2000|
|Corrected April 19, 2000|
IT APPEARING THAT:
1. By correspondence dated November 8, 1999, AAI requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to initiate a miscible gas tertiary recovery project in the Point McIntyre Oil Pool and a waterflood enhanced oil recovery project in the West beach Oil Pool. Both projects are located in the Eastern Operating Area of the Prudhoe Bay Unit.
2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on November 20, 1999.
3. The Commission did not receive a protest or request for a public hearing.
4. The Commission held a hearing at the Commission’s offices on January 12 and 13, 2000.
5. A correction to Area Injection Order No. 4C is necessary in order to delete the third paragraph of Rule 10 that is redundant to requirements contained in Rule 13 of Conservation Order No. 311B and Rules 15 and 16 of Conservation Order No. 317B.
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 No. 4 on July 11, 1986, Administrative Approval No. 4.1 on October 28, 1986, Area Injection Order No. 4A on August 12, 1993, revised October 4, 1993, a letter approval July 5, 1994, and Area Injection Order No. 4B on April 13, 1998. Pools covered by prior iterations of Area Injection Order No. 4 include the Eastern Operating Area of the Prudhoe Oil Pool, Lisburne Oil Pool, Pt. McIntyre Oil Pool, and the Stump Island Oil Pool.
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 is the operator of the Eastern Operating Area of the Prudhoe Bay Unit including the Point McIntyre Oil Field and the West Beach Oil Pool. There are no other operators within a one-quarter mile radius of the proposed injection operations.
4. The State of Alaska is the only surface owner within one mile of the Point McIntyre Oil Field and the West Beach Oil Pool.
5. Facility modifications at the Lisburne Production Center (LPC) are designed to ensure that the volume of natural gas liquids extracted at the LPC will not be impacted by the manufacture of miscible injectant solvent.
Findings Related to the Pt. McIntyre Pool Miscible Gas Injection Project
6. AAI proposes to use hydrocarbons from the Pt. McIntyre, West Beach, North Prudhoe Bay, Niakuk and Lisburne Oil Pools processed in the LPC. Components from the natural gas liquid plant downstream from the feed flash drum will be added to enrich the miscible injectant (MI) stream to be used in the Point McIntyre enhanced recovery project.
7. Seventy-four producing and service wells were active in the Point McIntyre Oil Pool (PMOP) as of January 1, 1999. Fifteen water injectors and one gas injector were providing pressure support to the PMOP, maintaining average reservoir pressure near the original pressure of approximately 4370-psi.
8. The inverted nine-spot waterflood pattern in the PMOP is flexible and can be adapted to changes in reservoir performance as the enhanced recovery process matures.
9. The PMOP miscible gas injection project involves conversion of present and future waterflood injectors to water-alternating-gas (WAG) injection service.
10. A MI slug equivalent to approximately 35 percent hydrocarbon pore volume (HPV) will be placed over a twenty-three year period.
11. The maximum MI rate that can be manufactured from LPC residue gas is projected to be 50 MMSCFD at a minimum miscibility pressure of approximately 4350-psi.
12. An extensive performance history indicates that the Pt. McIntyre waterflood has been able to adequately balance voidage in the reservoir to maintain an average reservoir pressure of 4370 psi.
13. The minimum miscibility pressure is designed to be as close to average reservoir pressure as possible. This will maximize the volume of MI that can be manufactured at LPC.
14. Limited supply of MI will require phased implementation and conversion of patterns to WAG injection. Any volumes of MI in excess of the nominal 50 MMSCFD rate injected in the PMOP will have to be purchased from an external source.
15. The benefits of using additional MI, up to 100 MMSCFD purchased from an external source for this project, are being evaluated.
16. Modifications at LPC done in 1999 to manufacture MI included installation of an MI compressor, a new parallel chiller, new compressor coolers, blending station, and an upgrade of the natural gas liquid plant piping.
17. MI will be transported to the Point McIntyre drill sites by a new pipeline using existing vertical support members and new drill site distribution piping.
18. The geologic description of the injection and confining zones for both the PMOP miscible gas tertiary recovery project and the West Beach Oil Pool (WBOP) enhanced oil recovery project have been previously submitted in "Application for Modification to Area Injection Order No. 4" dated April 5, 1993.
19. Injection wells in the PMOP have been drilled, cased, cemented according to requirements of 20 AAC 25.005 and tested according to 20 AAC 25.412. Applications and completion records are on file at the AOGCC.
20. Seawater is currently injected in the Pt. McIntyre waterflood. It is possible that produced water will be used later in the project. Both water sources have previously been approved in Area Injection Order No. 4B.
21. Estimated average and maximum injection pressures (at pump discharge) for PMOP WAG wells are expected to be 4100 psi and 4500 psi respectively.
22. Surveillance and performance data for both water and gas injection in the PMOP indicates out of zone fractures have not occurred.
23. MI injection pressures are not likely to cause fracturing of the PMOP confining zones based on previous enhanced recovery injection performance.
24.Secondary recovery gas re-injection and pattern waterflood operations in the PMOP are projected to increase recovery to 42-45% of the original oil in place (OOIP).
25. The PMOP MI enhanced recovery project will increase oil recovery from the pool by 6% of the OOIP or by 32 MMSTB in the area where MI will be applied.
Findings Related to the West Beach Pool Injection Project
26. The WBOP is estimated to contain 15 to 25 MMSTB of oil in place.
27. Recent WBOP reservoir simulation studies, incorporating all well and seismic data, indicated a peripheral waterflood could increase recovery over primary depletion by an incremental 10-15% of the OOIP, about 2 MMSTB. Gas injection to recover "attic" oil along the southern boundary fault is being evaluated and may be implemented in the future.
28. After production tests of wells WB-05B and WB-06, a peripheral waterflood will be implemented by converting either WB-04 or WB-06 to water injection.
29. Potential injectors, WB-04 and WB-06, have been drilled, cased, cemented and tested according to requirements of 20 AAC 25.005. Applications and completion records are on file at the AOGCC. Whichever well is converted will be tested according to 20 AAC 25.412 prior to initiation of injection.
30. Facilities have been installed to accommodate additional production and injection wells if evaluation of field performance indicates additional reserves can be recovered.
31. The waterflood will be managed to replace reservoir voidage and injection rates will be modified in response to well performance.
32. The WBOP waterflood will utilize water produced from a dedicated source well drilled to the Tertiary Sagavanirktok Formation. Pump design capacity is expected to be 10,000 barrels per day.
33. No Sagavanirktok Formation water samples have been obtained from a West Beach pad well. Wireline log analyses of the West Beach State #1 well indicate Sagavanirktok Formation water samples from adjacent wells are representative of the interval in the West Beach Pad area.
34. Laboratory testing, core analyses and geochemical modeling indicate no significant problems are likely due to clay swelling or in-situ fluid compatibility problems between WBOP and Tertiary formation waters.
35. WBOP waterflood source water from the Sagavanirktok Formation is expected to have excess barium ion which could precipitate barium sulfate scale if mixed with PMOP produced water. WBOP produced water will be inhibited upstream of the commingling point with PMOP fluids to prevent scale precipitation.
36. Estimated average and maximum injection pressures (at the pump discharge) for WBOP water injectors are 2100 and 2850 psi respectively.
37. Injection pressures are not likely to fracture the WBOP confining zones based on previous injection performance in similar stratigraphy in the adjacent PMOP.
38. Potential benefits of gas injection in WBOP are being studied. Preliminary evaluation of gas injection estimates maximum gas injection of 25 MMSCFD with average and maximum injection pressures (at the pump discharge) of 4100 and 4500 psi respectively. No compatibility issues are anticipated between WBOP fluids and LPC residual gas.
1. The application requirements of 20 AAC 25.402 have been met for the AAI proposed PMOP miscible gas injection project and the WBOP enhanced oil recovery 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 PMOP miscible gas injection project and the WBOP injection project. The record for this order includes the hearing record and administrative files from: Area Injection Order No. 4 dated July 11, 1986, Administrative Approval No. 4.1 dated October 28, 1986, Area Injection Order No. 4A dated August 12, 1993, revised October 4, 1993, a letter approval dated July 5, 1994, and Area Injection Order No. 4B dated April 13, 1998.
3. No underground sources of drinking water are known to exist beneath the area covered by this order, the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field.
4. Injection operations in the PMOP and the WBOP will be conducted in permeable strata that can reasonably be expected to accept fluids at pressures less than the fracture pressure of the confining strata.
5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions.
6. The PMOP miscible gas injection project and the WBOP enhanced oil recovery project will both result in significant additional hydrocarbon recovery from the respective oil pools.
7. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests of injection wells will ensure successful implementation of these projects.
8. The PMOP miscible gas injection project and the WBOP injection project will not cause waste, jeopardize correlative rights, or impair ultimate recovery.
9. A plan to inject gas in the WBOP is being evaluated and is not complete.
NOW, THEREFORE, IT IS ORDERED that: (1) Area Injection Order No. 4C (Corrected) supersedes Area Injection Order No. 4C dated March 23, 2000; (2) The following rules govern Class II injection operations in the affected area described below:
|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, and 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||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, and 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||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, authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as follows:
For the Prudhoe Oil Pool strata 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 Lisburne Oil Pool strata which correlate with and are common to the formations found in the ARCO Prudhoe Bay State No. 1 well between the measured depths of 8,790-10,440.
For the Pt. McIntyre Oil Pool strata which correlate with and are common to the formations found in the Pt. McIntyre No. 11 well between the measured depths of 9,908-10,665 feet.
For the West Beach Oil Pool strata which correlate with and are common to the formations found in the West Beach No. 4 well between the measured depths of 14,458-14,781 feet.
For the Stump Island Oil Pool enhanced recovery plans will be evaluated on a well by well basis in conjunction with Pt. McIntyre Oil Pool development.
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, however when tubing-casing annulus pressure approximately equals the tubing pressure, the well must be shut-in and the Commission notified.
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 total decline of no more than 10% and must show pressure stabilization. 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, annulus 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.
Rule 11 Notification
The operator must 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.
CORRECTED April 19, 2000. Effective March 23, 2000.
Robert N. Christenson, P.E., Chair
Alaska Oil and Gas Conservation Commission
Camillé Oechsli Taylor, Commissioner
Alaska Oil and Gas Conservation Commission