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CO 198
Conservation Order Cover Page XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it retains it's current location in this file. ..Conservation Order Category Identifier Organizing (~o,~,) RF-~,~J'/ r~.-- Color items: [] Grayscale items: [] Poor Quality Originals: Other: NOTES: BY: ROBIN~ Scanning Preparation DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED (Scannable with large plotter/scanner) [] Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) ~' Logs of various kinds [] Other BY: ROBIN MARIA ~SI Production Scanning Stage I PAGE COUNT FROM SCANNED DOCUMENT: ~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: ,,~YES NO Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES ~ NO (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE APPLICATION OF ARCO ) ALASKA, INC. requesting an ) order approving a full-field) waterflood project for the ) Kuparuk River Unit in the ) Kuparuk River Field. ) Conservation Order No. 198 Kuparuk River Field Kuparuk River Oil Pool June 14, 1984 IT APPEARING THAT: I · ARCO Alaska, Inc., by letter and documents dated March 23, 1984, requested the Alaska Oil and Gas Conservation Commission to approve the implementation of a full-field waterflood project for the Kuparuk River Oil Pool within the Kuparuk River Unit in part of the Kuparuk River Field. · Notice of a public hearing was published in the Anchorage Times on May 7, 1984. · A public hearing was held in the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska on May 23, 1984. FIND INGS: 1. · · · · An application for additional recovery (Increment I) was approved on February 8, 1982 which allowed ARCO Alaska, Inc. to waterflood a limited portion of the Kuparuk River Unit. The data from Increment I, which started early in 1983, provided information to plan for full-field waterflood. The application for additional recovery pertaining to the full-field waterflood project filed by ARCO Alaska, Inc. contains all of the necessary data required by 20 AAC 25.400. Delination and development drilling data indicates a current estimate of original oil-in-place (OOIP) of 5.4 billion stock tank barrels. Primary recovery is estimated to be 560 million stock tank barrels of oil or 10.4 percent of the OOIP. Primary and waterflood recovery is expected to be 1.6 billion barrels of stock tank oil or 30 percent of the OOIP. Conservation Or~ · No. 198 Page 2 June 14, 1984 · Rule 3 of Conservation Order No. 173 provides for one well per governmental quarter section. Increased well density may be required to recover the maximum amount of oil in areas of the Kuparuk River Oil Pool. · Areas of the Kuparuk River Oil Pool may require a production/injection well density of one well per 40 acres to provide the flexibility needed for an effec- tive waterflood project. · Correlative rights will be protected and there will be no waste in a 40 acre spacing pattern for the Kuparuk River Unit. · The Alaska Oil and Gas Conservation Commission should have administrative power to approve modifications in a full-field waterflood project. CONCLUSION: The planned full-field waterflood project in the Kuparuk River Unit will result in the recovery of significantly more oil, correlative rights will be protected and there will be no waste of hydrocarbons. NOW, THEREFORE, IT IS ORDERED THAT a full-field waterflood project is approved for the Waterflood Permit Area described as follows: T10N, R8E, U.M. T10N, R9E, U.M. T10N, R10E, U.M. TllN, R8E, U.M. TllN, R9E, U.M. TllN,'R10E, U.M. TllN. RllE. U.M. T12N, R8E, U.M. T12N, R9E, U.M. T12N, R10E, U.M. T12N, RllE, U.M. T13N, R8E, U.M. T13N, R9E, U.M. Sections 1 through 17. Sections 1 through 11, 17, and 18. Section. 6. Sections 1, 2, 11 through 14, 22 through 28, and 32 through 36. Sections lthrough 36. Sections 1 through 36. Sections 5 through 8, 17 through 20, and 30. Sections 1, 2, 11 through 14, 23 through 26, 35, and 36. Sections 1 through 36. Sections 5 through 9, 15 through 23, and 25 through 36. Section 31. Sections 13, 23 through 26, 35, and 36. Sections 15 through 22 and 25 through 36. Conservation Or~" ' No. 198 Page 3 June 14, 1984 Rule 1. Well Spacing. Rule 3 of Conservation Order No. 173 is hereby amended by adding the following sentence: However, in the area described in Conservation Order No. 198, except for those governmental quarter sections adjacent to the Knparuk River Unit boundary, four wells may be drilled per governmental quarter section. Rule 2. Administrative Action. The Alaska Oil and Gas Conservation Commission may, by administrative action, make changes and approve operations that will enhance the efficiency of the full-field waterflood project. Rule 3. Kuparuk River Unit Waterflood Surveillance Program. The Unit Operator will submit an annual report to the Commission on the Kuparuk River Unit waterflood. The report will be submitted by April 1 of each year for the period ending December 31 and will contain the following information. (a) A tabulation of all pertinent reservoir pressure and injection pressure data on wells in the waterflood permits. (b) A tabulation of all production logs, injection well surveys, and injection well performance data. (c) Produced fluid volumes (oil, gas, and water) and water injection volumes reported by month and on a cumulative basis. Rule 4. In~.ectivity Profiles. An injection profile survey will be obtained on each injection well during the first nine months of sustained injection using a quantitative method. Follow-up surveys will be performed on a rotating basis such that one-third of the total number of injection wells are surveyed during each calendar year. The completed injection surveys will be filed with the Commission within 90 days after performing the survey. Conservation Orei' Page 4 June 14, 1984 No. 198 i. DONE at Anchorage, Alaska and dated June 14, 1984. Harry W. ~6gler, Commissioner Alaska Oil and Gas Conservation Commission Lon~mi~~~~. ~t~, %~Smmis s ioner Alaska Oil and Gas Conservation Commission May 28, 1993 ADMINISTRATIVE APPROVAL 198.4 (CHANGED TO 198.5) Re: The application of ARCO Alaska, Inc. that requests approval of a polymer gel pilot project at Drill Site 2W in The Kuparuk River Unit, in accordance with Rule 2, Conservation Order 198. C. W. Strickland Kupamk Petroleum Engineering ARCO Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Dear Mr. Strickland, We received your application May 6, 1993, requesting approval of a pilot project to inject a polymer gel material in up to six injectors on Drill Site 2W. The pilot project will use a Deep Diverting Gel (DDG) to modify vertical sweep within C3/4 Sand zones, increase injection into A Sand and reduce water cycling in the C 1 Sand. The pilot project will begin in July 1993 with the injection of 100,000-150,000 Bbl. of treated sea water per well and is expected to take up to two months. The DDG treatment will be mixed with 60 OF sea water at the surface and injected into the Drill Site 2W wells. The treatment will take advantage of the thermal gradient between the area where sea water injection has cooled the formation in the near wellbore vicinity and higher temperature rock further from the point of injection. When the treatment reaches a point in the reservoir where the temperature is great enough, the gel will activate and provide a permeability barrier, diverting subsequent injected water into other sections of the reservoir. Evaluation of the pilot project will determine technical and economic feasibility for potential expansion within the Waterflood Permit Area of the reservoir. The Commission has reviewed the proposal and determined the project will evaluate the capability of the DDG process to enhance the efficiency and effectiveness of the waterflood in the C 1, C3/4 and A Sands of the Kuparuk River Unit within the pilot project area. The Commission hereby approves the Deep Diverting Gel pilot project at Drill Site 2W in wells 2W-4, 5, 8, 9, 10 and 16. Sincerely, Russell A. Douglass Commissioner BY ORDER OF THE COMMISSION ALASKA OIL AND GAS CONSERVATION COMMISSION June 21, 1991 WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 198.4 Re: Modification of injectivity profile requirements of Rule 4. P. S. White, Senior Operations Engineer ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK. 99510-0360 Dear Mr. White: We have received your correspondence dated June 10, 1991 requesting modification of Rule 4. As currently written , Rule 4 requires injectivity profiles on. all wells regardless of whether or not multiple intervals are open to the wellbore. The modification would restrict productivity profile requirements to those wells that have multiple injection zones. The Commission has determined that modification of Rule 4 will enhance the efficiency of the waterflood project and will not promote waste. Rule 4 is hereby amended to read as follows: Rule 4 Injectivit¥ Profiles An injection profile survey will be obtained on each well with A and C sand injection within the first nine months of sustained multiple zone injection. One third of all multiple zone injectors will be surveyed each calendar year. The completed injection surveys will be, filed with the Commission within 90 days after performing the survey~ Sincerely, Russell A, Douglass Commissioner BY ORDER OF THE COMMISSION June 3, 1987 Telecopy No. (907) 276-7542 ADMINISTRATIVE APPROVAL NO. ]98.3 Re: Kuparuk River Unit Enriched Gas Enhanced Oil Recovery (EOR) Project. J. R. Pollock Kuparuk Engineering Manager ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-b360 Dear Mr. Pollock~ We have received your correspondence of May 21, 1987 on behalf of ARCO Alaska, Inc. In it you have made application for a Kuparuk River Unit Enriched Gas EOR Project. The Project would begin in 1988 with enriched gas injected alternately with water into the Kuparuk River Oil Pool on Drill Sites 1Y and 2Z. The gas enrichment will result in miscibility at reservoir conditions. Miscible gas injectant will be manu- factured at the Central Production Facility 1 and Central Production Facility 2. Expected recoverable reserves from this project range from 23 to 49 ~R~STBO. .Under continued favorable conditions, this project would be expanded to include additional drill sites lA, 1F, 1G, lQ, 2C, 2D, 2X and 2W which could increase the estimated recoverable reserves to 70 MMSTBO.' The Commission has determined the proposed project will enhance the efficiency and effectiveness of the full-field waterflood project authorized by Conservation Order No. 198. The Commission hereby approves the Kuparuk River Unit Enriched Gas EOR Project. In addition to the reporting requirements as set forth in Rule 3 of Conservation Order No. 198, the composition of all injectant fluids utilized in the Enriched Gas EOR Project should be included in the annual report. S z~J¢ e r e lyy... .... 77~ ~'~Lonnie C.' Smith Commis s ioner BY ORDER OF THE COPRMISSION jo/3.AA198 ALASII OIL AND 6AS CONSERVATION.COMMISSION · .October 10, 1986 Bill .~heffield, Governor 300, Po.cu.,.E DR,VE ANCHORAGE.ALASKA gg$01J"3192 (907) 276-7~42 AD M I N I S T RA T I V E A P P RO VA L NO. 198.2 Re: The application of ARCO Alaska, Inc. to implement immiscible water alternating gas (WAG) operations in Kuparuk River Otl Pool. Mr. J. R. Pollock Kuparuk Engineering Manager ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Pollock: We have received your letter of October 3, 1986 requesting approval to implement immiscible water alternating gas (WAG) qperations at Drill Sites 2F, 2G~ and 2U in the Kuparuk River Field. The purpose of this request is to improve the efficiency of the waterflood project which may increase ultimate oil '' recovery from the Kuparuk River Pool. The Commission has examined the submitted data, and finds that the WAG operations should enhance waterflood efficiency and.do. not constitute waste. Therefore, pursuant to Rule 2 of Conservation Order No. 198, the Alaska Oil and Gas Conservation Commission approves the implementation of immiscible water alternating gas (WAG) operations at Drill Sites 2F, 2G, and 2U for the Kuparuk River Oil Pool. · Sincerely~ ~,! Lonnie C. Smith ' Commissioner · , BY ORDER OF THE COM~ISSION o . "'-'-'- ALASKA OIL AND GAS CONSERVATION COMMISSION ~ 3OOl PORCUPINE DRIVE December 19, 1985 / ANCHORAGE, ALASKA 99501-3192 / TELEPHONE (907) 279-1433 Re: A D M I N I S T R A T I V E A P P R O V A L NO. 198.1 The application of ARCO Alaska, Inc. to implement immiscible water alternating gas (WAG) operations in Kuparuk River Oil Pool. Mr. J. R. Pollock Kuparuk Engineering Manager ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Pollock: We have received your letter of December 17, 1985 requesting approval to implement immiscible water alternating gas (WAG) operations at Drill Sites 2-V, 2-B and .2~H in the Kuparuk River Field. The purpose of this request is to improve the efficiency of the waterflood project which may increase ultimate oil recovery from the Kuparuk River Pool. The Commission has examined the submitted data and finds that the WAG operations should enhance waterflood efficiency and does not constitute waste. Therefore, pursuant to Rule 2 of Conservation Order No. 198, the Alaska Oil and Gas Conservation Commission approves the implementation of immiscible water alternating gas (WAG) operations at Drill Sites 2-V, 2-B and 2-H for the Kuparuk River Oil Pool. Sincerely, Lonnie C./SMith Commissioner BY ORDER OF THE COMMISSION be:3.AA198 --. KUPARUK RIVER UNIT LARGE SCALE EOR PROJECT Application for Injection June 6, 1995 RECEIVED JUN -7 1995 Alaska 0il & Gas Cons. Commission , ~chor~?~ Reference 20 AAC.25.402(c)(1) 20 AAC.25.402(c)(2) 20 AAC.25.402(c)(3) 20 AA0.25.402(c)(4) 20 AAC.25.402(c)(5) 20 AA0.25.402(c)(6) 20 AA0.25.402(c)(7) 20 AAC.25.402(c)(8) 20 AAC.25.402(c)(9) 20 AAC.25.402(0)(10) 20 AAC.25.402(0)(11) 20 AA0.25.402(c)(12) 20 AAC.25.402(0)(13) 20 AAC.25.402(c)(14) TABLE OF CONTENTS Subject Introduction Plat of Project Area Operator & Surface Owners Affidavit Project Description Pool Description Formation Geology Injection Well Logs Injection Well Casing Description Injection Fluids Injection Pressures No Fracture Propagation Formation Water Analysis Freshwater Exemption Incremental Hydrocarbon Recovery Proposed Findings Recommended Conclusions Requested Decisions Page 4 10 10 10 10 11 12 12 KRU LSEOR Project Application Exhibit 1 Exhibit 2 Exhibit 3 Exhibit 4 Exhibit 5 Exhibit 6 Exhibit 7 Exhibit 8 LIST OF EXHIBITS Plat of the Kuparuk River Unit Affidavit & List of Surface Owners LSEQR Project Schematic Type Log - West Sak River State No. 1 Stratigraphy - Kuparuk River Formation Injection Wellbore Schematic Miscible Injectant Compositions Water Analyses KRU LSEOR Project Application -3- Introduction This application seeks Alaska Oil and Gas Conservation Commission (Commission) authorization and endorsement of the proposed Kuparuk River Unit (KRU) Large Scale Enhanced Oil Recovery (LSEOR) Project. This application has been prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and Area Injection Order No. 2, issued June 6, 1986. The LSEOR Project is a significant expansion of the KRU Enriched Gas EOR Project which was approved by the Commission in June 1987 and was initiated in several patterns at Drill Sites 1Y and 2Z in 1988. Consistent with the Commission's Administrative Approval No. 198.3, the original KRU Enriched Gas EOR Project was expanded to the remaining patterns at Drill Sites 1Y and 2Z in 1991 and to Drill Site lA in 1993. The enriched gas EOR process would likely be expanded to at least two additional Kuparuk drill sites within the expected field life even if the LSEOR Project were not implemented. Whereas the scope of the approved KRU Enriched Gas EOR Project is limited by the volume of Miscible Injectant (MI) which can be manufactured from enriching fluids indigenous to the Kuparuk River Oil Pool, the LSEOR Project involves the acquisition of Natural Gas Liquids (NGLs) from the Prudhoe Bay field. Such NGLs will be transported to the Kuparuk River Field via the Oliktok Pipeline, mixed with Kuparuk enriching fluid, pumped to injection pressure, blended with Kuparuk produced gas at Central Production Facilities No. 1 and 2 (CPF-1 and CPF-2), and distributed as MI to a total of 21 Kuparuk EOR drill sites, including those within the current KRU Enriched Gas EOR Project. The LSEOR Project was approved by the Working Interest Owners of the KRU in March 1995. Start-up of the facilities integral to this project is scheduled to begin in late 1995 and to be completed by late 1996. Under the approved scope of the LSEOR Project, the KRU plans to acquire up to 26 MBPD of Prudhoe Bay NGLs upon completion of start-up activities. The actual volume of NGLs acqt~ired will depend on Kuparuk's facility limits and Prudhoe Bay's volume of NGLs available. These NGLs will be combined with approximately 14 MBPD of Kuparuk enriching fluids and injected as MI at 12 to 15 Kuparuk drill sites (including Drill Sites lA, 1Y, and 2Z). The remaining six to nine planned EOR drill sites will commence MI injection as mature EOR patterns are converted back to water or lean gas injection. Incremental oil recovery from the 18 additional LSEOR drill sites is expected to range from 4% to 10% of the Original Oil In Place (OOIP), resulting in over 200 MMSTB of additional Kuparuk oil reserves. Recovery of these reserves, pursuant to the LSEOR Project plan, will require the acquisition of approximately 100 MMSTB of NGLs, but approximately 35% of the acquired NGLs are expected to ultimately be produced as part of the Kuparuk crude stream. KRU LSEOR Project Application Additional LSEOR Project details are addressed within the 14 specific requirements of 20 AAC 25.402(c). ARCO Alaska, Inc.'s proposed findings, recommended conclusions, and requested decisions of the Commission are included at the end of this application. Plat of Project Area 20 AAC 25.402(c)(1) A plat of the Kuparuk River Unit showing the bottom hole locations of all proposed and existing injection wells, production wells, abandoned wells, dry holes, and any other wells that penetrate the injection zone within the Unit is included as Exhibit 1. The boundaries of the Kuparuk Participating Area (KPA) and the proposed LSEOR Project area are displayed on the KRU plat. The planned LSEOR Project involves expansion of the enriched gas EOR process beyond Drill Sites lA, 1Y, and 2Z to Drill Sites 1F, 1G, lQ, 1 R, 2A, 2B, 2C, 2D, 2F, 2G, 2H, 2K, 2M, 2T, 2U, 2V, 2W, and 2X. The KPA will be expanded to include the bottom hole locations of any wells proposed for drilling beyond the current KPA boundary adjacent to Drill Sites 2M and 2T prior to injection into, or production from, these wells. Operator & Surface Owners 20 AAC 25.402(c)(2) The LSEOR Project is located within the Kuparuk River Unit, which is operated by ARCO Alaska, Inc. The owners of surface rights within the LSEOR Project area and extending one-quarter mile beyond the project area boundary are listed in Exhibit 2. Affidavit 20 AAC 25.402(c)(3) An affidavit showing that the operators and surface owners within a one-quarter mile radiu~; have been provided a copy of this application for injection is included in Exhibit 2. Project Description 20 AAC 25.402(c)(4) The LSEOR Project will significantly expand the miscible enriched gas EOR process beyond Drill Sites lA, 1Y, and 2Z and is designed to ultimately cover 21 KRU drill sites during the expected 15 to 20-year life of the project. Without this project, the current KRU Enriched Gas EOR Project would likely be limited to two or three additional drill sites using MI manufactured from enriching fluids indigenous to the Kuparuk River Field. As depicted in Exhibit 3, the proposed LSEOR Project will involve the acquisition of NGLs from the Prudhoe Bay Central Gas Facility (CGF) for blending with Kuparuk lean gas to significantly increase MI injection within the Kuparuk River Field. A discussion of the facility requirements for this project follows. KRU LSEOR Project Application -.5- The Oliktok Pipeline will be used to transport NGLs from Skid 50, the Prudhoe Bay NGL/oil blending facility, to Kuparuk's CPF-1. This 16-inch pipeline was last in service in 1988 as a natural gas pipeline. It is currently being prepared for recommissioning in NGL service. Since NGLs will be required to blend with lean gas at both CPF-1 and CPF-2, a new NGL tie-line will be installed between these facilities. At CPF-1, a new module will be installed with facilities to receive the NGLs from the Oliktok Pipeline and pump them into new vessels at CPF-1 and CPF-2 (via the NGL tie- line) where the NGLs will be mixed with indigenous Kuparuk enriching fluid. These liquid hydrocarbon mixtures will then be pumped to injection pressure (above 4,000 psi) by an existing'pump at CPF-1 and a new pump at CPF-2 and blended with compressed lean gas at each CPF. The mixing of gas and liquid will be controlled to produce MI with a minimum miscibility pressure of approximately 2,900 psi with the reservoir oil. The other significant facility modification is an expansion of the electric power distribution system which will allow excess power at CPF-3 to be utilized by the new electric driven NGL transfer pumps at CPF-1. No significant MI distribution system modifications will be required, as high pressure gas piping has previously been installed for lean gas injection at all of the planned LSEOR Project drill sites. To fully utilize the equipment planned for the LSEOR Project, up to 26 MBPD of Prudhoe Bay NGLs will be required upon start-up completion in late 1996. The actual volume of NGLs acquired will depend on the ultimate capacity of the LSEOR Project equipment and the volume of NGLs available at Prudhoe Bay. When these NGLs are blended with approximately 14 MBPD of Kuparuk enriching fluid, the total Kuparuk MI injection rate is expected to increase from about 65 MMSCFD to nearly 220 MMSCFD. This rate of MI will be sufficient to flood 12 to 15 Kuparuk drill sites with MI, and the remaining six to nine planned EOR drill sites will be phased in as MI injection is reduced in mature EOR patterns. The expected MI injection rate contemplates that, in future years, MI returned from Kuparuk EOR drill sites will supplement NGLs imported from Prudhoe Bay. We expect that the daily rate of NGLs acquired from Prudhoe Bay will decline over time. Both the A and C sandstone units (see Formation Geology below) within an EOR pattern will be flooded with MI, provided that both sands are expected to remain open to flow for several years. MI injection will be alternated with water injection to improve the sweep of the MI. Because the injectivities of the A and C intervals within a well differ, the ultimate MI slug size injected into the A and C intervals of an EOR pattern will also differ. Therefore, the ultimate MI slug size injected within the LSEOR Project area is expected to range from 10% to 30% of a pattern's hydrocarbon pore volume. Similarly, the expected incremental oil recovery varies from 4% to 10% of a pattern's OOIP. KRU LSEOR Project Application Finally, additional drilling is planned for certain areas of the LSEOR Project drill sites. Potential drilling opportunities have been identified where a peripheral well or a structurally isolated infill well is expected to recover incremental tertiary reserves by providing a means for MI to contact additional pore volume. A few pattern infill locations have also been identified where a significant change in fluid flow path within the reservoir is expected to improve MI sweep. Pool Description 20 AAC 25.402(c)(5) The A and C intervals of the Kuparuk River Pool will be affected by the LSEOR Project. The Kuparuk River Pool is defined by Rule 2 of Conservation Order No. 173 as the strata that are common to, and correlate with, the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 Well between the depths of 6,474 and 6,880 feet, measured depth, or 6,387.9 and 6,793.9 feet, subsea. The West Sak River State No. 1 type log is shown in Exhibit 4. Formation Geology 20 AAC 25.402(c)(6) The stratigraphy of the Kuparuk River Formation is depicted in Exhibit 5. The ( .... ~paruk River Formation was deposited on a shallow marine shelf during Early · ..,,'etaceous time and is divided into Lower and Upper Members, which are separated by a regional Lower Cretaceous unconformity. Each member is subdivided into lithostratigraphic units; the A and B in the Lower Member and the C and D in the Upper Member. Units A and C are further divided into stratigraphic intervals based upon well log response. Reservoir sands are located in Units A and C. The A sands are a sequence of interbedded marine sandstone, siltstone, and mudstone. The sandstone is quartzose, very fine- to fine-grained and generally well sorted. Reservoir sandstone in Unit A averages 23% porosity and 100 md permeability. Unit C is composed of bioturbated marine sandstone which is quartzose, fine- to coarse- grained, and poorly- to moderately-sorted. The sandstone contains trace to abundant amounts of glauconite and secondary siderite cement. Porosity and permeability in Unit C is highly variable but averages 23% and 130 md. Unit D is composed of primarily mudstone and siltstone, while Unit B is comprised of thinly-interbedded very fine-grained sandstone, siltstone, and mudstone. The Kuparuk River Field is a combination structural and stratigraphic trap. The main structure is a broad anticline which plunges to the southeast. The shallowest depth to the top of the Kuparuk Formation within the project area is 5,611 feet subsea in Well 2T-11. The deepest penetration of the top of the Kuparuk in the area is 6,515 feet subsea in Well 1R-22. Along the western margin of the field, Unit A is truncated by the unconformity at the base of the ?per Member and the Unit C sandstone pinches out. The southern extent of the field is delineated by decreasing reservoir quality in both units. To the north KRU LSEOR Project Application -7- and east, the limit of the oil pool is determined by the intersection of the reservoir sands and local oil-water contacts that range in depth from 6,530 feet subsea to 6,710 feet subsea. The confining interval above the Kuparuk River Formation consists of more than 2,000 feet of Cretaceous shale. The lower confining interval is the Kingak shale, which exceeds 1,500 feet in thickness. Injection Well Logs 20 AAC 25.402(c)(7) All injection well logs have been submitted to the AOGCC in accordance with Conservation Order 173. Injection Well Casing Description 20 AAC 25.402(c)(8) Typical completion designs used for injection wells within the LSEOR Project area are shown in Exhibit 6. The completion design selected for a specific well is dependent on the productivity of the A and C sandstone units encountered by the well and the separation between these sands. The typical casing program used for production and injection wells within the LSEOR Project area utilizes three strings of casing: 1) 16", 62.5 lb casing from surface to ~100 ft measured depth; 2) 9-5/8", 36 lb or 10-3/4", 45.5 lb casing from surface to a measured depth of 2,000-4,000 ft; and 3) 7", 26 lb casing from surface to bottom. Well completion data, including casing, cementing, and testing programs, have been, and will continue to be, submitted for each injection well in accordance with 20 AAC 25.030. Each producing well which is converted to injection service is re-tested in accordance with 20 AAC 25.412. To demonstrate the mechanical integrity of all injection wells in the Kuparuk River Field, annulus pressures are monitored and reported monthly to the AOGCC. Injection Fluids 20 AAC 25.402(c)(9) As previously mentioned, the MI required for the proposed expansion of Kuparuk's enriched gas EOR process will be manufactured at CPF-1 and CPF-2 KRU LSEOR Project Application by blending lean gas from the Kuparuk River Reservoir with NGLs acquired from the Prudhoe Bay CGF. Upon full LSEOR Project start-up (late 1996), up to 26 MBPD of PBU NGLs, combined with approximately 14 MBPD of Kuparuk enriching fluid, will be blended with up to 170 MMSCFD of Kuparuk lean gas to produce nearly 220 MMSCFD of MI with a minimum miscibility pressure of approximately 2,900 psi. The expected composition of MI produced at each CPF in late 1996 is presented in Exhibit 7. The composition of Prudhoe Bay NGLs will vary depending on actual CGF operating conditions. The Kuparuk enriching fluid is comprised of several light hydrocarbon liquid streams produced by the KRU facilities. Specifically, the CPF-1 enriching fluid is comprised of scrubber liquids from the CPF-1 artificial lift gas compression system, NGLs from the CPF-1 NGL plant, and naphtha from the Kuparuk River Unit Topping Plant. The CPF-2 enriching fluid is comprised of scrubber liquids from the CPF-2 artificial lift gas compression system and NGLs from the CPF-2 fuel gas stripping unit. Laboratory core flood experiments indicate that MI with these constituents is fully compatible with the Kuparuk River Formation. Water will be injected alternately with MI in the EOR injection wells to improve the MI sweep in the reservoir. Approximately 400 MBPD of water will be injected into the proposed LSEOR Project area, including the three existing EOR drill sites. However, not all of the drill sites in this region will be receiving MI simultaneously. Those drill sites which are not initially converted to MI injection will continue to inject lean gas alternately with water until MI injection is initiated. Beaufort Sea water and Kuparuk produced water will be injected in the proposed LSEOR Project area. Both of these water sources have been previously approved for injection under the AOGCC Conservation Order 198. While these two types of water are compatible with the Kuparuk River Formation, they tend to precipitate barium sulfate or calcium carbonate scale when mixed. Therefore, within the Kuparuk facilities, sea water and produced water are either handled by separate injection systems or treated with scale inhibition chemicals. Injection Pressures 20 AAC 25.402(c)(10) The maximum MI and water injection pressures available at the plants will be 4,400 psi and 3,000 psi, respectively. Due to pressure losses in the distribution .,1 systems, actual wellhead pressures will vary across the field. The average MI and water injection pressures at the wellheads within the proposed LSEOR Project area are expected to be 3,800 psi and 2,700 psi, respectively. / ~,, KRU LSEOR Project Application -~)- No Fracture Propagation 20 AAC 25.402(c)(11) The maximum injection pressures for the enhanced recovery wells will not initiate fractures into confining strata and, therefore, will not allow injection or formation fluid to enter any freshwater strata. Injection into the Kuparuk River Formation at bottom hole pressures above the formation parting pressure often occurs in water injection wells. However, injection at such pressures does not breach the integrity of the confining zone. The reservoir is separated from other producing horizons and water bearing zones by over 2,000 feet of confining shales which act as an impermeable barrier. These shales provide a substantially greater barrier than necessary to contain fractures within the Kuparuk River Formation. Formation Water Analysis 20 AAC 25.402(c)(12) Produced water analyses from the Kuparuk River Formation are included in Exhibit 8. Since the LSEOR Project includes drill sites across the CPF-1 and CPF-2 areas, laboratory analyses are presented for produced water samples from each of these production facilities. Freshwater Exemption 20 AAC 25.402(c)(13) All aquifers or portions of aquifers lying below and within one-quarter mile of the KRU are exempted aquifers for Class II injection (reference 40 CFR 147.102(b)(3), 20 AAC 25.440(c), and Area Injection Order No. 2). Incremental Hydrocarbon Recovery 20 AAC 25.402(c)(14) The expansion to the Kuparuk enriched gas EOR process, in combination with the proposed drilling, within the LSEOR Project area is expected to increase KRU oil recovery by over 200 MMSTB. This represents incremental recovery of 4% to 10% of the OOIP within these 18 drill sites, based on total MI injection of 10% to 30% of the area's hydrocarbon pore volume. While approximately 100 MMSTB of Prudhoe Bay NGLs are required to achieve this recovery pursuant to the LSEOR Project plan, approximately 35% of the acquired NGLs are expected to ultimately be produced as part of the Kuparuk crude stream. KRU LSEOR Project Application - ] 0- Proposed Findings ARCO Alaska, Inc., as KRU Operator, respectfully proposes that the Commission make the following findings. 1. The proposed LSEOR Project will add up to 59,000 surface acres to the current KRU Enriched Gas EOR Project at Drill Sites lA, 1Y, and 2Z, which covers about 8,700 surface acres. 2. With this areal expansion of the enriched gas EOR process at Kuparuk, the approximate OOIP in the project area will increase from 575 MMSTB up to 2,900 MMSTB. 3. To meet the projected MI requirements of this EOR project expansion, it is expected that approximately 100 MMSTB of Prudhoe Bay NGLs will be utilized during the project's life. 4. Implementation of the Kuparuk LSEOR Project will require facility modifications and additions, including new NGL transfer pumps at CPF-1, a new NGL injection pump at CPF-2, a new NGL pipeline between CPF-1 and CPF-2, enriching fluid collection system modifications at CPF-1 and CPF-2, and an electric power distribution system expansion between CPF-1 and CPF-3. 5. Injection of MI into the EOR expansion area is scheduled to commence in late 1995, and the new facilities are scheduled to be fully operational in late 1996. 6. Within the EOR expansion area, approximately 150 current water and gas injection wells are expected to have MI injected. Furthermore, there are currently over 180 producing wells within this expansion area. 7. There are up to 70 new Production and injection wells planned for the EOR expansion area., These wells, which are deSignated" in red"'on'Exhibit '~;-'"l";'"'~i'i~'-b'bn'sistent'with the Unit plan of development for the LSEOR Project. As new production wells are drilled, some of the existing producers will be converted to injectors and will receive MI alternated with water injection. 8. Additional drilling within the Kuparuk enriched gas EOR area is expected to improve the distribution of MI in the reservoir and increase the EOR reserves. 9. The expected increase in oil recovery from the expansion of EOR acreage and additional drilling within this acreage is over 200 MMSTB. KRU LSEOR Project Application -.[ ]- Recommended Conclusions ARCO Alaska, Inc., as KRU Operator, respectfully requests that the Commission make the following conclusions. 1. Expansion of the Kuparuk enriched gas EOR process via the proposed LSEOR Project, in conjunction with additional drilling within the EOR expansion area, involves the application of a tertiary enhanced oil recovery method in accordance with sound engineering principles. 2. The combination of expanding the Kuparuk enriched gas EOR process and drilling additional wells within this expanded area is reasonably expected to result in more than an insignificant increase in the amount of crude oil that ultimately will be recovered. 3. The proposed areal expansion of Kuparuk's enriched gas EOR process will be undertaken to recover oil from areas not substantially affected by previously implemented tertiary recovery activities and will be applied to acreage and reservoir volume to which tertiary activities have not been applied previously. 4. The proposed additional drilling within the EOR expansion area will be undertaken to sweep areas of the reservoir previously unaffected by the enriched gas EOR process and to recover oil from areas and reservoir volume not substantially affected by previously implemented tertiary recovery activities. 5. MI enriching fluid (i.e., NGL) from outside the KRU is required to increase the supply of MI for expansion of Kuparuk's enriched gas EOR process. 6. Facility modifications and additions within the KRU are required to manufacture and inject additional MI for expansion of Kuparuk's enriched gas EOR process. Requested Decisions ARCO Alaska, Inc., as KRU Operator, respectfully requests that the Commission issue an order authorizing the underground injection of miscible enriched natural gas for enhanced oil recovery in the expanded area of the proposed KRU Large Scale EOR Project. ARCO Alaska, Inc., as KRU Operator, respectfully requests that the Commission endorse: 1) the areal expansion of the enriched gas EOR process via the proposed KRU Large Scale EOR Project and 2) additional drilling within the EOR expansion area. KRU LSEOR Project Application - ] 2- EXHIBIT 1 KRU LARGE SCALE EOR PROJECT Plat of the Kuparuk River Unit EXHIBIT 2 KRU LARGE SCALE EOR PROJECT Affidavit of Daniel G. Rodgers and List of Surface Owners STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Daniel G. Rodgers, declare and affirm as follows: 1. I am employed as a Senior Attorney by the Atlantic Richfield Company, and I serve as in-house council in Anchorage, Alaska for ARCO's wholly owned subsidiary, ARCO Alaska, Inc. 2. On ?)~ 0¢ , 1995, I mailed copies of the Kuparuk River Unit Large Scale EOR Project application for injection to the following owners of surface rights within a one-quarter mile radius of the proposed Project area. Mr. Ken Boyd State of Alaska Department of Natural Resources 3601 C Street. Anchorage, AK 99503 Ms. Nancy Welch, Regional Manager Alaska Department of Natural Resources Division of Land 3700 Airport Way Fairbanks, AK 99709-4609 Mr. Ron Swanson, Director Alaska Department of Natural Resources Division of Land 3601 C Street, Suite 1122 Anchorage, AK 99503-5947 -1- Mr. Jerry Brossia Alaska Department of Natural Resources Pipeline Coordinator's Office 411 West 4th Ave., Suite 2C Anchorage, AK 99501-2343 Mr. Brad Berg Kuparuk Pipeline P. O. Box 100360 Anchorage, AK 99510-0360 Mr. Don Puckett Oliktok Pipeline P. O. Box 100360 Anchorage, AK 99510-0360 Dated' ~ Daniel G. Rodgers 995 Declared and affirmed before me this ~.'f'~ day of June, 1995. Nota-r~ublic-- in~and foi-Alaska My commission Expires: ~ I. :z z- ~ ~' -2- KRU LARGE SCALE EOR PROJECT Schematic PBU NGLs to Kuparuk Oliktok Pipeline Enriched Gas EOR Process Kuparuk Pipeline O paruk NGLs Lean Gas Separator Off-Gas ' .:'-.F...!0W : :. ...: ':: :: ~ ~.. . · ..station .:. .:. .. Prudhoe Bay Miscible Gas EXHIBIT 4 ~'" SSTVD m, , 6850 - KRU LARGE SCALE EOR PROJECT Type Log - West Sak River State No. I ~.5 CAL1-BCS-S ~ .s IN -~2o SP-DIL-R o 2o GR-FDN-R 2o I 'i ,i .................. .UNIT ......... .. . · :i I LD-DIL-R 2oo I t LM-DI L-R 20o J ~ LLS-D I L-R 2oo ~.~ RHOB-FDN-S ~.6~ ~ G/C3 C3 . ..... ~ ......... ~...~....~ ......... :::::::::::::::::::::::::::::::::: + ................ ! ......... CiA B4 :::::::::::::::::::::::::::::::::::::::::::: ... .. B! · · · . · I A4 ...+o.f.,..,.~.+ ........... ...~..?.~.~.~ ........... ::::::::::::::::::::::: i: ::::::::::::::::::::::: :~e.;, ............ ~ .... .. ,. .. ,,.'-,~, ~ . '!'i' + ". '.~'i' ::::::::::::::::::::::::::::::::::::::::::::: .. ::::::::::::::::::::::: .. .-,. : . :~, ., .... KRU LARGE SCALE EOR PROJECT Stratigraphy- Kuparuk River Formation Gamma ResiStivity Subsea IntervaIUnit Member Formation May 150 1 1000 ~epm Kalubik "~ 'C' Sandstone D · Glauconitic, ~.- ~-6000' ~ C Upper Siderite-cemented ~ ~ Sandstone · Complex Mineralogy ~ ..... ~ & Pore Distribution ~ · Pay Recognition on Logs Difficult -6100' ~. 0.4- 33% " k: 0.01 - 3000 md -~ -~ '~ i; ' i~ .':. :~ ~ - -6300' Miluveach, ~ Sandstone [-'] Mudstone [--] Interbedded Sandstone, Siltstone, and Mudstone KRU EXHIBIT 6 LARGE SCALE EOR PROJECT Injection Wellbore Schematic Selective ca~r~ Productiofl/ Ini~ttofl Single Single Blast Joim Production/ Injection KUPARUKs,N~iDA ~ ~ EXHIBIT 7 KRU LARGE SCALE EOR PROJECT Miscible Injectant Compositions (Mole %) Component CPF-1 CPF-2 N2 0.4 0.4 CO2 0.8 0.8 C~ 65.8 66.7 C2 7.6 7.1 C3 7.0 4.8 iC4 2.2 2.5 nC4 6.0 6.6 iC5 2.1 2.4 nC5 2.8 3.3 Cs 2.2 2.4 C7 1.9 2.0 Ca, 1.2 1.0 EXHIBIT 8 KRU LARGE SCALE EOR PROJECT Water Analyses From: ARCO ALASKA, INC. KUPARUK LABORATORY SERVICES ANALYSIS REPORT To: February 10, 1994 Corrosion NSK-39 CPF-1 Facility Engineer NSK-6 CPF-1 Supervisor NSK-6 The following analytical results have been obtained for the indicated sample which was submitted to this laboratory: Sample I.D. AA17814 Sample point: ClOPWTW Sample description: CPF-1 Prod. Water Tank Outlet ~ Sample collector: DML Sample collection date: 02/07/94 Lab submittal date: 02/07/94 Time: 17:11 Parameter Result Sulfate by IC~- 113 Iron by AA+- 0.7 Sulfidee 12 PH+ 7.9 ,~Specific Gravity @ 60 degrees F 1.0185 ~onductivity ~hloride .Bicarbonate ~arbonate Barium~- Calcium~- Magnesium~ -- ~Sodium ~Strontium Potassium Units MDL mg/1 1 mg/1 0.1 mg/1 1 0.1 0.0001 39692 micro-mhos/cm 1 13684 mg/1 1 2489 mg/1 1 0 mg/1 1 39 mg/1 1 54 mg/1 1 67 mg/1 1 9259 mg/1 1 5 mg/1 1 36 mg/1 1 If there are any questions regarding this data, please call. Completed By: .~7~/~R Reviewed By: ~ From: ARCO ALASKA, INC. KUPARUK LABORATORY SERVICES ANALYSIS REPORT To: February 10, 1994 CPF-2 Super./Fac. Eng. NSK-14 Corrosion NSK-39 The following analytical results have been obtained for the indicated sample which was submitted to this laboratory: Sample I.D. AA17815 Sample point: C2OPWTW Sample description: CPF-2 Prod. Water Tank Outlet ~ Sample collector: DML Sample collection date: 02/07/94 Lab submittal date: 02/07/94 Time: 17:11 Parameter Result Sulfate by IC 206 Iron by AA 0.4 Sulfide 15 PH 8.0 Specific Gravity @ 60 degrees F 1.0198 Units MDL rog/1 1 rog/1 0.1 mg/1 1 0.1 0.0001 Conductivity 40892 micro-mhos/cm 1 Chloride 14876 mg/1 1 Bicarbonate 2244 mg/1 1 Carbonate 0 mg/1 1 Barium 30 mg/1 1 Calcium 69 mg/1 1 Magnesium 96 mg/1 1 -- Sodium : 9564 mg/1 1 Strontium 8 mg/1 1 Potas s ium 40 mg/1 1 If there are any questions regarding this data, please call. Completed By: ~/}d/~ Reviewed By: ~ -2- ARCO ALASKA ;=RUDHOE 8AY CENTRAL LABuRATORY ANALYTICAL REPORT .J ,4RCHIUE NUMBER: 784 APCH1VE VOLUME:90 SAMPLE NUMBER: FACILITY: STP COMPANY: ARCO ~AMPLE DATE/TIME: 021~90/1~:~0 SAMPLE TYPE: SEAWATER SAMPLE FOINTxMETER l~: EAST 5[JPPLY LINE DETERM I NAT I ON VALUE UN I TS H.vdrox.v I O. Mg/L Carbonate O. Mg/L Bicarbonate .~ 1~. Mg/L pm 7.7~ Ca lc ium ~. Mg/L Ma~nes ~um 1~0. MgxL Pot ass ~um 412. Mg/L ~ed ium 11450. Mg/L Bmr :um < 1.00 Mg/L ~t font turn Aluminum < 1. O0 Mg~L ~i l icon COPPER < 1. Chiop ide 210~4. Fluor ide l. Mg/L S~eci~ic Gravity ~ ~0 degrees F [.02}0 Resistivity ~ 68 de~rees F. 0.2l~ DHM-M Boron 6. Mg/L COMMENTS SULFATE ANALYZED BY BP LAB. STATU[ Completed b.~ Reviewed by StP OPERATIONS SUPERUI~OR F$ ~I/STP SUPERINTENDENT StP FACILITY ENGINEER SIP OPERATIONS SUPERUISOR CORROSION SPECIALIST ~2~ OPERATIONS ENG.CODRD INATOR ~24 S.M.BU~ARUM PRC lO~ H.G. BYRRS PRC E212 MIKE BILL ATQ i55Q LAB FILE r, jCi UC'T V -S- ARCO Alaska, Inc. ", Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 November 16, 1993 David W. Johnston, Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Johnston' Please consider this letter a request by ARCO Alaska, Inc., as Operator of the Kuparuk River Unit, for the modification of Conservation Order 198. Applicant requests that the area defined in Conservation Order 198 be revised to match the current Kuparuk River Unit boundary. Since the Conservation Order was issued in 1984, the Unit has undergone one contraction and several small expansions, and the Unit and Order boundaries differ somewhat. This modification seeks to preserve the original intent of the Conservation Order while updating it to the current Unit area. Besides being the Operator of the Kuparuk River Unit, ARCO is also the dominant leaseholder of acreage adjacent to the area included in this expansion request. ARCO does not believe the expansion will create waste, impair correlative rights, or adversely affect recovery. A copy of Exhibit A as submitted to the DNR defining the current Kuparuk River Unit boundary is included as an attachment. P. S. White Senior Engineer Kuparuk Petroleum Engineering Attachment RECEIVED NOV 1 8 1993 Alaska 0il & Gas Cons, Commission Anchorage ARCO Alaska, inc. is a Subsidiary of AtlanticRichfieldCompany Exhibit A, Kuparuk River Unit Agreeme,,, Tract Legal ADL No. Royalty ORR Ownert~ Interest I0 T 13N-I~F_~UM ~-c. 13: All Sec. 14: Ail Sec. 23: All Sec. 24: All T 13N-I~E,-UM Sec. 17: All Sec. 18: All Sec. 19: All T13N-RgE-UM Sec..15: All Sec. 16: All Sec. 21: All Sec. 22: All T13N-RgE-UM Sec. 25: All Sec. 26: Ali Sec. 35: All Sec. 36: All T13N-R9E-UM Sec. 27: All Sec. 28: All Sec. 33: All Sec. 34: All T13N-RgE-UM Sec. 29:. Ail Sec. 30: AIl Sec. 31: All Sec. 32: All TI3N-RSE-UM Sec. 27: All Se~ 3~ All Sec. 34: All T12N-RBE-UM Sec. 3: All · ~ec. 4: All Sec. 9: All Sec. lO:. N/2, SW/4 256o 255~ ~/8 2544 25512 1/8 2560 25513 1/8 2560 25519 1/8 2560 :15520 I/8 2555 25521 1/8 256O 25523 1/8 m2o 25s24 1/8 240O 25532 1/8 Exhi~t A, Page I AR 5O% BP 5O% AR 33-1/3% BP 33-1/3°~ UN 33- l / 3% - , RECEIVED NOV 18 l-$93 Alaska Oil & Gas Cons. Commission Anchorage Exhibit A, Kuparuk River Unit Agreemen~ ADL 10A 11 12 13 14 15 16 18 19 T12N-RBE-UM Sec. 10:SE/4 T12N-R8F_,-UM Sec. l:All Sec. 2: Ail Sec. Il:All Sec. 12: All T12N-RgE-UM Sec. 5: AIl Sec. 6: AIl Sec. 7:AIl Sec..8: All TI2N-RgE-UM Sec. 3:AIl Sec. 4: AIl Sec. 9: AIl Sec. 10. All T12N-RgE-UM Sec. l:Ail Sec. 2:All Sec. Il:All Sec. 12: All T12N-RIOE-UM Sec. 5:AIl Sec. 6:AIl Sec. 7:AIl Sec. 8:AIl TI2N-R10E-UM See. 3:All Sec. 4:All Sec. 9:All Sec. 10. Ail TI2N-RIOE-UM Sec. 14: AIl Sec. 23: AIl T12N*RIOE-UM See. 15: All See. 16: Ail Sec. 21: All Sec. 22: All 160 25532 l/8 2560 25531 1/8 2437 25631 1/8 2560 25630 1/8 2560 25629 1/8 2437 25628 1/8 2560 25627 1/8 1280 25637 I/8 2560 25636 I/8 BP BP BP BP BP. BP BP BP 100~ 33-1/3% 33-1/3% 33-t/3% 50% 50% Exhibit A, Page 2 RECEIVED Alaska Oil & Gas Cons. Commission Anchorage Exhibit A, Kuparuk River Unit Agreemer,, T~aet ADL NPSL O~me~ Interest 21 22 T12N-R10E-UM Sec. 17: All Sec. 18: AIl Sec. 19: All Sec. 20: All TI2N-RgE-UM Sec. 13: All Sec. 14: AIl Sec. 23: All Sea 24: All T1RN-RgF.,-UM Sec..1.5: AIl Sec. 16: AIl Sec.. 21: A~ Sec. 22: All TI2N-R9E-UM Sec. 17: AIl Sec. 18: All Sec. 19: All Sec 20:)21 T12N-R8E-UM Sec. 13: AIl Sec. 14: AIl Sec. 23: All Sec. 24: All T12N-RBE-UM Se~ 15: All Sec. 16: All Sec. 21: All Sec. 22: All T12N-I~F,-UM Sec. 27: All See. 28: AIl Sec. 3~ AIl Sec. 34: All TI2N-RSE-UM Sec. 28: Ail Sec. 35: Ail Sec. 36: Ail T 12N-RgF.,-UM Sec. 29: AIl Sec. 30: AIl Sec. 31: All Sec. 32: AIl 2448 25635 1/8 2560 25634 1/8 2560 25633 1/8 2448 25632 1/8 2560 25547 1/8 2560 25546 1/8 2560 25549 1/8 2560 25548 1/8 2459 25643 1/8 Exhibit A, Page 3 AR 5O% BP AR 33-1/3% BP 33-1/3% UN 33-1/3% AR 33-1/3% BP 33-1/3% UN 33-1/3% AR 33-1/3% BP 33-1/3% UN 33-I/396 AR 33-1/3% BP 33-1/3% UN 33-1/3% RECEIVED 18 Oil & Gas Cons. Commission Anchorage Exhibit A, Kuparuk River Unit Agreement Tmet No. ADL ~ No. Royalty ORR Tract Working NI~L O~mers ~ 31 32 36 37 39 T12N-RgE-UM Sec. 27: All Sec. 28: all Sec. 33: All Sec. 34: All TI2N-RgE-UM Sec. 25: Ali Sec. 26: Ali Sec. 35: All Sec. 36: All T12N-RIOE-UM Sec. 29: All Sec. 30: AIl Sec. 31: All Sec. 32: All T12N-R10E-UM Sec. 27: All Sec. 28: All Sec. 33: All Sec. 34: All T12N-RIOE-UM Sec. 25: All Sec. 26: All Sec. 35: All Sec. 36: All T12N-R11E-UM Sec. 31: All TI IN-RI IF_rUM Sec. 5: At! Sec. 6: All Sec. 7:AIl Sec. 8:All TI IN-RIOE-UM Sec. l:AII Sec. 2:AIl See. Il:Ail See.. 1~: AIl T11N-RIOE-UM Sec. 3: All Sec. 4: All Sec. 9: All Sec. 10: All 256O 25642 1/8 2560 2564 1 l/8 2459 25640 1/8 2560 25639 1/8 256O 25638 591 47449 1/8 2469 25242 1/8 2560 25649 1/8 256O 25648 1/8 AR 5O% BP 50% AR 100o~ AR 100~ CH 50% MO 50% AR 100% AR lO0O~ Exhibit A, Page 4 RECEIVED NOV 1 8 Alaska Oil & Gas Cons. Commission Anchorage Exhibit A, Kuparuk River Unit Agreemsm Tract No. ADL WPSL Tract Working O~nero ~ 41 42 43 45 49 T11 N-R IOF,-UM Sec. 5:Att Sec. 6: Att Sec. 7:ALl Sec. 8:Ali T11 N-RgF.,.UM Sec. I:AIt Sec. 2: AIl Sec. Il:All Sec. 12: AIl T11N-RgF,-UM .~ Se~. 4: All Sec. 9:All Sec. 10:All TI IN-Rg~UlVl See. 5: All Sec. 6:AIl Sec. 7: All Sec. 8: All TI 1N-I~F_,-UM .~.c. l:All Sec. 2:AIl Sec. Il:All ~ 12: AIl TI 1N-RSF_,-UM Sec. 3: All Sec. 4: Alt Sec. 9:AIl Sec. 10. All TI IN-RBErUM Sec. IS:All Sec. 16: Ail Sec. 21: AIl Sec. 22: All TI IN-RB~,UM Sec. 13: Alt Sec. 14: AIl Sec. 23: AB Sec. 24: Ail 2460 25647 1/8 256o 2564~ 1/8 2560 25645 1/8 2469 25644 1/8 256o 25569 1/8 256o 25568, 1/8 2560 25571 1/8 256O 25570 I/8 AR 100~ AR 5o% BP 50% AR 33- l/3~ BP 33-1/3% UN 33- l/3% AR 33-I/3% BP 33-1/3% UN 33-1/3% A~ 33-1/3% BP 33-1/3% UN 33-1/396 AR 33-1/3% BP 33-1 / 3% UN 33-1 / 3% Exhi~t A, Page5 RECEIVED NOV 1 8 t,,i 5 /.,,.t>:~ka Oil & Gas Cons. Gommiss[o~ Anchorage Exhibit A, Kuparuk River Unit Agreemen[ Tract ADL No. Revolt? ORR NPSL ~ ~te~eot 51 52 55 57 T11N-RgE-UM Sec. 17: AIl Sec. 18: AIl Sec. 19: AIl Sec. 20: All TI 1N-R9E.-UM Sec. 15: AIl Sec. 16: AIl Sec. 21: AIl Sec. 22: All TI 1N-RgE-UM Sec. ,_13: All Sec. 14: AIl Sec. 23: All Sec. 24: All T11N-RIOE-UM Sec. 17: AIl Sec. 18: AIl Sec. 19: All Sec. 20: All TI IN-R10E-UM Sec. 15: AIl Sec. 16: AIl Sec. 21: AIl Sec. 22: All T1 IN-R10E-UM Sec. 13: AIl Sec. 14: All Sec. 23: All Sec. 24: Ail T11N-RI 1E-UM Sec. 17~ AIl Sec. 18: Ail Sec. 19: Ail Sec. 20: All T1 IN-RI IE-UM Sec. 16: AIl Sec. 21: Ail Sec. Ill:All T11N-R11E-UM Sec. 27: All Sec. 28: All Sec. 33: All 2480 25655 1/8 2560 25654 1/8 256O 25653 l/8 2480 25652 1/8 2560 25651 1/8 2560 25650 1/8 248O 28243 1/8 19~0 28244 1/8 1920 28247 1/8 Exhibit A, Page 6 AR 5O% BP 50% AR 100% AR 100% AR 32.96724% BP 17.03276% MO 50% RECEIVED NOV 18 Oil & Gas Cons. Anchorage Exhibit A, Kuparuk River Unit Agreement No. ADL NO. Royalty ORR NPSI, Owne~ Interest 61 62 67 TI 1N-RI 1E-UM Sea 2~. Ail Sec. 30: All Sea 31: All TI IN-RIOE-UM Sec 25: All Sec. 26: All Sec 35: All Sec~ 36: All T11N-R IOE-UM Sec. 27: All Sec. 28: All Sec. 33: All Sec. 34: All TI IN-RIOE-UM Sec. 29: AIl Sec. 30: AIl Sec. 31: AIl Sec. 32: AIl TI IN-RgE-UM Sec. 25: All Sec. 26: All Sec~ 35: All Se~ 36: All TI IN-RgE-UM Sec. 27: All Sea 28: All Sec. 33: All Sea 34: All T 11N-RgE-uM Se~ 2~. All Se~ 3~. Ail Sec~ 31: All Sec 3~ ~l 1851 28248 1/8 2560 25661 1/8 256O 2566O 1/8 2491 25659 1/8 256O 25658 1/8' 2560 25657 1/8 2491 25656 1/8 TI IN-RSE-UM 2560 25587 1/8 Sec, 25: All - TI 1N-RSE-UM Sec. 29: All Sec 3~. All See. 31: All Sec 32~ All 256O 25586 1/8 2491 25585 I/8 Exhi~t A, Page 7 AR 100~ AR 100~ AR tOO% AR 5O°6 BP- 50% AR 33- l/3% BP ' · 33- !/3°,/0 AR 33- l/3% BP 33-1/3% UN 33-1/3% AR 33-1/3% BP 33-1/3% UN 33-I/3% RECEIVED NOV 18 0/t & Gas Cons. Commission Anchorage ( Exhibit A, Kuparuk River Unit Agreemem ADL No. ~,owdtv ~ 74 75 76 78 81 82 TION-I~E-UM Sec. 5: AIl Sec. 6:All Sec. 7:All Sac. 8:AIl TION-RBE-UM Sac. 3:AIl Sec. 4: AIl Sac. 9: AU Sec. 10:All T10N-I~E-UM Sec. l:All Sec. 2:AIl Sec. Il:All Sec. 12: AIl TION-RgE-UM 5ac. 5:AIl Sec. 6:All Sec. 7: AIl ,~'c. 8:AIl T 10N-R9E,-UM ~ 3:AIl · ~'c. 4:AIl Sac. 9:All Sac. 10:All T10N-RgE-UM Sec. l:All Sec. 2:All ~ Il:All Sec. Il:Ail TION-RIOE,-UM Sec. 5:AIl Sec. 6:AIl Sec. 7:AIl See. 8:Ail TION-RI0~-UM ~ 3:Ail Sec. 4:All Sec. 9: Ali Sec. 10. All T10N-RIOF,-UM Sec.'l: All ~.c. 2:All ,Sec. Il:All ~ i 2: All 2501 25590 1/8 256O 25589 1/8 256O 25588 1/8 2501 25667 1/8 256O 25666 256O 25665 1/8 2501 25664 1/8 256O 25663 1/8 256O 25662 1/8 Exhibit A, Page 8 AR 33-1/3~ BP 33-1/3% UN 33- l/3q<, AR 33-1/3q6 BP 33-1 /3o/6 UN 33-1/3% AR 33-1/3o/6 BP 33-1/3% UN 33-1/3% AR 100°/6 AR 100~ RECEIVED NOV 18 993 0il & Gas Cons. ConlmissJon Anchorage Exhibit A, Kuparuk River Unit AgreemI,,. Leg,,1 DeserioU~ ADL ~ z~o. ~~ OL~ Tn~t Owne~ tnte~st 89 95 T10N-RIOE-UM Sec. 15: All Sec. 16: All Sec. 21: All Sec. 22: All T10N-RIOE-UM Sec. 17: AIl Sec. 18: AIl Sec. 19: AIl Sec. 20: All T10N-RgE-UM Sec. 13: AIl Sec. I4: All Sec. 23: All Sec. 24: All T10N-I~E-UM Sec. 15: All Sec. 16: All Sec. 21: All Sec. 22: All T10N-RgE-UM See. 17: All Sec. 18: All Sec. 19:. All Sec. 20: Ail TION-RSE-UM Sec. 13: AIl Sec. 14: AIl Sec. 23: All Sec. ~4: Ail T 10N-RSE-UM Sec. 15: All Sec. la:All Sec. 21: All See. 22: An T10N-RSE-UM Se~ 29:. AIl Se~ 3~. All Sec. 31: All Se~ 32: AIl 256O 25672 1/8 2512 25671 1/8 2560 25670 1/8 2560 25669 1/8 2512 25668 1/8 256O 256O5 1/8 AR 33-1/3% BP 33- l/3% UN 33.1/3~ 256O 25604 t/8 AR 33.1/3% BP 33. l/3~ UN 33-1/3% 2512 256O3 1/8 AR 33-1/3% BP 33.1/3% UN 33-1/3% 2523 25608 1/8 AM 16-2/3%' AR 33-1/3% BP 33-1/3% UN 16-2/3% * ARCO owns all of Amoco's interest as to the Kuparuk River Reservoir. RECEIVED Exhibit A, Page 9 [ OV 1 8 0il & Gas Cons. Commissior~ Anchorage Exhibit A, Kuparuk River Unit Agreern~,.. ~t No. Rov,,~ty ORR NPSL ~ ~te~e~t 100 I01 I04 T10N-RSE-UM Sec. 27: Ail Sec. 28: All Sec. 33: All Sec. 34: All TION-RgE-UM Sec. 29: Al! Sec. 30: All Sec. 31: All Sec. 39~ AIl TION-RgE-UM Sec. 27: All Sec. ~-8: All Sec. 33: All Sec 34: All T10N-ROE-UM Sec. 25: Ali Sec. 26: Ail Sec. 35: AIl Sec. 36: All T10N-RI 1E-UM Sec. 5:All Sec. 6:AIl Sec. 7:All Sec. 8:All See. 23: Ali Sec. 24: Ali T10N-RIOE-UM Sec. 29: All Sec. 30* All Sec. 31: All Sec. 32: AIl T13N-RgE*UM See. I:AIi ~ 2:AIl See. 3:AIl See. 4: AIl. See. 0:Ali Sec. 10,All See. Il:All Sec. 12: AIl Sec. 8: Exclude T&S lands and USS 4275 256O 256O7 1/8 AM AR BP UN * ARCO owns all of Amoco's interest as to the Kupamk River Reservoir. 2523 25679 1/8 AR EX 2560 25678 1/8 AR EX 2560 25677 1/8 AR EX 2501 3186O2 1/5 30~ AR BP 2523 25676 1/8 16-2/3%* 33-1/3% 33-1/3% 16-2/3% 5175 355023 1/8 AR 6.250~ CH 50q~ BP 43.75~ 30~ AR 100% Exhibit A, Page 10 RECEIVED NOV 18 ()il & Gas Cons. Cor, nmission Anchorage 'Exhibit A, Kuparuk River Unit Agreeme~, Tzm:t Ho. ADL ~t Workl~ ~ (2~st~s InteTeSt 122A 123 124 125 126 T13N-RgE-UM USS 4275 Include Tract C. ATS 1259 Exclude Tract B. ATS 1259 Exclude Tract A. Ars 1289 {Not presently tn Untt} T13N-R9F,,-UM Sec. 5: Exclude USS 4275 Sec. 6: All Sec. 7: Exclude USS 4275 Sec. 8: T&$ lands TI4N-RCE-UM Sec. i4: Att Sec. 25: AIl Sec. 36: Ail T14N-RgF_,-UM Sec. 19: AIl Sec. 30.' Al! Sec. 31: All T13N-RCE-UM Sec. I:AII Sec. 2:AIl Sec. Sec~ tO: All Sec. Il:All Sec. 12: AIl See. 15: AIl T13N-RBE-UM See. 19: All Sec. 2~ ~ See. 21: All Sec. 22: All Se~ 2~. ~dl Se~ 3~. All Sec. 31: All Se~ 3~All 677 373G0t 1/8 558O 355024 l/8 4480 355030 1/8 5108 355032 1/8 640 365501 1/6 AR 59.22868% BP 40.77132% 30~ AR 10OYo 3O96 AR 100°~ 30~ AR 100~ AR 100% Total Acres (Excluding Tm_ct 122A} Exhibit A, Page 11 -RECEIVED ,?~,~,ka Oil & 6as Cons. Commission Anchorage ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 July 27, 1993 C. W. Strickland Kuparuk Petroleum Engineering ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Re; Approval of a polymer gel project 2W i,not~he Kuparuk River Unit, in '~' accordance with Rtil'e 2'; Conservati ,'0'nO~rdcr ,j'o,: ~ Dear Mr. Strickland: Administrative ApprOval 'No. 198".'4, dated May 28, 1993 was assigned in error. Please change the number to AA.1..98..5.~.. David W. John'~...~ Chairman ARCO Alaska, Inc '~'' Post Office B~o~, 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 June 10, 1991 David W. Johnston, Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Re: Application for Modification of Rule 4, Conservation Order No. 198 Dear Mr. Johnston: Please consider this letter a request by ARCO Alaska, Inc., as Operator of the Kuparuk River Unit, for the modification of Conservation Order No. 198. Applicant requests that Rule 4 of Conservation Order No. 198 be modified to require injection profiles only on wells with both A and C sand injection. This modification will eliminate the administrative burden of reporting injection profile data on wells which have only one sand present. This will have no impact on the approximately 200 A & C sand injectors, of which at least one-third will be surveyed each year. It is further requested that the requirement that surveys be performed on a rotating basis be revised. Under the current rule, wells are required to be surveyed once every three years. Revising this rule to simply require one-third of the A and C sand injectors to be surveyed each year improves efficiency, while maintaining the same overall data collection frequency. The value of injection profile data is maximized and reservoir management objectives will continue to be met. Applicant believes that the changes outlined above will not adversely affect ultimate recovery or create waste and conforms to prudent oil field operating and engineering practices. Sincerely, P. S. White Senior Operations Engineer RECEIVED JUN 1 t991 Alaska 0il & 6las Cons. (,0mmlsS[.(t~ Anchorage ARCO Alaska, Inc, is a Subsidiary of AtlanticRichfieldCompany AR3B-6003-C ARCO Alaska, In~' Post Office' ...ox 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 Jerry R. Pollock Engineering Manager Kuparuk River Field October 3, 1986 Mr. C. V. Chatterton Chairman, Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 dear Mr. Chatterton' Subject' Request to Implement Immiscible Water Alternating Gas (WAG) at Drill Sites 2F, 2G, and 2U in the Kuparuk River Unit. ARCO Alaska, Inc., in reference to Conservation Order Number 198, Rule Number 2, requests approval to implement an expansion of immiscible water alternating gas injection to Drill Sites 2F, 2G, and 2U to enhance the efficiency of the waterflood project in the Kuparuk River Unit. The WAG injection program will consist of gas injection for one-fourth of the time and water injection for three-fourths of the time with effectively a one-to-one WAG ratio. Initially, the cycle will be set at three months on gas injection followed by nine months of water injection. The gas injection rate for each well will be optimized to replace voidage, regulate gas breakthrough at the offset producing wells, and to maximize waterflood efficiency. The eight injection wells used in this program will be the direct- line-drive locations for all three drill sites. Our studies indicate that an increase in oil recovery will be possible on these drill sites due to migration of gas towards the top of the reservoir. This gas migration increases vertical sweep efficiency by displacing oil that would not have been otherwise contacted by water injection. In addition, WAG injection slows down water-oil ratio increases in the offset producing wells. This should lower lifting cost, potentially increasing economic recovery. In summary, WAG injection will increase waterflood efficiency and economic reserves at Drill Sites 2F, 2G, and 2U. We will be happy to discuss this project with you at any time. RE,CEIVEB OCT o 9 1986 Nas~ 0ii & Gas Cons. Commission Anchorage ARCO Alaska, Inc. is a Subsidiary of AtlanticRichlieldCompany Mr. C. V. Chatterton October 3, 1986 Page 2 If you have any questions, please contact Tom Schmitt at 263-4440 or Dana Dayton at 263-4269. Sincerely, J. R. Pollock Manager, Kuparuk Engineering JRP'JHC'mlw CC' J. D. Dayton S. W. Jones T. A. Schmitt M. L. Hagood ATO-1220 ATO-2090 ATO-1228 ATO-1120 ('.),C'l" 0 9 1986 Oil & Gas 6o~s. Commisstr,~ A~cbom~e ARCO Alaska, Inc- Post Office B'~o~, -100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 Jerry R. Pollock Engineering Manager Kuparuk River Field December 17, 1985 Mr. C. V. Chatterton Chal rman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage~ Al( 99501-3192 Dear Mr. Chatterton: SUBJECT: Request to Implement Immiscible Water Alternating Gas (WAG), Drill Sites 2V, 2B, and 2H in the Kuparuk River Unit ARCO Alaska, Inc., in reference to Conservation Order Nun~er 198, Rule Number 2, requests approval to implement an immiscible water alternating gas injection project on Drill Sites 2V, 2B, and 2H to enhance the efficiency of the water- flood project in the Kuparuk River Unit. The WAG injection program will consist of gas injection in two wells on each drill site and water injection in the remaining six injection wells. The gas injection will be rotated an~ng all of the injection wells to complete the cycle. Initially, the cycle will be set at three months on gas injection followed by nine months of water injection. The gas injection rate for each well. will be optimized to replace voidage, regulate gas breakthrough at the offset producing wells, and to maximize waterflood efficiency. The eight injection wells used in this program will be the direct-llne-drive locations for all three drill sites. Our studies indicate that an increase in oil recovery will be possible on these drill sites due to migration of gas towards the top of the reservoir. This gas migration increases vertical sweep efficiency by displacing oil that would not have been otherwise contacted by water injection. In addition, WAG injection slows down water-oil ratio increases in the offset producing wells. This should lower lifting cost, potentially t ncreaslng economic recovery. In summary, WAG injection at Drill Sites 2V, 2B, and 2H should increase waterflood efficiency for these three drill sites. Other opportunities extst in the Unit to expand this type of project which could further increase the efficiency of the fullfield waterflood. Further expansion into these areas will require substantial capital outlays. Information obtained on Drill Sites 2V, ~B, and 2H will be valuable in makin~~F VED remaining decisions. .... ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany Alask, a Uli ~ c,~.~ ~.,,'.~;~s. Con~mJssJolt Anchorage C. V. Cha~, .arton December 17, 1985 Page 2 If you have any questions, please contact George Phillips at 263-4280 or Dana Dayton at 263-4269. Very truly yours, J. R. Pollock Kuparuk Engineering Manager JRP:mlw cc: J. D. Dayton G. K. Phillips AT0-1220 AT0-1296 RECEIVED Alaska Oil & ,::,,?,::; ::;:,,,,;s G~:;r~lmissio~ A¢Ct'lOt',',:i~ ;¢3 ARCO Alaska, Inc. l~' Post Office E .100360 Anchorage, Alaska 99510-0360 Telephone 907' 276 1215 July 19, 1984 Mr. C. V. Chatterton State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Re: Revised Surface Casing Setting Depths for 1L, lQ, 1R, 2E, 2U, and 2W Pads in the Kuparuk River Field. Dear Mr. Chatterton: __.J. 4 ENG --'J 20~OL j I STAT TE~-- J' STAT TE~ ........ CON.R: FILF~ .... This letter is to request Administrative approval to vary from the existing Kuparuk River Field Rules, Conservation Order No. 173, to allow the surface casing to be set deep as 3700'TVD in development wells on Pads 1L, lQ, 1R, 2E, 2U, and 2W. The Field Rules currently requtre~that the surface casing be set in a depth interval ranging from 500 measured feet below the base of the permafrost to 2700'TVD. The deepest horizon for the base of the West Sak sand occurs on IR pad at 3600'TVD. The attached table gives our estimated depths for the surface casing shoes on the subject pads. · Our request for a deeper surface'.cas'ing seat is made for the following reasons: -, 1. It is preferred to set the surface casing shoe just below the West Sak sand. This Sand can be better isolated with surface casing, as opposed to the current method of using production casing to isolate the sand. 2~ Abetter formation integrity test will be obtained prior to drilling into the Kuparuk sands. Although past formation integrity tests have been acceptable, drilling of the Kuparuk interval will be made safer with higher surface casing shoe integrity. ARCO Alaska, Inc. Is a Subsidiary of AtlanllcRIchfleldCompany RECEIVED JUL2 1984 Alaska 011 & Gas Cons. Commission Anchorage Mr. C. V.~' ~tterton ~" July 19' I~4 · Page 2 e We feel that West Sak hydrocarbons can be safely drilled using a flow dtverter stack on conductor casing. On previous Kuparuk development wells, the West Sak was safely drilled (below surface casing) with a drilling fluid density of 9.0 ppg. The West Sak reservoir pressure is approximately 8.4 ppg equivalent, with no known gas/oil contact and a low solution GOR. e The information and experience gained from setting the surface casing deeper than 2700'TVD on previous pads indicate that the West. Sak reservoir can be drilled safely with a conductor/diverter system. ~ Not every well on the pad will have the casing set through the West Sak sands. Some, because of long departures, will be more economical to set above the West Sak sands. The estimated spud date for the first well affected by this request is August 15 for 1L-7. Due to the timing of this well, and to allow your staff sufficient time to review and process our proposal, we would like to request individual exception for this well if possible, similar to that obtained for Well 1F-16. Any significant changes in geological conditions discovered subsequent to this request will be forwarded to your office in writing'in a timely fashion. o If you have any questions on the a~ove, please feel free to call me at 263-4970 or Ken Bonzo a~,,263-4967. Sincerely, Area Drilling Engineer JBK:KLB:jh LO1 07/19/84 RECEIVED, JUL2: I I 011 & Gas Cons. Commission Anchorage '" I I ESTIMATED SURFACE CASING SETTING DEPTH FOR 1L, lQ, 1R, 2E, 2U, and 2W Pad No. 1L 1R 2E 2U 2W Base of the West Sak Subsea 3300' 3200' 3600' 2900' 2700' 2865' Proposed ,Casing Setting Depth Subsea 3400' 3300' 3700' 3000' 2800' 3000' KLB:M02 07/19/84 RECEIVED JUL p- ) ~ Alaska 011 & Gas Cons. Commission Anchorage I. Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO ALASKA, INC. for approval to implement a fullfield waterflood project in the Kuparuk River Oil Pool in the Kuparuk River Unit. Notice is hereby given that ARCO Alaska, Inc. has requested the Alaska Oil and Gas Conservation Commission to issue an order, pursuant to 20 AAC 25.400, approving a fullfield waterflood project for that portion of the Kuparuk River Oil Pool within the Kuparuk River Unit. The operator will present testimony at a public hearing in support of the request. The hearing will be held at 9:00 AM on Wednesday, May 23, 1984 in the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska. All interested persons and parties are invited to give testimony. Harry W. Kug Commi s s ioner Alaska Oil & Gas Conservation Commission 10 11 t2 13 14 16 18 19 2O 21 23 ALASKA OIL AND GAS CONSERVATION COMMISSION FORMAL HEARING KUPARUK RIVER FIELD FULLFIELD WATERFLOOD PROJECT APPLICATION FOR ADDITIONAL RECOVERY CIqAT CHATTERTON, LONNIE C. SMITH, HARRY W. KUGLER, CHAIRMAN MEMBER MEMBER GREATER ANCHORAGE AREA BOROUGH ASSEMBLY CHAMBERS 3550 EaSt:'Tudor ROad Anchorage, Alaska May 23, 1984 9:00 A.M. R£C£1V£D JUN 1 4 BB4 Oil & Gas Cons. Commiss[oll Anchorage R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1OO'7 W. 3RD AVENUE 272-7515 10 11 14 16 18 19 2O -2- PROCEEDINGS MR. CHATTERTON: Okay. I'm told that we are on the record. My name is Chat Chatterton. And we are currently -- the date today is abou% May the 23rd, 1984, and it's roughly about 9:01 A.M. Excuse me. And we are gathered in the Assembly Chambers of the Anchorage -- Anchorage Municipality for the purpose of conducting a public hearing on an application by ARCO, the operator of the Kuparuk River Unit for full field waterflood of -- of the currently productive interval within the Kuparuk River Unit. I'll introduce the people here that we have, and there's just -- at my extreme right, your left, is Commissioner Lonnie Smith. Seated next to him is Commissioner Harry Kugler. And to my immediate left, your right of me, why, is Meredith Downing, who is the -- a -- the court reporter, will -- will report this. She,s with R & R Court Reporters. I'll ask Harry to read into the record the official call of this hearing. MR. KUGLER: This is regarding the application of ARCO Alaska, Incorporated, for approval to implement a full-field waterflood project in the Kuparuk River Oil Pool in the Kuparuk River Unit. Notice is hereby given that ARCO Alaska, Inc., has requested the Alaska Oil and Gas Conservation Commission to issue an order pursuant to 20 AAC 25.400 approving a full-field R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVENUE 272 7515 10 11 14 15 16 17 18 19 waterflood project for that portion of the Kuparuk River Oil Pool within the Kuparuk River Unit. The operator will present testimony at a public hearing in support of the request. The hearing will be held at 9:00 a.m. on Wednesday, May 23rd, 1984, in the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska. Ail interested persons and parties are invited to give testimony. And this notice was advertised on Monday, May 7th, 1984, in the Anchorage Times. MR. CHATTERTON: Thank you, Commissioner Harry. The -- I'll speak to the hearing format. It shall be conducted in accordance with the regulation 20 AAC 25.540, and the regulation's highlights are as follows: We'll have the applicant: testify first. Any other wishing to testify shall follow immediately upon completion of the direct testimony by the applicants. As we -- we shall at our discretion allow cross examination of the witnesses. Oral statements from anyone presen' in the audience are permitted upon conclusion of all testimony, and written statements shall be accepted following all oral statements. If anyone wishes to make oral comments, why they'll be permitted to at our discretion, and written comments will be accepted after the oral statements are presented -- finished. Direct questioning of witnesses by members of the audienc~ shall be ruled out of order. Questions may be written and submitted to the Commission, and we will review them and if we R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572. 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1OO'7 W, 3RD AVENUE 272 7515 !4 !5 !6 17 !8 19 think they're germane to the subject at hand -- hand, we shall ask the proper person that question. We have this meeting facility available I think until 3:00 p.m. Hopefully we'll be the heck out of here before noon- time. And I am told that an estimate of the direct testimony of the applicant will take about roughly an hour and a half, some- thing give or take a little bit. Hopefully at that time we're -- we'll be able to take a slight break and reconvene immediatelyl following that break. A ten-minute break or something like that. I think that's about all I have to offer as to the format of this hearing, and so, Mr. Williams, why you as spokesman for the applicant, why, you may proceed. MR. WILLIAMS: Thank you, Mr. Chairman, members of the Commission. Mr. Chairman, ladies and gentlemen, my name is Stephen M. Williams. I'm an attorney with ARCO Alaska, Inc. ARCO Alaska, Inc. is unit operator for the Kuparuk River Unit. The Kuparuk River Unit working interest owners have requested this public hearing before the Alaska Oil and Gas Conservation Commission for approval of an application for additional recovery through the implementation of a full field waterflood project. The application for additional recovery was filed with the Commission on March 23rd, 1984. The application contained the documentation required by 20 AAC 25.400 and was transmitted to all interested leaseholders within and adjacent to the Kuparuk River Unit. 810 N STREET, SUITE101 277'0572"277'0573 R 8,: R COURT REPORTERS 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 9950] 100'7 W 3RD AVENUE: 2727515 l0 l? 19 20 24 -5- We request that the documents, including the Kuparuk River Full -- Field fulll field waterflood project application, along with the affidavit and supporting documentation be entered into as -- the public record at this time. MR. CHATTERTON: That is so ordered. It is. MR. WILLIAMS: Thank -- thank you, Mr. Chairman. Several ARCO representatives will present testimony today on behalf of the Kuparuk River Unit working interest owners The testimony will discuss the criteria specifically required by Commission regulation, and show how this project meets thos criteria, promotes conservation, prevents waste, and increases recovery from the Kuparuk River Oil Pool. Our intent today is to emphasize and discuss the items we feel are 'the most important in implementing this project, and to provide a forum from which the Commission may ask questions on project specifics. The following individuals will testify today: To my immediate left and down the line, S.G. Suellentrop, W. -- R.S. May, W.D. Masterson, L.K. Blacker, and J.R. Brandstetter Mr. Ted Morkum will be handling the -- the slides this morning, Mr. Chairman, but will not testify. MR. CHATTERTON: Okay. Fine. Okay. Commissioner Harry, would you swear the five witnesses in, please MR. KUGLER: Would you all stand, please, and raise your right hand? MR. WILLIAMS: Raise your right hand, please? R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-05'72 .. 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100-7 W 3RD AVENLJE 2727515 10 11 12 13 14 15 16 17 18 19 21 -6- (S.W. Suellentrop, W.D. Masterson, R.S. May, L.K. Blacker and J.R. Brandstetter duly sworn under oath.) MR. KUGLER: You may be seated. MR. CHATTERTON: Thank you, Harry. Ted, we didn't have to swear you in, because it was said you were~ not going to testify. MR. WILLIAMS: At -- at the end of the testimony, Mr. Chairman, the -- the witnesses would like to form a panel to respond to any of the Commission's questions. This testimony has been prefiled, and each of the witnesses has included in that testimony a statement of their qualifications. We will begin our testimony today with Steve Suellentrop of ARCO Alaska, who will provide an introduction and overview of today's testimony. MR. SUELLENTROP: Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Steve Suellentrop. I have received a Bachelor -- Bachelor of Science and a Master of Science degree in petroleum engineering from the University of Missouri-Rolla. I have worked for nine years in varying aspects of reservoir engineering. The last four years have been spent in Alaska. I am presently a regoinal reservoir engineer for ARCO Alaska, Incorporated, and I am responsible for all reservoir engineering studies relating to the Kuparuk River Field. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272 7515 10 11 13 14 16 19 MR. CHATTERTON: Steve, the Commission finds that you fully qualify as an expert witness in the matters before MR. SUELLENTROP: Thank you, Mr. Chairman. MR. CHATTERTON: You may proceed. MR. SUELLENTROP: I will make some introductory remarks for the technical presentations that will follow, review the schedule currently envisioned for full field waterflood development, and discuss the special requests that accompany the application for additional recovery. The Kuparuk River Field is located in the North Slope Borough of Alaska as shown on Exhibit One. The Kuparuk River Reservoir was dicovered in April of 1969, with the drilling of Ugnu State Number One by British Petroleum and Sinclair oil Companies. In the l~ year period between ~969 and ~980, more than 25 delineation wells were drilled by ARCO, B.P. Alaska Exploration, Incorporated, and Sohio Alaska Petroleum Company. In late ~980, ARCO requested that the Commission cnsider field rules for the development of the Kuparuk River Field as shown on Exhibit Two. These field rules were approved on May 6th, 198~, as Conservation Order Number ~73. On December ~st, ~981, the Kuparuk river Field was unitized to prevent waste and to protect the correlative rights of the working interest owners. The Kuparukk River Unit agreement and the initial plan of development were approved by the Commissioner of the Department R 8< R COURT REPORTERS 810 N .STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE~ ALASKA 99501 1007 W 3RD AVENUE 272.7515 ]8 ]9 -8- of Natural Resources. Further delineation and development drilling over theyear. has given a current estimate of oil in place in the Kuparuk River Field of 5.4 billion stock tank barrels. The Kuparuk River Field is a solution gas drive reservoir with no primary gas cap. Primary recovery of oil is through pressure depletion. Secondary recovery through waterflood is expected to yield an incremental 1.04 billion stock tank barrels of oil, or nearly 19.5% of the original oil in place. This is exPected to bring the total field recovery to 1.6 billion stock tank barrels of oil. The Kuparuk owners previously requested and received approval ofan application for additional recovery on February 8th, 1982, to operate a pilot waterflood in a limited portion of the Kuparuk River Field. The purpose of this pilot, called Increment One, was to optimize recovery and reduce the risks associated witha fullfield waterflood project. Water injection into the two drill sites involved in Increment One began in early 1983, as shown on Exhibit Three. During 1983, the three drill sites to the east and north of Increment One were used for gas injection. During the same period, the seven remaining drill sites were produced by natural depletin to Central Production Facility Number One, or CPF-One. I would now like to provide a brief overview of field development. Upon approval of this fullfield application, water- R 8:: R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 27'7-0573 277-8543 ANCHORAGE. ALASKA 99501 1OO'7 W 3RD AVENUE: 272 7515 10 11 13 14 15 16 17 18 19 21 -9- flood operations will be expanded this year to Drill Sites 1F and 1G which are adjacent to the Increment One as shown on Exhibit Four. Waterflood of these two drill sites will reduce their pressure decline and solution gas production. The lowering of gas-oil ratios in this area will allow more oil to be processe~ through CPF-One. Central Production Facility Number Two, or CPF-2, will be operationin in late 1984, and will process oil from drill sites in the southwestern portion of the Kuparuk River Field. Drill· Site 2V in the CPF-2 area will be used initiallylfor gas injection. As shown on Exhibit Five, during 1985 waterflood will continue on Drill Sites lA, 1E, 1F and 1G. No new drill sites will be waterflooded. Five additional drill sites will be brough~ on production, three to CPF-1 and two to CPF-2. In 1986 the second increment of this waterflood will begin as shown on Exhibit Six. Source water from the Beaufort Sea will be treated and delivered to local injection plants at .CPF-1 and CPF-2. By year end a total of 18 drill sites will be waterflooded. CPF-3 is cheduled to start up in early 1987, as shown on Exhibit Seven. CPF-3 facilities will include water injection facilities. Ten drill sites in the CPF-3 area will be water- flooded before the end of that year. The majority of the drill sites within the Kuparuk River Field will be waterflooded by 1988, as shown on Exhibit Eight. R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 277-05'72 · 277-0573 277-85Zl, 3 ANCHORAGE. ALASKA 99501 100'7 W 3RD AVENUE. 2'72 7515 10 11 13 14 15 16 17 18 19 20 9.3 -10- Ten drill sites in the CPF-1 and CPF-2 areas will be affected by injected gas and will not be waterflooded until the mid 1990s. Currenlt waterflood development plans call for 160-acre development of the Kuparuk River Reservoir. As shown on Exhibit Nine, three special requests are contained in this application. First, we are asking for a minimul well spacing of 40 acres per well within the waterflood permit boundary. Currently, Conservation Order Number 173 limits field development to 160-acre spacing. Implementation of an efficient and effective waterflood may require closer well~ spacing, in certain areas of the field. Forty-acre spacing should provide the optimum flexibility to enable implementation of the fullfield waterflood in the Kuparuk River Field. the second -- second sepcial request is that the effectiv~ date of this application be the approval date by the Commission. This will allow the Kuparuk owners to proceed with the 1984 waterflood plans to start water injection on two drill sites adjacent to Increment One. The third special request is that future modifications to the waterflood permit boundary be approved administratively by the Commission to allow the waterflood boundary to coin- -- coincide with or extend beyond 'the future boundary of the Kuparuk participating area. The requested waterflood permit boundary is shown on Ehxibit Twn. As selected in this applicatior the waterflood permit boundary includes entire governmental R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVENUE 272 7515 10 11 12 14 16 17 18 19 -11- sections when a portion of that section is included in the Kuparuk participating area. The boundary also includes ADL 28242 owned by ARCO and Exxon Corporation along the eastern side of the Kuparuk River Field. This tract will become part of the Kuparuk participating area in the near future. The selection of this waterfloo~ permit boundary reflects the intention of the Kuparuk owners to effectively utilize the resources within the Kuparuk Reservoir. By providing a mechanism in the order to administratively approve future boundary changes, the working interest owners will have the flexibility to optimize ultimate recovery from the Kuparuk River Oil Pool. I would like at this time to review the agenda of today's testimony as shown on Exhibit 11. Dallam Masterson will be presenting a description of the Kuparuk River Field geology. Laura Blacker will address the performance of Increment One waterflood, and the impli- -- implications of its results for future reservoir development. Robert May will present the operational aspects of surveillance of Increment One waterflood operations. I will thlen review the forecast for fullfield waterflood performance. Robert May will then review the source waters for use in fullfield waterfield. Joel Brandstetter will present the surface facilities that will be required to accomplis fullfield waterflood. And, finally, I will summarize today's testimony. We will begin now with our testimony with Dallam Masterson. R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W, 3RD AVENUE 272-7515 10 1] 14 15 16 17 18 19¸ -12- MR. MASTERSON: Mr. Chairman and members of the Commission, ladies and gentlemen, my name is Dallam Masterson and I am presently geologic testimony on behalf of ARCO Alaska Incorporated. I received a Master of Arts degree in geology from the University of Texas at Austin in 1981, and have been employed by ARCO as a petroleum geologist since that time. I have spent the last two years studying the geology of the Kuparuk River Field and surrounding areas. MR. CHATTERTON: Thank you, sir. The Commission finds you qualified as an expert witness to testify in the matters before us. MR. MASTERSON: Thank you, Mr. Chairman. My testimony will begin with a review of the structure and strati- graphy of 'the Kuparuk River Field and will conclude with a review of the geology in the Increment One waterflood area. The Kuparuk River Field is a combination structural and stratigraphic trap. The contour map of the top of the Kuparuk River Reservoir structure, shown in Exhibit 12, incorporates all the non- Confidential wells that will -- were drilled prior to December 27th, 1983. The depths shown are feet subsea. Note that faults have been omitted from this map in order to simplify the structure. On the west, the field is bounded by an erosional unconformity which truncates the Kuparuk reservoir rocks. The approximate position of this truncation is shown by a dashed, scalloped line. The southern end of the field is delimited R &: R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277'-8543 ANCHORAGE, ALASKA 99501 1007 W. 3~"?D AVENUE 272 7515 t! t6 24 -13- by decreasing reservoir quality in the Kuparuk sands. To the north and east the limits of the oil pool are determined by the intersection of structural dip and the local oil-water contact. Line C-C-prime, a structural cross-sectoin extending from west to east across the Kuparuk River Field, is shown on Exhibit 13. The depths shown on the left and right margins of the cross-section are feet subsea. Both geophysical ~ information and well control were used to construct the cross- section. At the eastern end of the cross-section, the Kuparuk River Formation intersects an oil-water contact which is at approximately minus 6560 feet subsea. The erosional surface which truncates the lower portion of the Kuparuk River Formation is represented with a heavy scalloped line. At the estreme western end of the cross-section, the unconformity has completely removed the A land B units of the Kuparuk River Formation. In some areas of the field, such as Drill Site 1E, the fault pattern is extremely complex. Exhibit 14 shows the distribution of faults which intersect the Kuparuk River Formation in the waterflood permit area. These faults have been identified from well control and from geophysical information. Up to 300 feet of structural displacement is present along the faults. Two sets of faults are present, one set trending north-south, and the other set trending northwest-southeast. R 8<: R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVEINUE 2'72. 751.5 10 11 14 17 18 19 -14- Exhibit 15 summarizes the stratigraphy of the Kuparuk River Formation. the well log shown is 1A-13, which is a cored, water injection well in the Increment One waterflood area. The Kuparuk River Formation is divided into an upper and a lower member which are separated by an erosional unconformity. Unit D is a siltstone unit and Unit B is a sequence of interbedded sandstone, siltstone and mudstone. The reservoir sands are found in the A and C units, both of which are believed to have been deposited on a shallow marine shelf during Lower Cretaceous time. The C sands are quartzose, fine to coarse grained, poorly to moderagely well sorted, bioturbated, contain trace to abundant amounts of glauconite, and are often cemented by siderite, particularly in the C-four and C-one intervals. Naturally occurring fractures are observed in cores through the siderite- cemented C-four and C-one sands. Varying amounts of dispersed glauconitic clay, siderite cement and fracturing cause wide variability in C sand porosity and permeability. Exhibit 16 shows the distribution of Kuparuk C sandstone. The yellow coloring represents the approximate with at least ten feet of net C sand. The thickest accumulation of C sand is in the CPF-1 area where the Increment One waterflood is taking place, the C sand bodies pinch out into the CPF-2 and CPF-3 development areas. The northwest trend of the C sands in the CPF-1 area is partially controlled by northwest-southeast trending faults which were active during deposition of the C interval. R 8: R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 2'77-0572 - 277-0573 27'7-8543 ANCHORAGE. ALASKA 99501 1007 W, 3RD AVENUE 272 7515 10 11 12 13 14 15 16 17 18 19 21 -15- Stratigraphic cross section A-A-prime is shown on Exhibit 17. The yellow colored areas on the cross sectoin are sand- rich zones within the C unit. The lowermost sandstone, the C-one sand, is thought to have been a transgressive marine sand- stone which was deposited upon an eroded surface as the Cretaceou sea transgressed across the area. The C-one sand can be locally discontinuous. The C-three/C-four sandstone body is interpreted to have been an offshore marine bar which prograded out into deeper water to the northeast. The siderite cemented zones indicated in green can be widely or only locally distributed. Thickened C and B intervals are often present on the downthrown sides of northwest-southeast trending faults. The Kuparuk A sands are more widespread than the C sands and will provide most of the production in the CPF-2 and CPF-3 areas. The A sands are quartzose, very fine to fine grained, and well sorted. The A unit can be divided into at least six sandstone and mudstone packages which prograded towards the southeast, creating an imbricate stack of stratigraphically separated sandstone intervals. The progradatoinal nature of the A sands is illustrated by stratigraphic cross sectoin B-B- prime which is shown on Exhibit 18. The line of cross sectoin extends from northeast to southwest across the Kuparuk river Field. Sand-rch zones wihtin each interval are colored -- colored in orange. Exhibit 19 shows the areal distribution of Kuparuk A R 8< R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 27.7-0573 2'7'7-8543 ANCHORAGE. ALASKA .99501 1007W 3RD AVENUE 272 7515 10 13 16 17 18 21 -16- sand intervals which have more than ten feet of net sand. Note the location of cross section B-B-prime which I showed you in Exhibit 18. The A sandstone bodies are elongated in a northeast- southwest direction and are truncated by the erosional unconformity at the western edge of the Kuparuk River Field. Because of the progradational nature of the A sands, pay zones overlap vertically in some areas of the field, and these areas are shown with darker tint. The interbedded sandstones, silt- stones, and mudstones of the A unit are believed to have been deposited during storms on a shallow marine shelf. I will now review the geology of the Increment One waterflood area. ILncrement One is located in a complexly faulted area along the northeastern flank of the field's structural closure. The location of Drill Sites lA and 1E is shown on Exhibit 20. Exhibit 21 is a structure contour map of the top of the Kuparuk River Formation at Drill Site lA. The 'depths are feet subsea, and faults are shown in red. Faulting in the Drill Site lA area has been defined by seismic mapping and well control Reservoir rock is juxtaposed against non-reservoir rock across some of the larger faults, forming a local barrier to fluid movement. The portions of faults which are believed to act as barriers to fluid flow are cross'hatched. Reservoir quality sand at Drill Site lA occUres predominantly in the A-4, C-4, C-3 and C-1 intervals and, to a lesser extent, in the A-3 and R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W 3RD AVENUE 277-0572-277-0573 277-8543 272.7515 ANCHORAGE, ALASKA 99501 10 11 14 18 2]¸ -17- A-5 intervals. Exhibit 22 shows a structure contour map of the top of the Kuparuk River Formation at Drill Site 1E. Faults are colored red, and the depths are feet subsea. The one fault which is thought to act as a burial -- barrier to fluid flow is cross hatched. Reservoir quality rock is found in the C-3, C-4, A-4 and A-5 intervals at Drill Site 1E. Reservoir sands are also present in the C-1 interval in some Drill Site 1E wells. Natural fractures are common in the siderite-cemented C-1 and C-4 intervals at Drill Sites lA and 1E. The orientation of the fractures is thought to be parallel to the north-south trending fault system. The north-south trending faults and fractures are believed to have developed after deposition and cementation of athe Kuparuk River Formation. In summary, the Kuparuk River Formation is divided into two reservoir zones with differing rock properties. The C unit is characterized by glauconite, siderite cement, and natural fractures in the C-1 and C-4 intervals. Thick accumulations of C sand are present at CPF-1 and to a lesser extent at CPF-2. A regoinal erosional unconformity at the base of the C-1 interval separtes the C unit from the underlying A and B units. The A sands differ from the C sands in grain size, grain composition, sorting and depositinal history. Fractures are not common in the A intervals. This concludes the geologic portion of the testimony. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W :}RD AVENUE 272 7515 10 11 ¸12 14 16 17 18 19 2O -18- The following testimony by Laura Blacker will review the Incremen~ One waterflood performance. MR. CHATTERTON: Thank you very much, sir. Laura? MS. BLACKER: Mr. Chairman and members of the Commission, ladies and gentlemen, my name is Laura Blacker. MR. CHATTERTON: Laura, may I interrupt you? Can you .... MR. WILLIAMS: Have her speak up. Tell her to speak up. Speak up a little bit. MR. CHATTERTON: Anyone having any difficulty hearing Laura? MR. SMITH: I am. MR. WILLIAMS: Speak up a little bit, Laura. MS. BLACKER: I'll try. MR. CHATTERTON: Please go ahead. MS. BLACKER: I received a Bachelor of Science degree in chemical engineering from Tulane. University in 1976. I have been employed in the oil and gas industry since my graduation, and by ARCO Alaska since November of 1980. Since that time I have worked as both an operations and reservoir engineer in the KuparUk engineering group. I am currently lan area reservoir engineer in charge of waterflood studies. MR. CHATTERTON: Laura, the Commission finds you qualify as an expert witness in the matters before us. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-05'72 - 277-0573 2'77-8543 ANCHORAGE. ALASKA 99501 1007 W, 3RD AVENUE 272 7515 10 11 13 14 16 17 18 19 -19- MS. BLACKER: Thank you, Mr. Chairman. My testimony will begin with a review of the objectives of the Increment One waterflood. This project was started up as a pilot waterflood in early 1983. As shown on Exhibit 23, the overall goal was to optimize the recovery and reduce the risk associated with fullfield waterflood. In addition, specific objectives were to obtain reservoir information that would be used to attain this goal. The first of these was to determine reservoir properties which affect injectivity. The second objective was to determine reservoir properties affecting sweep. The third objective was to determine optimum well spacing, and lastly to obtain an estimate of ultimate recovery from waterflood As I present the Increment One performance in detail, I will review the information obtained from this pilot waterflood and how it relates to these specific objectives. I will review the performance of the two drill sites, one at a time, beginning with Drill Site 1E. Exhibit 24 shows the location of Drill Site 1E. It is located in the CPF-1 area and is one of the five original Phase One drill sites in the Kuparuk River Field. This drill site is located directly south of Drill Site 15, which has been used as a gas injection drill site since February of 1982. As you will see later, the performance of Drill Site 1E has been impacted by gas injection. Exhibit 25 shows the location of the patterns o Drill Site 1E. On the east half of the drill R 8: R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W 3RD AVI.:.NUE 272' 7515 10 11 14 17 18 19 -20- site, there are 160-acre five-spot patterns. The wells are drilled to 80-acre spacing in these patterns, with the producer spacing at 160 acres. On the west side of the drill site are four 80-acre five-spot patterns. Wells in these patterns are drilled to 40-acre spacing. One of the patterns, the one surrounding Well 1E-12, is an A sand only pattern. The remaining patterns contain wells completed in both the A and C sands, in which injection and production are comingled. Currently nine wells on Drill Site 1E have water break- through. Exhibit 26 shows the wells in which water breakthrough has occurred, and in additoin shows the wells which are shut- in due to high GOR. Water breakthrough has occurred in all but one of the 'ten active wells completed in the C sand. Seven wells are shut-in due to high GOR. These wells have all been impacted by injected gas from Drill Site lB. Injected gas migrated into Drill Site 1E before the start of Increment One, and most of the wells which are currently shut-in for high GOR were shut in prior to the start of waterflood. The performance of Drill Site 1E under waterflood can best be described by referring to a plot of rate versus time shown on Exhibit 27. I have shown on this plot oil rate, GOR, water injection rate, and produced water rate between 1982 and 1984 to show both primary and waterflood performance. The oil rate reached its maximum immediately lbefore the start-up of Increment One due to producing additional wells which had been R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572. 277-0573 277-854.3 ANCHORAGE. ALASKA 99501 100'7 W 3F?D AVENUE 2'72. 7515 10 11 16 t? 18 19 -21 - drilled as part of Increment One. The rate declined at the start of waterflood due to conversion of wells to injectin, and has continued to decline since that time primarily because of shutting in high GOR wells. The waterflood has not prevented the further migration of gas into the drill site. The impact of injected gas clan be seen by looking at the GOR performance. This has continued to increase even though we have been water- flooding the drill site. The slight decline at the end of 1983, is due to shutting in additional high GOR wells. The water injection rate has been level at about 18,000 barrels of water per dayl since April, 1983, when all the water injectors were placed on injeactoin. The produced water rate, shown in green, increased rapidly after initial breakthrough in March of 1983. It reached a peak of about 2,000 barrels of water per day in October of 1983. The slight decline in recent months is due to shutting in wells which produce high water cuts because of water handlinlg capacity of the facility. The water injection rate greatly exceeds the produced water rate on this drill site, indicating that even though breakthroug~ has occurred, the majority of the water is continuing to displace oil. However, much of the waterflood response has been obscureed due to the effects of injected gas. One of the objectives of the Increment One waterflood was to determine reservoir properties which affect injectivity. To accomplish this, we have run a number of surveys in both R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3F:~E) AVENUE 272 '7515 10 11 14 15 16 17 18 19 -22- injection wells and producing well, which Robert May will review in more detail later. I will show you the average injection profile on Drill Site 1E determined from these surveys. The graph on Exhibit 28 shows percent of injection by sand along the X axis. The Y axis indicates the percent of the total reserves of each sand. As shown, 86% of the water we are injecting into Drill Site 1E is entering the C-4 sand which contains only 22% of the reserves on the drill site. Eleven percent of the water is entering the C-3 sand, which contains about 41% of the reserves. Only 3% of the water is entering the A sand, which contains 37% of the reserves. This percentage does not include the water which is being injected into the A sand only pattern. Based on the injection profile, we have identified two factors which affect injectivity. The first is that a disproportionate share of the water is entering 'the C sands relative to the C sand reserves. The second is that within the C sand itself, the majority of the water is entering into the naturally fractured high permeability C-4 sand. I would like to review the water breakthrough on Drill Site 1E further. Exhibit 29 shows the wells in which water breakthrough has occurred, and also indicates by arrows from which injection wells the water came. This water breakthrough has been confirmed by tracer data. The breakthrough in all of the wells with the exception of 1E-2 has come from an injector either directly north or south of the producing well. There R & R COURT REPORTERS 810 N STREET, SUITE I01 .509 W, 3RD AVENUE 277-0572 " 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1OO7W, 3RD AVENUE 272-7515 10 11 12 14 15 16 17 18 19 2O 21 24 -23- has been no confirmed breakthrough in the east-west direction. As I mentioned earlier, most of the water injection has occurred in the naturally fractured, high permeability layers of the C sands. Most of the water breakthrough has also occurred in these layers. Because the confirmed breakthrough has all been in the north-south direction, we have concluded that the fracture intervals of the C sands have a strong north-south preferential fluid movement. This preferential fluid movement could be caused by matrix permeability, natural fractures, faulting, or a combination of any of these. This trend will be referred to as directional permeability in this review. Directional permeability is responsible for early breakthrough which has occurred on Drill Site 1E and Drill Site lA. Additional data, which I will discuss later confirms this directional permeability Because of the nature of the C sand, waterflood response discussed so far has been dominated by C sand performance. The A sand has exhibited a much different response to waterflood as I will show you now by reviewing the performance of the A sand only pattern centered around well 1E-12. Exhibit 30 shows rates versus time for well 1E-12. there were little or not withdrawals from this well prior to the start of waterflood, therefore, the GOR at the start of the flood was essentially solution GOR and has remained at this level throughout the water- flood, the oil rate has increased indicating waterflood response in this well. R & R COURT REPORTERS 81o N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 .- 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3RD AVENUE 2'72 '7515 10 13 14 16 17 19 -24- The injection rate has fallen off slightly, possibly due to pressuring up around the pattern area. No water break- through has been noted in this well to date, even though the well spacing is close, indicating that we can successfully water- flood the A sands of the Kuparuk River Reservoir. Iwill now review th'e performance of Dril Site lA. This drill site is also located in the CPF-1 area and is directly west of the gas injection Drill Site lB as shown on Exhibit 31. Drill Site lA was not as affected by injected gas as Drill Site 1E was at the start of the waterflood. Therefore, its response is considerably different from that of Drill Site lA. Eight 320-acre five-spot patterns are included on Drill Site lA as shown on Exhibit 32. These patterns are shown as extending outside the Drill Site lA boundary because some of the wells in offset drill sites have been impacted by the waterflood on Drill Site lA. The performance of Drill Site lA from January, 1982, to the present as shown on Exhibit 33, indicates a very positive response to the waterflood, especially in the GOR performance. During primary production from January, 1982, until January, 1983, the GOR increased as would be expected in a solution gas drive reservoir and reached a maximum of 1200 standard cubic feet per stock tank barrel. Since the start of waterflood, the GOR decreased quite rapidly and has leveled off to about 650 standard cubic feet per stock tank barrel. The oil rate R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, SRO AVENUE 1007 W, 3RD AVEiNUE 277-O572 - 277-0573 277-8543 272-7515 ANCHORAGE, ALASKA 99501 10 11 13 14 17 18 19 -25- dropped sharply at the start of the Increment One waterflood due to converting half of the wells on the drill site to water injection. Since that time it has continued to decline slightly. This is not due to lack of waterflood response, but rather to operational constraints. The water injection rate, shown as a blue line on this slide, has remained constant at about 30,000 barrels of water per day. Water breakthrough first occurred in June of 1983, about six months after the start of water injection. The produce~ water rate is currently about 2,000 barrels of water per day. Water Breakthrough occurred earlier than expected after the start of water injection considering the well spacing -- spacing on this drill site. This is due to the north-south directional permeability in the C sands and the fact that we have five-spot pattrens with injectin wells directly north or south of the producing wells. Exhibit 34 shows the wells which have water breakthrough in the Drill Site lA area. All of the active wells on Drill Site lA have water breakthrough except Well 1A-8. Breakthrough has also occurred on two wells on Drill Site 1F which are offset to injection wells 1A-7 and 1A-11. The two producing wells on the east side of the drill sitel are shut- in due to high GOR from injected gas at Drill Site lB. Well 1A-8 is shown on this exhibit and has not had water breakthrough. This well was originally drilled as one of the delineation wells in the Kuparuk River Field, and as such was R & R COURT REPORTERS 1310 N STREET, SUITE 101 .509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W 3RD AVENUE 272.7515 11 14 16 18 19 2O 21 -26- not drilled in a regular pattern location on this drill site. Consequently, the well is not directly north or south of an injection well. Because of its unique location, the performance of this well merits discussion. During primary productioon throughout 1982, the oil rate declined approximately 35% per year as shown on Exhibit 35. The oil rate decline leveled off at the beginning of the Increment I waterflood and the rate has since increased, indicating positive waterflood response. It is currently producing at over 90% of its initial rate. The GOR performance of this well is also interesting. It continued to increase after waterflood began, then dropped off sharply, then increased again, eventually leveling off. Recently it has again begun to decline. The fact that there are two peaks on the GOR curve could indicate that a gas bank from one of the sands appeared before the gas bank in another sand. The total performance of this well is indicative of what we can expect with a line-drive pattern. Well 1A-8 performance indicates that by lining up the patterns correctly, we should be able to successfully waterflood this reservoir even though the C sands have north-south directoinal permeability. Before concluding my discussion of the Drill Site lA performance, I would like to review the average injection profile of the drill site. Exhibit 36 shows that the fractured C-four interval is taking 65% of the water and contains about 25%'of the reserves. This drill site also contains a considerable \ , R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 100'7 W 3RD AVENUE 277-O572 - 277-0573 277-8543 272'7515 ANCHORAGE. ALASKA 99501 10 11 12 13 14 16 17 18 19 -27- amount of the C-one sand, which you will recall is a thin high permeability sand. Twenty-five percent of the injected water is entering this sand, which contains about 10% of the reserves. The unfractured C-three interval is taking only 6% of the water and contains about 30% of the reserves. The A sand is taking only 4% of the water and contains 35% of the reserves. I would like to emphasize that the differences in the C sand injectivity is not as severe a problem as it lmay seem. The water injection rate into this drill site is 30,000 barrels of water per day contrasted with a produced water rate of only 2,000 barrels of water per day. This indicates that most of the water is displacing oil. This concludes my discussion of the waterflood performance of the two Increment One drill sites, kAs I mentioned earlier, we are collecting data in other parts of the field to help confirl or disprOve some of the information obtained from the Increment One waterflood. This data will be used to help plan the full- field waterflood. I would like to review the directional permeability 'tests conducted on two CPF-2 drill sites shown on Exhibit 37. The two drill sites are 2X, in which we conducted a C sand only directional permeability test, and Drill Site 2C, in which we conducted an A sand only directional permeability test. Analysis of the test on Drill Site 2X has shown that the C sand does indeed have a directoinal permeability in hte north-south R ,5: R COURT REPORTERS 81o N STREET, SUITE 101 509 W, 3RD AVENUE 277'0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AvErNUE 272.7515 10 ]1 12 14 15 16 17 18 19 2O 21 -28- direction five times the permeability in the east-west direction. The results of the A sand tests on Drill 2C were somewhat surprising since this test indicated that the A sand has a directional permeability in the east-west direction with a magnitude of three to one. This result is suspect because the producing well, 2C-8, was partially faulted. This may have affected the results of the test. Since the 2C test did not provide conclusive results;, we plan to conduct a second A sand only directional permeability test on Drill Site 2F beginning in late May. In summary, the information which we have obtained from the Increment One waterflood has proven to be very valuable in our planning for fullfield waterflood. As shown on Exhibit 38~ many of the objectives of the pilot waterflood have been accomplished to some degree. We have determined reserVoir properties affecting injectivity with our injection profiles. These include the strong preference of injectin into the C sand over the A sand, and to a lesser degree, the high injectivity into the fractured intervals of the C sand. Reservoir properties affecting sweep are dominated by the north-south directional permeability of the C sand. In the near future, we hope to gain conclusive information concerning A sand directional permeability. We have also shown that waterflood response can be obtained from 320-acre patterns on Drill Site lA. We have not yet determined optimum well spacing, but have identified R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 , 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1007W. 3RD AVENUE 272 7.515 10 11 13 14 15 16 17 18 19 -29- situations which could require infill drilling. The information obtained from Increment one has also provided a basis for predicting recovery using reservoir models. The results of these models will be discussed in the fullfield waterflood performance section of the testimony. As Robert 1May and Steve Suellentrop go through their testimony, you will see how this information is actually being used in our fullfield waterflood planning. Robert May will now present the testimony on field waterflood operations. MR. CHATTERTON: Thank you, Laura. Robert, go. MR. MAY: Mr. Chairman and members of the Commission, my name is Robert May. I am regiOnal operations engineer for ARCO Alaska, Incorporated, and am responsible for all operations engienering studies and field surveillance program for the Kuparuk River Field. I received my Bachelor of Science degree in mechanical engineering from Southern Methodist University in 1970, and have been employed by ARCO as an engineer since that time. I spent 12 years in the Gulf Coast area prior to my assignment in Alaska and have now spent the last two years in engineering positions for ARCO in the Kuparuk River Field. MR. CHATTERTON: Thank you, Robert. The Commission finds that you qualify as an expert witness in these matters. MR. MAY: Thank you, Mr. Chairman. I would 810 N STREET, SUITE101 277"0572-277-0573 R &: R COURT REPORTERS 509 w. 3RD AVENUE 277-85/43 ANCHORAGE, ALASKA 99501 100'7 W 3RD AVEINLJE 2727515 10 11 16 17 18 19 -30- like to first cover the extensive surveillance programs under- taken by the Kuparuk River Unit working interst owners for Increment One waterflood. Following this, I will outline some of the actions already taklen in well completion design as a result of this program, and some of the on-going efforts to mitigate the intrasand imbalances shown in the previous testimony The surveillance program for Increment One waterflod is made up of two parts. First, the radioactive tracer .program and, second, extensive production/injection logging and bottom- hole pressure work. Laura Blacker has already outlined the objectives of this work. I will describe their implementation. The radioactive tracer program undertaken on Drill Site 1E has provided a great deal of useful data. The program is comosed of two parts: tagging and sampling. Radioactive tracers were place in nine Drill Site 1E injectors between May 19th and June 6th, 1983. Exhibit 39 shows the location of the tagged wells. The sampling program began almose immediately and tritium was first identified in Well 1E-28 about five days after tagging Well 1E-30. The high confidence radioactive tracer results to date are listed in Exhibit 40. Exhibit 41 shows the location of these wells. We have seen tracer breakthrough in more wells than those shown, however, the wells shown are the most reliable. Other tracer breakthroughs have been detected, specifically Nickel-63, however, becasue of their of repeatability, they have R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 · 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W, 3RD AVENUE 272.7515 10 11 13 14 15 18 19 21 -31- been excluded from this exhibit. Throughout the program, samples have been taken once a week on each producing well on the drill site. Considerable data has been gathered since startup of Increment One waterflood from various wireline aactivities, including injection profiles, production profiles, and various types of bottomhole pressure measurements. All of the efforts reviewed here are in addition to the requirements set forth in Conservation Order Number 173, and were undertaken in order to gain as mucn meaningful data as possible during Increment One without severely impacting our day-to-day operations. Exhibit 42 shows the number of wells in which injection profiles have been run. A total of 19 injection profiles were initially run in injection wells on Drill Sites lA and 1E. This data was needed to determine the relative injection volume by zone, hte results of which were already reviewed. These logs indicated predominate C-four and C-one sand injectin. Injection profiles were originally run in all ilnjection wells wit the exception of Well 1A-13. Well one- -- 1A-13 had a malfunctioning subsurface safetyk valve which prevented an initial log. However, the well -- well was repaired and included in the second set of injection profiles run in October, 1983. This subsequent set was run on selected injection wells to see if there had been any profile changes five to seven months after the initial runs. Exhibit 42 shows that six wells were included R & R COURT REPORTERS 810 N STREET, SUITE 101 .509 W, 3RD AVENUE 277'-0572 - 277-O573 277-8543 ANCHORAGE, ALASKA 99501 1OO'7 W 3RF) AVENLJ~:. 2727515 10 11 14 16 17 18 21 -32- in this second program. If profile changes occurred, the program would have been expanded to additional wells. However, the results were consistent with initial results and no additional logs were run. Also shown on Exhibit 42 is a compilation of the production profile logging during the Increment One surveillance program. A total of 14 wells had production profiles run. Again, these logs were run in addition to those required by Conservation Order Number 173. The initial logs, run as a part of the State requirement, were used as the basis to compare the logs listed in this exhibit. The production profile logs were reviewed for zones of water entry and any zones of entry increased contribution. All produc- -- production logs were run after water breakkkkkghrough. In order to monitor water breakthrough on Drill Site 1E, priority wells were identified and shakeouts were taken three times per -- per week. On Drill Site lA, well tests taken approximately once per week were used. On offsets to Drill Sites lA and 1E, well tests were again used. The criteria for water breakthrough was a repeated 1% water cut. An attempt was made to run all production surveys when the well reached a 10 to 20% water cut environment to provide accurate results. The production logs have confirmed that water is being prouced from the C-4 sands in wells on Drill Site 1E and the C-4 and C-1 sands in wells on Drill Site lA. Additionally, R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-O572 - 277-0573 2'77'8543 ANCHORAGE, ALASKA 99501 1007W 3RD AVENUE 272-7515 10 11 14 15' 16 ]8 19 21 -33- data was acquired on the capabilities of various production logging tools and combinatins of tools to optimize our surveillance of multizone producers in deviated wellbores. Exhibit 43 is a summation of the various pressure surveys run in conjunction with Increment One. Pressure data is useful for thee reasons. One, it is required to check injection pattern balance. Two, it aids in identifying problem wells that require stimulation. Three, it provides a data base which will aid in describing reservoir performance under waterflood. The areas of concern in waterflooding the Kuparuk River Field as identified by our surveillance program were reviewed earlier. I would like to further review the intrasand and inter, sand profile imbalances and how they relate to existing and future completions in the field. Exhibit 44 is a schematic of the existing completions in the Increment One waterflood area. The profile imbalances currently exist in commingled wellbores. These wells are typically characterized by high production or injeactin in the C sand, pimarily C-four and C-one depending on the area of the field, and much lower rates in the A sand. Aread affected by injected gas typically have high GOR C sand productin usually resulting in shut-in of the well and shut-in of the A sand. Because of these imbalances between the A and C sands, new wells in which both sands are present are evaluated for completion in the manner depicted in Exhibit 45. this selctive R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-854.3 ANCHORAGE, ALASKA 99501 1OO7 W 3RE) AVENUE. 2.72 '7515 10 11 13 14 16 17 18 19 21 -34- single completion allows separate stimulation of the two different sands with techniques designed for only that sand. Currently lthe C sand is acidized when required and the A sand is fracture stimulated to increase productivity/injectivity. The completion also allows isolation of the C sand from the A Sand. The isolation capability allows continued production from the A sand when G0R from the C sand dictate that the interval be shut-in. Additionally, this type of completion will allow us to regulate concurrent injection into the A land C sand through downhole devices. Intrasand profile impalances within the C sand during water injectin have also been discussed this morning. Typically when the C-four and/or C-one sand is present, injection.'.is primarily into those sands. Tests are currently being conducted on Well 1E-30 in the Increment One area to determine if the dominant injection profile can be altered by combining polymer with the injection water. The polymer is designed to reduce flow into the high permeability zones divertin9 water to other zones. Early work in this area is incomplete, but encouraging. I would like to now review the completion specifications for Kuparuk wells. Exhibit 46 is the completion specifications for the typical single completion. Exhibit 47 is the completion specification for a typical selective single completion. Not all wells fit these specificatoins exactly. We continually endeavor to optimize wellheads and downhole equipment based R 8: R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 2'77-0573 277-85z~3 ANCHORAGE, ALASKA 99501 100'7 W. 3f:~D AVENUE 272-7515 10 11 14 18 -35- on the expected long-term service of the -- the wells. Wells are designed in anticipation of acidizing and fracturing requirements and long-term service as water injetors during waterflood operations. The seven-inch casing string is cemented in place with the cement top located about 800 feet above the top of the Kuparuk interval. This is sufficient isolation during production/injection or stimulation operations to pre~ent fluid migration to any strata above the Kuparuk River Reservoir. Additionally, as a further safety precaution, we routinely monitor the casing/rubing annulus pressures. Summarizing this part of the testimony, we have diligently pursued the Increment One waterflood from an operations surveillance standpoint and have gained valuable data which will help us more effectively produce and waterflood the field. Key emphasis has already been placed in providing mechanical separation of the A and C sands in order to allow selective production/injection and stimulation, and we are evaluating chemical means for intrasand redistribution. The working interest owners request that no surveillance requirements be issued for this waterflood permit in addition to those currently included in Conservation Order Number 173. The unit operator will continue to aggressively pursue waterflood surveillance to provide sufficient quantities of data to maximize waterflood efficiency and oil recovery. Steve Suellentrop will continue today's testimony with R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 ~ 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272 '7515 10 11 13 14 16 17 18 19 -36- a review of fullfield waterflood performance. MR. CHATTERTON: Thank you very much, sir. And, Steve, why, you have already been sworn in as an expert witness. MR. SUELLENTROP: Thank you. I will now review our projection of fullfield waterflood performance and compare that with anticipated primary performance. Before I do that, however, I'd like to take some time and tell you how these forecasts were developed. These projections are those of the operator. Our method to predict field performance used an areal simulator in combination with more rigorous pattern modeling. The purpose of this combined procedure was to take advantage of the strengths of the areal simulator as well as mitigate its perceived weaknesses. The use of the areal simulator is appropriate in undeveloped sections of the field kwhere there will be little primary production prior t° waterflooding. The areal model, however, is not effective in accurately projecting waterflood performance after extended primary production. Neither is it efective in determining the impact of injected gas on primary and secondary performance. Pattern models have been developed to determine waterflood performance in these cases. The fullfield simulator is coarsely gridded into 80- acre cells areally, and two layers, the A and C sands, vertically R 8: R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 · 277-0573 277-85-43 ANCHORAGE, ALASKA 99501 1007 W 31RD AVENUE 272 7515 10 11 14 15 18 19 -37- The reservoir description incorporates our best understanding of net pay, porosity and permeability distribution throughout the field. It also includes our latest understanding of oil/. water contact, fluid distributions, and fluid properties. Despite some of its needed simplifications due to its size, we feel that it's adequate -- it adequately projects performance in the currently undeveloped sections of the field. Most drill sites in the CPF-3 area and the peripheral drill sites in CPF-1 and CPF-2 have been forecast with our areal model. Two general reservoir descriptions have been used in the pattern models: one with the A and C sands present, and one with the A sand only. The A and C sand description reflects our understanding of the Increment One waterflood results. MR. MORKUM: Oh, hold on. MR. SUELLENTROP: We'll take a break here to change the -- change the slides. The A and C sand model layout is depicted on Exhibit 48. This model has five layers: four layers for the C sand and one layer for all of the A sand. The top layer of the C- four interval has a high horizotal permeability in the X-direction of 800 miltidarcies to model the natural~ fractures, and a~higher permeability of 4000 millidarcies in the Y-direction to reflect directional permeability. This C-four interval has a net sand thickness of four feet and consequently the smallest volume of all the layers. The rest of the sand in the C-four interval R 8< R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 27'7-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVENUE 272. 7515 10 t? 18 19 20 -38- is unfractured and has a permeability of 80 millidarcies. The C-three interval has the largest net sand thickness of 25 feet. The C-one interval is isolated from the rest of the C sands and from the A sand. It has an X-direction horizontal permeability of 200 millidarcies and a Y-direction horizontal permeability of 1,000 millidarcies, similar to the directional permeability in the C-four fractured interval. A single A sand layer of 35 feet anld a permeability of 65 millidarcies was used in this pattern model. Exhibit 49 shows a typical waterflood performance of the A and C sand model with a direct line-drive pattern. After the start of water injection, pressure begins to increase and reaches initial pressure in five to six years. The pressure drop in this case is 675 psi, and is associated with approximately 4% primary recovery. Peak oil rate response is seen after two years of waterflood. Water breakthrough occurs almost three years after the start of water injection. The second pattern model used to evaluate waterflood response was one with only A sands present. As presented in the geologic desCription, the A sand intervals overlap areally, but usually only two are present at any location. The A-four and A-three sand intervals, sperated by an impermeable shale barrier -- barrier zone are present in the CPF-2 area. The pattern model reflects this reservoir description. A five-layere. pattern model containing two layers for the A-four sands with R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950'1 1007 W 3RD AVENUE 272.751.5 ]0 11 13 ]4 15 16 17 18 19 -39- equal permeability and no directional permeability is shown in Exhibit 50. The top A-four layer is thinner to allow faster fluid movement. A thin upper layer was also used for the upper A-three sand. Layers four and five contain the rest of the A-3 net sand and have identical properties. Exhibit 51 -- 51 shows the performance of this pattern model with a five-spot water injection pattern. The injection nad production rate curves show the same characateristics as the A and C sand model, however, because of the lower permeabilit· in hte A sand, the time to waterflood response is longer. G©R responds the quickest to waterflood, collapsing within two years to solution GOR. Peak oil response occurred after four years of waterflood. Water breakthrough occurs almost six years after the start of water injection. The impact of gas injection and encroachment have also been determined independently in pattern models similar in description to the A sand only pattern models. GOR performance on those drill sites where gas injection or encroachment is anticipated has been modified according to pattern model predictions. Exhibit 52 shows the drill sites used in the performance prediction, and indicates the type of treatment accorded to each drill site. The drill sites shown in red are those drill sites whose performances were predicted using the areal model. The drill sites shown in green are those drill sites whose R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 9950~ 100'7 W 3RD AVENUE 272'7515 10 13 15 18 19 2O -40- performances were determined using the A and C sand pattern models. The A sand only drill sites are shown in blue. Each of these of these drill sites waterflood response was determined independently as a function of its anticipated primary production Those drill sites which have had their GOR and oil rate performance modified due to gas injection are shown in yellow. Those drill sites which have been modi- -- have had modified behavior due to gas encroachment are striped. Oil, gas and water rates were totaled by drill lsite and modified by facility limit constraints to yield fullfield performance. Oil production was deferred on those drill sites impacted by gas injection when the facility gas handling capacity was reached. The oil rate projected by this method is shown in Exhibit 53. It shows that the startup of CPF-2 in 1985 increases the fullfield rate to 181,000 stock tank barrel's of oil per day. A reduction in the oil rate to 165,000 stock tank barrels per day in 1986 occurs with the converstion of wells to water injection service. CPF-3 will start up in 1987 and oil production should increase to 228,000 stock tank barrels per day. The peak oil rate should occur in 1988 at 25,000 stock tank barrels per day as a result of waterflood response. After 1989, the oil rate begins its decline at about 7% per year to the year 2017. The field has a relatively shallow decline rate due to the staging in the water- -- due to staging in the R 8<R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 · 277-0573 277-8543 ANCHORAGE ALASKA 99501 1007 W. 3RD AVENUE 272 7515 10 11 13 14 16 17 18 19 -41- waterflood on gas injection drill sites and the deferred response to waterflood on some drill sites due to gas encroachment. For comparison, the oil production from the Kuparuk River Field under natural depletin is also shown. The depletion mechanism for this case is solution gas drive with some immiscible gas injection support. These rates were obtained solely from our areal model lusing the same development schedule as the waterflood case and are for 320-acre development within the participating area. This case also assumes that most of the solution gas is not reinjected. In 1985, the oil rate would reach 127,000 stock tank barrels per daky with the start up of CPF-2, and peak at 143,000 stock tank barrelsl in 1987 following the start of CPF-3. After its peak, the rate declines at 17% per year until the year 2012. Cumulative oil production for both primary and secondary recoveries are shown on Exhibit 54. After 30 years, neatural depletion would yield 560 million stock tank barrels. In comparison, waterflooding the Kuparuk River Field is expected to yield approximately 1.6 billion stock tank barrels of oil, or over 1.04 billion attributable to waterflooding. Primary recovery would be 10.5% of the oil in place while secondary recovery under waterflood is -- is expected to be 30% of the oil in place. Exhibit 55 shows projected cumulative'~ solution gas production from both the primary and secondary cases. Under R &: R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-O572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W. 3RD AVENUE 2'72 7515 ]0 11 14 15 16 17 18 19 20 -42- natural depletion, cumulative gas productin is nearly 1.5 trillion cubic feet by the year 2012. In the -- in the water- flood case, the cumulative gas produced to year 2017 is nearly 910 billion cubic feet. Injected water will be comprised of source water from the Beaufort Sea and cycled produced water. As shown on Exhibit 56, peak source water plant requirements will be from 1986 through 1989 at nearly 340,000 barrels of water per day. In future years the source water requirements will decline as fill up occurs and produced water is reinjected. Significant produced water first occurs in 1988 with the water coming primarily from the CPF-1 area. The produced water rate rises over the life of the field and reaches a producing water/oil ratio of seven to one by the year 2017. Pattern selection througout the Kuparuk River Field will e based on results from the Increment One waterflood, the directional permeability tests, and field performance. Our present understanding of fluid properties in the Kuparuk river Field lindicate a mobility ratio of slightly less than unity. While this is favorable for waterflood efficiency, it limits the waterflood patterns to those with a one to one producer/ injector -- injector ratio. A special request has been made to alow infill drilling to 40-acre spacing. Approval of this request will allow flexibility -- flexibility in determining ~timate pattern density. It also represents the density R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, SRO AVENUE 100'7 W 3RD AVENUE 277-0572~277-0573 277-8543 272,7515 ANCHORAGE. ALASKA 99501 10 11 13 14 17 18 - 43- currently existing on the western half of Drill Site 1E. Exhibit 57 shows a direct line drive pattern with injectors and producers in north-south rows on regular 160-acre spacing. The 320-acre waterflood pattern is shown with a dashed line. This pattern is preferred in areas of A and C sand development where drill sites have already been drilled on 160- acre spacing. One advantage of this pattern is that it optimizes recovery where strong directional permeability exists in the C sand. Another advantage of this pattern is that it allows infill drililng of a symmetrical five-spot pattern aligned 45° off north-south as shown on Exhibit 58. Infilling -- infill drilling in this manner will result in 80-acre regular spacing with 160-acre waterflood patterns shown with a dashed line. Exhibit 59 shows a staggered line drive on 160-acre spacing., This type of develop- -- this type of pattern can be effectively utilized in areas of A and C sand development where drilling to 160-acre regular locatins has not been complete This results in the 320-acre waterflood patterns outlined on Exhibit 59. One advantage of this pattern is a high- -- slightly higher sweep efficiency at water breakthrough and a shorter time to peak response compared to the direct line-drive pattern. Exhibit 60 shows a regular 160-acre five-spot pattern containing 320-acre waterflood pattern. This pattern is targeted for use in areas of A sand only development depending on the outcome of the directional permeability test. This configuration R & R COURT REPORTERS 810 N STREET, SUITE 101 .509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W. 3RD AVE..NUE 272 7515 10 11 12 13 14 15 16 17 18 19 21 -45- has a shorter injector-producer distance allowing for the quickest response time. It also yields symmetrical infill drilling configurations. Shown on Exhibit 61 are both 80-acre and 40-acre regular spacing. The 80-acre spacing shown in the northwest quadrant results in 160-acre waterflood patterns similar to the infill results of the direct line drive. The 40-acre regular spacing shown in the southwest quadrant results in 80-acre waterflood patterns. In addition to infill drilling on regular spac- -- spacing~, approval of the 40-acre spacing also provides the flexibility to handle special situations should the need arise. Drill Site lA depicted on Exhibit 62 with its existing injector- producer configuration shown in black triangles and circles respectively. Also shown are the sealing faults reviewed 'in the geologic description of this testimony. Shown in red triangles and circles on this diaagram is one potential method of optimizing oil recovery within these sealing boundaries. The realization of this option would require infill drilling on 40-acre regular spacing. This diagram is used only for illustrative purposes and does not represent any currently planned development by the Kuparuk owners. Activity within the Kuparuk River Field as the result of waterflood development is illustrated in Exhibit 63, which shows the number of production wells and the number of water R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277"8543 ANCF'IORAOE, ALASKA 99501 1OO7 W 3RD AVENUE 2727515 10 11 14 15 16 18 19 2O -45- injection wells at any year. Before 1986, drill sites involved with Increment One Waterflood and its possible expansion contain the only water injectors. After 1986, with the startup of full- field waterflood, the number of water injectors is approximately half of the total number of wells in the field. When initial development is complete, we expect approximately 400 water injection wells and 400 producing wells within the waterflood permit boundary. This well count represents fullfield developmen' on 160-acre regular spacing. In summary, secondary recovery by waterflooding is expected to recover an additional 1.04 billion stock tank barrels of oil from the Kuparuk River Oil Pool above that recovery through natural depletion. The recovery factor is anticipated to increase 19.5% to 30% of the original oil in place. CumUlative gas production is anticipated to decrease nine hundred -- 590 billion standard cubic feet. Fullfield waterflood patterns are still being decided, but will probably be a combination of line-drive and five-spot patterns depending on reservoir heterogeneities. Forty-acre spacing will allow us the flexibility to optimize pattern selection and waterflood development in the Kuparuk river Field. This concludes mly review of projected fullfield water- flood performance and development. Robert May will now review the source waters to be used in this development. MR. CHATTERTON: Thank you, Steve. Robert, R & R COURT REPORTERS 810 N STREET, SUlTE101 509 W, 3RD AVENUE 277-0572-277-0573 277.~8543 ANCHORAGE. ALASKA 99501 1OO'7 W 3RD AVENUE: 2727515 10 11 14 16 17 18 il -46- you are already been sworn (sic), so proceed. MR. MAY: Thank you, Mr. Chairman. I will now review the source water currently in use in the Increment One waterflood and that planned for fullfield waterflood. Additionally, I will review the current disposition of produced water in the Increment One area and the planned deposition of produced water during fullfield waterflood. Source water for use in the Increment One waterflood is obtained from ten Upper Ugnu source wells located on Drill Site lB. Their location is shown on Exhibit 64. Operating history of Increment One has demonstrated tghat the Upper Ugnu aquifer is a reliable source of high quality injection water. This source water is beingsuccessfully obtained from ten gravel packed wells lifted with hydraulic jet pumps. Exhibit 65 shows the withdrawals from this reservoir. About 16 million barrels have been withdrawn to date. Exhibit 66 is a log of a typical Upper Ugnu interval as it appears in Water Source Well Number Six. This well contains about 300 foot (sic) of perforated and gravel packed interval. Downhold hydraulic pumps and gravel pack completions are performaing as expected with no problems encountered to date. Bottomhole pressure monitoring of the Upper Ugnu aquifer was initiated early to gaive indications of reservoir limits which might affect the aquifer's ability to suply injection water for Increment One. Exhibit 67 is a summary of the pressure R 8:R COURT REPORTERS 810 N STREET. SUITE 101 509 W. .3RD AVENUE 277-0572 - 277-0573 277-854-3 ANCHORAGE, ALASKA 99501 100'7 W 3RD AVENUE 272 '7515 10 11 14 15 t? 18 19 -47- history to date. This exhibit also compares actual pressure history to pressure predicted from an infinite acting aquifer. The prediction technique acounts for pressure responses due to the ten water source wellsl and uses daily allocated water production volumes from each well as input. The actual pressures compare favorably with predicted pressures until October 1983. The pressure in January, 1984, is lower than predicted, possibly indicating some boundary effects. The current bottomhole pressure indicates, however, that this aquifer is capable of supplying sufficient rate for the current -- current Increment One waterflood and the proposed expansion. If the January 1984, pressure does indicate a boundary, the aquifer still would be large enough to supply all projected source water needs until startup of fullfield waterflood. Additionally, the mechanical capability of increasing the net withdrawal rate from the source water wells has been evaluated. A high rate test was conducted on Water Source Well Number Four in May, 1983. Increased withdrawal rates were achieved without adversely affecting the gravel pack completion. The mechanical completion used in this test will enable us to withdraw at rates approaching 58,000 barrels per day of water for the expansion of Increment One. Exhibit 68 shows the water production from the Increment One waterflood. Until recently facility constraints limited the amount of produced water we could process. In March, 1984, R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE: 277-0572 ' 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W 3RD AVENUt:. 272 7515 ]0 ]1 12 13 15 16 18 19 -48- after extensive water compatibility work comparing Upper Ugnu source water with both Kuparuk water and produced water, the decision was made to mix the produced and source waters, this has allowed some wells which had been cut back or shut in because of high water cut to be brought back on production. Water handling capabilities at CPF-1 are currently being optimized to process all available produced water. With the start up of Kuparuk fullfield waterflood, water sources will consist -- will consist of both produced water and treat- -- treated Beaufort Sea water. Unlike the Upper Ugnu water and current produced waters, the Beaufort Sea water and produced water will be handled separately in order to prevent facility problems associated with water incompatibility. Exhibit 69 shows water analyses of the current Upper Ugnu water source, the Kuparuk River Reservoir water, the current produced water, and the Beaufort Sea water. When Beaufort Sea water and the Kuparuk River Reservoir water are mixed, the potential exists for formation of either barium sulfate or calcium carbonate scale. Summarizing this part of the testimony, at current with- drawal rates, the Upper Ugnu aquifer is continuing to be a source of high quality water for Increment One, and will be able to -- to continue to supply water in increased volumes for a 1984 expansion of waterflood. Additionally, after extensive compatibility testing, the Upper Ugnu source water and the R 8<R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RID AVENUE 277-0572 . 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1OO7 W ,3RD AVENUE 272 75'i5 10 11 13 14 15 16 18 19 "i -49- produced water are currently being mixed. This removes part of the facility limitation on produced water, thus allowing additional optimization of Increment One. The Beaufort Sea will replace the Upper Ugnu as the source with start kup of fullfield waterflood. The incompatibility of this water with produced water will necessitate separate handling systems. This concludes the water source part of the testimony. The following testimony by Joel Brandstetter will review the fullfield waterflood facilities. MR. CHATTERTON: Thank you, Robert. Joel? MR. BRANDSTETTER: Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Joel Brandstetter. I received a Bachelor of Science degree in mechanical engineering from Texas A and M University in 1975. I have worked for ARCO from that time in many areas, including offshore operations, project staff and exploration. I am presently lan area engineer in the facility planning group for the Kuparuk River Field in charge of the -- of waterflood facilities planning. I will review today the surface facilities needed to accomplish fullfield waterflood. MR. CHATTERTON: Joel -- Joel, the Commission finds you qualified to testify as an expert witness. MR. BRANDSTETTER: Thank you, Mr. Chairman. The expansion of the water- -- of the Kuparuk River Field water- flood involves the fabrication, erection and start up of a number R & R COURT REPORTERS 810 N STREET, SUITE 101 .509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RI') AVENt. If.-. 272 751.5 10 11 12 14 16 17 18 19 20 -50- of new sea water handling facilities indicated in this functional facility diagram in Ehxibit 70. The first waterflood -- I'm sorry, the first facility in the in -- is in an intake structure and sea water treatment plant at Oliktok Point. The intake will be located adjacent to the existing dock face, with the seawater treatment plant, or STP, attached via short pipeway to the south. The second facility is a low pressure, distribution system to transport the -- the treated sea water to the local injection plants at CPFs One and Two -- One, Two and Three, including pigging equipment to evacuate the low pressure system in case of plant shutdown. The third system is the local injection plants, or LIPs, at CPF-One, Two and Three, which boost the water up to injection pressure. And, finally, the distribution flowlines which deliver this high pressure water to the drill sites for injection and their associated pigging equipment for freeze protection. I will now review more closely each .component in -- in this system. As indicated in -- on Exhibit 71, the fact of the intake structure is a westward continuation of the exist- -- existing dock face. This orientation was chosen to minimize problems with sedimentation blocking flow into the seawater intakes. The intake configuration and marine by-pass system shown in Ehxibit 72 are based upon the Prudhoe Bay design with modifications for -- for the shallower water depth and Kuparuk's 810 N STREET, SUITE101 277-0572-277-0573 R & R COURT REPORTERS 509 w. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 100'7 W 3RE) AVENUE 272 '7515 10 11 12 13 14 17 18 19 440,000 barrels of water per day peak flow requirement. There are four identical intalke channels, each with seal bars to keep out marine mammals, a trash screen to stop floating debris and a primary diverter screen to move smaller marine life beyond the pump suctions. This screen is oriented such that water velocity is acurately established and fish move directly into the bypass system without impingement upon the screens. The bypass system is sized to accommodate the largest fish species in the area. To maximize the use of water entering the plant, the four bypass streams are combined in -- in two secondary diverter systems. Additional water is drawn off here for use in recycle lines and in the jet pump which moves the fish back to the Beaufort Sea. The major volume of water is transferred to the seawater treatment plant for further processing. There are additional minor return streams of hot water from the seawater treatment plant used to prevent ice formation on the seal guards, trash screens and diverters during the winter months. With 'the STP as represented in Exhibit 73, water from the seawater intake is heated in titanium plate and frame ~changes to approximately 60© Fahrenheit using glycol from fired heaters. The water is then filtered and deareated before being pumped to the local injection plants as CPFs One, Two and Three. This deareation is accomplished using natural case in packed columns which is combined down stream with makeup R 8: R COURT REPORTERS 810 N STREET, SUITE 101 509 W 3RD AVENUE 277-0572 - 2'77-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W, 3RD AVE. NL.J[-E 272-7515 10 11 14 16 18 19 -52- gas from the fuel sys- -- fuel gas system to provide fuel for the plant heaters. The STP power is provided by two turbine driven generators. The processed water is transferred as seen in Exhibit 74 from the STP in a 30-inch trunk to the LIP at CPF-Three and continuing to the "Y" where 24-inch branch lines transport it to the local injection plants at CPFs One and Two. The use of these large lines optimized the pump size needed and, additionally, increasaed line cooldown time during no-flow conditions resulting in a longer time before freeze up. kThese pipelines utilize pigging facilities for line evacuation in the event an extended plant -- in the event of an extended plant shut down. Pigs driven by natural gas remove the water from the lines to eliminate freezing problems. The pipelines will be warmed prior to start up with gas obtained from the gas lift system which is heated to approximately 180© Fahrenheit. In the local injection plants depicted on Exhibit 75, the source water and produced water are handled in two completely isolated systems. Each water type is received in a separate surge tank. And the tanks are -- feed electric driven booster pumps which supply intermediate pressurized water through a manifold system 'to turbine driven injection pumps where a final injection pressure 2550 pounds per square inch is obtained. Each pump train is identical, and manifolding and valving allow handling of either produced or source water by any train as shown as -- in this exhibit. Two pump trains will supplement R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277..8543 ANCHORAGE, ALASKA 99501 100'7 W. 3RD AVENUE: 272 7515 10 11 14 16 17 18 19 20 the existing Increment One pump trains at CPF-One and four trains will be installed at CPF-Two. Provisions have been made to add filtering equipment to the produced water system if needed later. A third local injection plant will arrive with CPF-Three in the 1986 sealift adding two additional pump trains to the system. From the L- -- the local injection plants a radial net- work of flowlines shown on Exhibit 76 distributes the water at injection pressures to individual sites in each CPF area. These lines also contain pigging facilities for line evacuation in the event an extended shutdown occurs. This concludes the description of the facilities that will be needed for fullfield waterflood, and Steve Suellentrop will now summarize today's testimony. MR. CHATTERTON: Thank you, Joel. Steve, you sure may proceed. MR. SUELLENTROP: In summary, the schedule for full- -- fullfield waterflood development achieves water injection on major portions of CPF-One, CPF-Two, and CPF-3 by the year end of of 1987. Results from the Increment One pilot will be incorporated in the fullfield waterflood plans. Injection well profiles have indicated preferential water entry into the C sand intervals. The combination of A sand stimulation techniques and alternative well completion, such as selective singles are needed to balance water injection profiles. R &: R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W, 3RID AVENIUE 272 '7515 10 11 14 15 18 19 Radioactive tracer data and pressure testing indicates a north- south directional permeability in at least the C sands. Oil recovery can benefit from this permeability trend by proper orientation and selection of waterflood patterns. Reservoir studies of waterflood performance indicate the productoin of 1.6 billion barrels of oil over a 35-year period for a 30% recovery of the original oil in plce. Natural depletion only of the Kuparuk River Oil Pool would yield 560 million stock tank barrels of oil. Optimization of oil recovery will require addressing the concerns highlighted by Increment One waterflood and the flexibility to drill to denser spacing than the planned 160 acres per well when geological conditions control fluid movement. Major waterflood facilities will be operational by January, 1986. Approximately 400,000 barrles of water per day of Beaufort Sea water will be filtered, deaerate- -- deaereated, heated and pumped through low pressure pipelines to local injection plants at each CPF. The local injection plants will increase the pressure of the source and produced water streams for distribution though a high pressure radial trunk system to the drill sites and eventual injection into the Kuparuk sands. Thank you for your attention. That concludes the testimony of the applicant. MR. CHATTERTON: Thank you very much, gentlemen. We appreciate it. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORA(GE, ALASKA 99501 1007 W, 3RD AVENUE 272 7515 ]0 11 14 15 16 17 18 19 -55- Are there any others that wish to present testimony? John? I'll 'tell you what we might do, John, we didn't expect it in time. Why don't you sit up here and maybe one of these mikes will reach over there. Will that be okay? COURT REPORTER: That one over there. MR. MILLER: That will be just fine. MR. CHATTERTON: We've got one set for you, okay. COURT REPORTER: No, take one of the ones that's already over there and put it over ..... MR. CHATTERTON: Okay. How about taking one from in front of Laura there or something. MR. WILLIAMS: Mr. Chairman, just for the -- for record purposes, the Applicant would request that the exhibits shown today, which will be delivered to the Commission, be admitted as part of the testimony and the testimony provided here today. MR. CHATTERTON: That -- that we appreciate, that we accept and that -- those are part of the record. MR. MILLER: Mr. Chairman, members of the Commission, my name is John Miller, and I am area manager for BP-Alaska Exploration, Inc. On behalf of BP-Alaska Exploration, Inc., I wish to offer a supplementary statement to the testimony submitted by ARCO. Testimony for application for additional recovery. BP-Alaska Exploration, Inc., with approximately 28% interest in R & R COURT REPORTERS 81o N STREET, SUITE 101 509 W, 3RD AVENUE 2'77-05-/2 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENLJE 272-7515 10 17 18 t9 -56- the Kuparuk River Unit, is a significant working interest owner. Since before unitization BPAE has been working actively with the unit operator and other partners in planning of development and operations for the field. BPAE believes that the performance to date of the Increment One pilot waterflood demonstrates the potential benefits to be gained by the proposed fullfield waterflood project. Our own studies support those provided by ARCO in this testimony and lead to the conclusion that waterflood of the Kuparuk Reser- -- River Reservoir will recover three times the quantity of oil that would be produced under natural depletion. BPAE with other partners has assisted ARCO in preparing the testimony presented by them to the Commission today and fully endorses the application for the Kuparuk River Field fullfield waterflood project. In addition, BPAE joins ARCO in making the accompanying three special requests. We thank the Commission for this opportunity to submit testimony in support of this application. Signed, John Grundon, President, BP Alaska Exploration. Thank you. MR. CHATTERTON: Okay, John. Thank you very much We appreciate that testimony. Are there any others that wish to testify on this matter? As I indicated before, I -- I think this will be a good time to take a break. Before we break though, I would like to introduce our executive secretary for the Commission, B.J. in the R & R COURT REPORTERS 8'10 N STREET. SUITE 101 .509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 9950'1 100'7 W 3RD AVENUE 272 '7515 10 11 13 14 17 18 19 24 -57- back of the room. And if there are any questions that the audience might wish the Commission to ask of either of the people that presented direct testimony, why would you please write them down and hand them to BJ and she'll bring them to us. With that, why let's reconvene in approximately minutes. Ten or 12 minutes. Thank you. (Off record) (On record) MR. CHATTERTON: Okay. We are reconvened and back on the record, Meredith, I believe? B.J., did we get any questions? B.J.: None. MR. CHATTERTON: Okay. Are there -- is there anyone that wishes to question the people that have testified? Or submit questions to us is more appropriate. Very good. Before we -- I'm sure the Commission will have a question or two, and before we get to that, I want to thank John and Steve and all of you people for your testimony today. It was well presented in my just- -- judgment, and it was very -- very complete and so forth. So you are to be congratulated by somebody I hope. Okay. Now, Lonnie, do you have any questions? MR. SMITH: Yes, I have a few here scattered through. I'm trying to determine where to start here. Just a minute. I think I've marked some of them about in two different places because of the way the testimony was presented. Page 15. R & R COURT REPORTERS 131o N STREET. SUITE 101 509 W. 3RD AVENUE 277'0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1OO'7 W 3RD AVENUE 272-7515 10 11 13 14 15 16 17 18 19 -58- I think this was -- would be for Laura Blocker. Is it Blocker or Blacker? Laura Blacker. Laura, on page 15, that reference to Exhibit 24, in that second paragraph there on that page, you indicated that the performance of Drill Site 1E has been impacted by gas injection. And I guess you adequately explained later how that was -- how that was impacted, but that was my question there just -- just what was the -- what was the magnitude and effect of this impact? MS. BLACKER: Are you referring to the -- the amount of gas that's encroached into the drill site? Or the GORs MR. SMITH: Yes, if you would elaborate a little bit on -- on what the effect of the gas injection was? I mean, how bad was it or how good was it or ..... MS. BLACKER: Okay. MR. CHATTERTON: Ted, we don't need the slide I don't think. MR. SMITH: .... to what ..... MS. BLACKER: Well, for the -- at the time that we started the Increment One waterflood, there had been a couple of billion cubic feet of gas which had migrated into the Drill Site 1E area we think mostly from Drill Site lB where we first began gas injection. At the -- there were several wells -- there were about six of the wells were shut in due to high GOR.before we ever started water injection. And what we had found was that the water injection did not move the gas off the drill site. We R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENIJE 272 7515 10 11 13 14 18 19 24 -59- were never able to get the GORs in those wells down enough by water injection so that we could actually bring them back on production. And that's the -- the main reason we haven't seen ~uch water response from the drill site is that most of the wells have been shut in. MR. SMITH: Well, my next question is along that same line. You indicated on the next page that the waterflood has not prevented the further migration of gas into the drill site, and then in some other testimony later, it was indicated that waterflooding of the gas injection areas would be delayed until later dates. Do you really -- you still expect to get an effective waterflood in gas injected areas? MS. BLACKER: Yes, we do. MR. SMITH: Why? MS. BLACKER: Well, when the field fuel requirements exceed the gas production, we'll be able to produce the gas back out of these drill sites, and once we are able -- once we blow down this gas, we'll -- we'll be able to waterflood the drill site, and we should get the same recovery that we would if we'd never injected gas into the drill site. MR. SMITH: Okay. Without a gas sales, -- you expect to do this without a -- able -- without putting the gas off of the property? MS. BLACKER: Yes, that's right. MR. SMITH: Because of why? R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1007W 3RD AVENUE 272 7515 10 11 13 14 15 16 17 19 2O -60- MS. BLACKER: Because by the mid 1990s the field fuel requirement will exceed the produced gas. MR. SMITH: Okay. Well, let's see. On page -- on page 17 you spoke there about the -- that a disproportionate share of the water is entering the C sands and relative to the C sands reserves, and this is one of the common problems with the over-all field and other zones, too, I believe. But anyway they -- the reserves -- where the higher reserves are -- there's a disproportionate share of the water goes into the proper places, and what are the main -- of course, you've -- you've determined this and you know this from the pilot project and the -- the production so far. And -- but you very -- you just touched slightly on the methods of controlling this or doing something about it. Can you elaborate any more on how you're going to do something about this? MS. BLACKER: Well, I think Robert ..... MR. SMITH: Okay. MS. BLACKER: ..... May can answer that question. MR. SMITH: Who- -- whomever. MR. MAY: I might elaborate a little bit. What ~e think -- what we believe we can do and what we're doing right this minute is -- is running selective single completions in the -- in the existing well bores. We'll'have a packer that actually separates the A from the C sand. This will allow us to stimulate the A sand selectively without stimulating the C sand. C sand is R 8< R COURT REPORTERS 810 N STREET. SUITE 101 509 W, ,3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272'7515 10 11 13 14 15 16 ¸18 19 -61- typically very high productivity, very high injectivity. The A sand is not as high productivity or injectivity. Fracture ~imulations done selectively like -- like this will allow us to increase productivity and injectivity in the A sand, thus balancing the production and/or injection. MR. SMITH: Okay. There -- there was mentioned the use of polymers at one point? MR. MAY: We lhave looked in and we have conducte( a test on 1E-30 as lmentioned in our testimony on polymers. It's primarily a test case trying to determine if polymers would be effective to correct the intrasand imbalances, the imbalances that prevent injection into the C-three interval I guess is one ~ the primary -- those -- those tests were very, very early. We -- we've -- we've run some and have seen some redistribution of -- of the injection profiles. We're currently taking another look at it to go back and -- and try again and see if we can -- can confirm this redistribution. MR. SMITH: Okay. And, of course, one of the dominant controlling factors is the directional permeability thing, and -- and you indicated -- and it was -- I don't know which would be the best to speak to this, but can you give us any ~rther details as to your current test in the A sand? The status of that test for determining directional permeability? MS. BLACKER: Again Robert knows more about when ~'s going to start. R 8< R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272 7515 .? 10 11 16 17 18 -62- MR. MAY: Well, we're -- we're currently set up to run a directional permeability test as Laura mentioned on Drill Site 2F. It's one producting well with eight surrounding ~ells with -- with pressure bombs (ph) located in -- in them to Wy to monitor the pressure pulse. We're at this moment running pressure bombs in those offset wells and should commence -- should actually commence the initial straight-line portion of the test sometime late this week. MR. SMITH: Okay. But there's no results yet, of course? MS. BLACKER: No. MR. SMITH: Robert, on page 24 you mention the surveillance program that you've been using and I presume you -- you -- you propose to continue this -- this type of set surveillance program with the fieldwide injection. Do any of the radioactive tracers that you -- that you use., is there a possibility of fluids that are harmful to -- to people in the program? Or any possibility of waste of fluids because of these radioactive tracers? MR. MAY: We don't believe so. These are -- they're fairly typically used in -- in other tracer programs and -- and they're handled very carefully and they're very, very low concentrations. They don't present a known hazard. MR. SMITH: Okay. Robert, on page 27, with reference to Exhibit 43, you mention taking data base. Are -- is R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1OO7 W 3RD AVENUE ;272 7515 10 11 14 17 18 19 21 -63- the data base that you're getting now adequate in your estimate? MR. MAY: We believe so. It's quite an extensive program. I -- I think we ...... MR. SMITH: Okay. I believe this was -- would be Steve, on page 34. Steve, you spoke there to the, let's see, peak oil response occurs after four years of waterflood and, here it is, water breakthrough occurs almost six years after the start of water injection. How does the reality of results from the pilot waterflood compare to this prediction or back it up or is it contrary to it? MR. SUELLENTROP: This is -- again, this is for the A sand only pattern. Remember, in Laura's testimony, we've been injecting water in our A sand only pattern 1E for almost a year and a half now on 40-acre spacing, and as of yet not seen any water breakthrough. We think it corresponds very well with what we would expect on the~320-acre patterns in the A sand. 5hese patterns would be essentially four times areal -- areal extent of our current A sand pattern where we haven't see it in a year and a half, so ..... MR. SMITH: And, of course, that was primarily the reason for the -- the small spacing on the pilot, is that true? So .... MR. SUELLENTROP: The pti- ~ ...... MR. SMITH: ..... that you ..... MR. SUELLENTROP: ..... primary reason was the C R &:R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 2-77-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1OO'7 W, 3RD AVENUE 272 7515 10 11 13 ]4 15 16 17 18 -64- responds quicker ..... MR. SMITH: Yeah. MR. SUELLENTROP: ..... in a shorter period of time. MR. SMITH: Okay. Relatively speaking, the same thing on the C sands. I don't know that I've marked the place, but what was the time -- when do you expect breakthrough? MR. SUELLENTROP: Back on page 33 I indicated that breakthrough occurs in three years after injection. And, of course, that's -- we have seen it on 320-acre patterns within six months on Drill Site lA. This three-year breakthrough is the result of re-orienting into a line-drive pattern and taking advantage of the directional permeability. And that's what that prediction on the pattern model -- pattern model performance was matched to the early breakthrough in a five-spot and reconfigured to a line-drive to give this three-year breakthrough. MR. SMITH: In your -- Steve, there on that page 35 in the lower paragraph, in your natural depletion case, why did you assume that under the -- the base conditions there that the solution gas was not reinjected? MR. SUELLENTROP Primarily it was for efficiency in running the simulator on a -- we were -- we weren't able to -- to get the gas into the model at the rate with with -- with which we were producing and the -- the natural assumption was to just not to reinject all the -- all the produced gas. It was R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572" 277-O573 277-8543 ANCHORAGE, ALASKA 99501 ~007 W, 3RD AVENUE. 272 7515 10 11 13 14 16 18 19 2.3 -65- primarily a model deficiency. MR. SMITH: Okay. Okay. At the bottom of page 38, Steve, and the top of 39 there, speaking of the lA 40-acre regular spacing, the last sentence, "This diagram is used only for illustrative purposes and does not represent any current planned development by the Kuparuk owners. I believe that's where you were showing infill wells, is that true? MR. SUELLENTROP: Yes, sir. It was the 40-acre ...~ spacing between the two sealing boundaries. MR. SMITH: Yeah. Why would you not pursue that in that area? MR. SUELLENTROP: We are internally studying that situation. It has not been adopted by the -- all the owners, and that's why a disclaimer is in there. We are currently developing the entire field on 160 and our plans call after that to go back and review in detail these infill cases. It -- It just has not been adopted by the owners yet. MR. SMITH: Okay. On that same page there, in the next paragraph you mention the -- the total number of 400 injectors and 400 producing wells. How many gas injection wells do you expect to drill? At a peak we'll -- we will have approximately 32 gas injection wells, or wells capable of gas injection service, depending on the -- the injectivity we -- it's undetermined how many we'll be using at any one time. R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 100"7 W. 3RD AVENU~:. 2727515 10 11 12 15 16 17 18 19 20 -66- MR. SMITH: With reference to the gas injection ~ells, of course, you've -- have one large gas invaded area in there and you're -- your plan to, over to the southwest, to develop another. How do you -- how do you plan to protect from the directional permeability there of -- of the -- of it affectin~ other areas massively? MR. SUELLENTROP: We -- we've chosen the -- that particular area in the southwestern portion primarily because it was going to -- it was -- it was to be only A sands where we have not seen directional permeability. We think the gas injection performance in those A sands will be better than the -- what we have experienced in the C sands on the eastern side. We don't -- those volumes in those areas impacted that was shown on the slide represent the total volume we think will be occupied by the total volume of gas needed to be injected. MR. SMITH: Okay. This would be Robert May I think in his testimony on page 42, where you were addressing the aquifer, the Ugnu aquifer, in Exhibit 67 you said your January pressure was off your prediction, was lower than your predictions Do you plan -- it's been some while since January now. Do you plan to take another pressure test soon of that? Or .... MR. MAY: Yes, sir, we do. We have taken one in April with similar results, ...... MR. SMITH: I see. MR. MAY: .... , which was not included on .there. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W 3RD AVENUE. 272 7515 10 11 14 15 17 18 19 -67- MR. SMITH: Was it, the one in April, still lower MR. MAY: Still lower. We -- we plan to continually moni- -- monitor the aquifer ..... MR. SMITH: Yeah. MR. MAY: ..... as we -- as we've .... MR. SMITH: So it ..... MR. MAY: ..... done in the past. MR. SMITH: ..... so it is reaching its limits, and it is affecting that reservoir, but it still will be adequate for your purposes as your plans go, is that ..... ? MR. MAY: Yes, sir, should it. It -- it's ~sseing some boundary at -- at some point in the reservoir. We don't know which direction. MR, SMITH: Robert, I got a little bit confused, and it's probably because it -- even though I've read through it briefly, it -- it -- we've gone through it so fast here. But on your exhibit there of the water analysis, which one was that? Is it 68? MR. MORKUM: No, 69. MR. SMITH: Sixty-nine. What's the difference between what you've called -- labelled there the reservoir water and the produced water? MR. MAY: Actually the difference -- the reservoil water is testing of A sand water in the -- in the -- in the field where we saw a well below oil/water contact. The produced water R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W, 3RD AVENL.IE 277-0572 · 277-0573 2-/7-8543 ANCHORAGE, ALASKA 99501 100'7 W. 3RD AVENUE 2727515 10 11 19. 14 18 19 -68- is essentially right now recycled source water or Upper Ugnu water as it's -- as -- after it has contacted the reservoir. MR. SMITH: Okay. On page 47 in referring to the possibility of evacuating the lines util- -- using pigs driven by natural gas, it -- if that should occur and -- and need to be done, would that gas then -- what would you do with the gas? How would that -- could it be saved, or would it be necessary to vent it? MR. BRANDSTETTER: The gas would then be vented. It's -- it is a very small volume from a throughput standpoint. We're talking -- I forget the -- the nature of the volumes. It's something on the order of three to five million cubic feet through a warm-up and freeze protection cycle per trunk. MR. SMITH: And then the second question on that same last sentence there, why is it necessary to use gas to heat that line when you're -- in the first part of the paragraph there you have -- you're heating the -- you heat the seawater to 60°? MR. BRANDSTETTER: The assumption here being that following a line displacement, the line would sit idle and reach ambient conditions. So prior to being able to introduce water into the system again, it would have to be brought up above the freezing point of water, so you introduce the heated gas to bring it up to that level before reintroducing the water. MR. SMITH: And again any gas you use to do that with would be -- have to be vented? R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1OO'7 W 3RD AVE. NLIE ,:.7.. 7515 tO t9 -69- MR. BRANDSTETTER: Would be vented, correct. MR. SMITH: When you evacuated the -- the water? MR. BRANDSTETTER: That's correct. MR. SMITH: Well, I think 'that's all of mine, Cha' MR. CHATTERTON: Okay. Thank you, Lonnie. Thank you, gentlemen. Harry, do you have any questions? MR. KUGLER: I have no questions. MR. CHATTERTON: Okay. We can probably -- I'd -- I'd like to take a moment and discuss a couple of things here, Steve. Steve Williams. The -- you -- you have made three special requests in addition to approval of the expansion of the waterflood to a field-wide situation. One is obvious, that the effective date be established so that your plans for this summer can be implemented, and that's no problem whatsoever -- whatso- ever, when we -- we'll approve this and you can get on with the program whenever you start. One unique thing to me is -- is your request of a water- flood permit area. And you're specifically requesting that the Commission retain administrative flexibility to change your requested established waterflood.permit boundary as -- and -- and make changes administratively as we collectively see fit. My specific question is why would the -- is -- is the reason that you want a waterflood permit area rather than just say the unit boundary because you suspect the unit boundary might contract at some time? To -- to me, you can waterflood inside the unit 810 N STREET, SUITE101 277-0572'277-0573 R 84 R COURT REPORTERS 509 w, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3FRD AVENUE 272 7515 10 14 16 18 19 20 -70- boundary any time you want. MR. WILLIAMS: I think there were -- there were two basis for that, Mr. Chairman, and I think Steve Suellentrop can add on to this. We selected the -- the waterflood permit boundary as corresponding to the -- to the Kuparuk participating area boundary, ..... MR. CHATTERTON: I -- I recall. MR. WILLIAMS: ..... as you noted. Extending beyond the Kuparuk participating area boundary by governmental sections of land where a portion of the tract was included within the Kuparuk participating area. And in addition as -- as Steve Suellentrop noted, ADL 28242, which is a tract owned by ARCO and Exxon which will be coming into the Kuparuk participating area in the near future. The Kuparuk participating area is the area that is presently planned for development by the KUparuk River ~rking interest owners. That area may expand or contract subject to approval by the Department of Natural Resources upon application to them. We felt that if we exceeded that area that that may show that we were expanding beyond the Kuparuk participating area boundaries, and it was not our intent to confuse either other working interest owners or the -- the Commission or the Department of Natural Resources. We specifically asked for administrative expansion of the waterflood permit boundary to correspond to the -- to the participating area to alleviate any problems that -- that occur down the road when R & R COURT REPORTERS 810 N STREET, SUITE: 101 .509 W. 3RD AVENUE 277-0572 - 277"0573 2'77-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVENUE 2727515 10 11 14 16 17 18 19 20 -71- the participating area expanded. We felt that we could come to you, show you the expansion of the participating area, show you what we intended to do for -- for waterflood purposes in -- in continuing on under our full field plan, and how this area would be affected by waterflood. MR. CHATTERTON: Fine. Fine. Okay. We -- we all recognize the fact that the perimeter if you like of a water- flood permit area should extend beyond -- to give you the flexi- m expend -- extend beyond your developed area to give you the flexibility if you wish for peripheral ..... MR. WILLIAMS: Um-hm. MR. CHATTERTON: ..... water drive, if that ever came to be desired. Okay. Fine. The effective date was spoken to. The waterflood permit vis-a-vis special requests. Well spacing we have taken care of. That will require an amendment to Conservation Order Number 173. You have requested that there be no further surveillance requirements than what's established in 173. On that point, 173 -- Conservation Order 173 did not address waterflooding in any form or faShion as you will recall. They were basically field rules. Our approval your Increment One waterflooding was accomplished by a letter of February 8th, 1982, and in that letter of approval, why, there -- there were two stipulations. And we will adhere to those stipulations. The first one I shall read. "The Commission will require semi-annual reports on R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W, 3RD AVENUE 277-0572 - 277-0573 2'77-8543 ANCHORAGE. ALASKA 99501 1007 W 3RD AVENLJE: 2727515 10 11 13 14 16 17 18 -72- implementation, progress and injection well performance during Increment One waterflooding." We'll expand it to the entire field. We've proposed to. We will consider it, is a better, safer.word. And the next is that ~any proposed changes must be -- from your plan must be committed -- submitted to -- and beyond what has been testified to here in this public hearing as to your plans would be submitted to the Commission for approval on down the road. And then the third thing that we impose, which is always nice, is that if we find it necessary in our judgment to impose additional stipulation, why, we'd like to have the freedom to do that. And particularly why I think this is important at this point in -- in time that we have that flexibility is we're sitting right on top of the potential of the State of Alaska taking over the impremisy (ph) for underground injection control for class two wells. And if we do apply for and do have approval to do that, I am fearful that there may be some surveillance requirements that neither thee nor thou can think of right now, so we would like to have the latitude to impose that. Now, did -- my question immediately is, does this -- do you think this imposes any hardship on you if we proceed with this type of stipulations? One, use identically the same ones we had in our February 8th, '82? MR. WILLIAMS: Mr. -- Mr. Chairman, maybe I'll -- R & R COURT REPORTERS 81o N STREET, SUITE 101 509 W, 3RD AVENUE 277-05'72 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 100'7 W 3RD AVENUE 272 7515 10 11 ]4 15 16 17 18 -73- I'll respond first and -- and the rest of the panel can add onto it. The -- the -- I don't think there would be any problems with the semi-annual reports. I think we intend on doing that anyway and have under Increment One and -- and would expect that to continue on. In addition, we understand as the Commission perceives taking over underground injection control responsibilit and the additional federal requirements that may be added as a result of that, we understand that we may be faced with those also and could see the need for that. With regard to the second suggestion on proposed changes in the plan before they take place to be submitted to the Commission, I take it that would be changes in the plan to make those less restrictive then and not the additional work that the operator may be doing, is that correct? MR. CHATTERTON: Correct. Correct. MR. WILLIAMS: I think that those will be acceptable. MR. CHATTERTON: Ail right. Fine. Thank you very much. I've got a couple of more. No, I don't know whether -- one thing that struck me -- oh, first of all, and I guess, Robert, this goes to you. What -- I think you have it here, but I missed it. What's the time schedule on when you think you will be replacing the Ugnu source water with Simpson Lagoon water? MR. MAY: Essentially on start up of the increment -- or of the fullfield waterflood. Somewhere around R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 27?.8543 ANCHORAGE, ALASKA 99501 100'7 W. 3RD AVEINUE 272'75]5 10 11 14 16 17 18 19 -74- January of 1986. MR. CHATTERTON: January '86, okay. Interim period 'til then, why, you'll have to continue the use of the Ugnu source water? MR. MAY: Yes, sir. MR. CHATTERTON: Okay. Seeing the need for and the potential for even more exotic downhole jewelry or completion techniques, whatever you want to call it, I am surprised that You have not asked us to amend -- amend Conservation Order 173 in its requirement for subsurface shut-in safety valves. It seems to me that that could be -- they could be giving you problems. Would you care to comment on that? MR. MAY: Well, we have -- we have not approached you. There has been -- there has not been a consensus within the unit on the use of subsurface safety valves, so we -- until that consensus is reached within the unit for them, we felt that it's -- we feel it's inappropriate really to -- to -- to comment on them. MR. CHATTERTON: The Commission has considered this and, in fact, is beginning to believe it's more hazardous to have them in than not to have them in, because of the wireline %Drk that you're having to do and everything else. And I guess what I'm wondering is, would you like to hold the record open on this hearing beyond the close of today's festivities to address that point? R & R COURT REPORTERS 810 N S'T'REET. SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE. ALASKA 99501 1007 W 3RD ,AVENUE: 272' 7515 10 11 13 14 16 17 18 19 20 -75- MR. WILLIAMS: I think, Mr. Chairman, we would prefer that -- that unless additional questions that require a response come up today, that we would prefer that the -- the hearing record be closed. We have, as Robert noted in the past, have an on-going dialog on subsurface safety valves within -- with the other owners. I suspect that we will have another dialog now and that as a result of that may be coming to the Commission requesting administrative release as a result of that. MR. CHATTERTON: You -- you would prefer to -- to have it as ..... MR. WILLIAMS: As a separate ..... MR. CHATTERTON: ..... as a separate issue? MR. WILLIAMS: ...... peti- -- as a separate petition, ..... Commission. MR. CHATTERTON: Ail right. MR. WILLIAMS: ..... yes, Mr. Chairman, if that's MR. CHATTERTON: We ...... MR. WILLIAMS: ..... that's acceptable to the MR. CHATTERTON: Ail right. Do you have any objection to closing this hearing -- closing ..... MR. WILLIAMS: Not -- not unless ...... MR. CHATTERTON: ...... the record at the close R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 277-0572 - 2'77-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W 3RD AVENUE 272.7515 10 11 13 18 19 20 -76- MR. WILLIAMS: ...... something comes up in your questions that -- that requires additional data, no, Mr. Chairman. MR. CHATTERTON: Thank you. That covers every- thing that I had. Back to the Commissioners. Any ..... ? MR. KUGLER: Nothing further. MR. CHATTERTON: Anything further to become -- to come before us? If not, we'll call this formal closed and we will close the record as of now. The time is approximately 11:12 a.m. Thank you, one and everyone. END OF PROCEEDINGS 810 N STREET, SUITE 101 277-0572 - 277-0573 R 8: R COURT REPORTERS 509 w. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W 3RD AVENUE 272 7515 10 11 14 16 17 18 19 CERTIFICATE UNITED STATES OF AMERICA STATE OF ALASKA I, Meredith L. Downing, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and electronic reporter for R & R Court Reporters, Inc., do hereby certify: That the anneXed and foregoing transcript of formal hearing was taken before me on the 23rd day of May, 1984, beginning at the hour of 9:00 A.M. at the Assembly Chambers, Greater Anchorage Area Borough, 3550 East Tudor Road, Anchorage, Alaska, pursuant to notice. That the witnesses before giving their testimony were sworn to tell the truth, the whole truth and nothing but the truth. That this transcript as heretofore annexed is a true and correct transcription of the testimony, taken by me elec- tronically and thereafter transcribed by me. That the original has been retained by me for the purpose of filing the same with the Alaska Oil and Gas Conservation Commission. I am not a relative or employee or attorney or counsel of any of the parties, nor am I financially interested in this action. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 11th day of June, 1984. SEAL Notary Public in and for Alaska My Commission expires: 5/3/86 R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 100'7 W. 3RD AVENUE 2727515 II III IV VI VII VIII KUPARUK RIVER FIELD FULLFIELD WATERFLOOD PROJECT APPLICATION FOR ADDITIONAL RECOVERY MAY 23, 1984 INTRODUCTION PROJECT OVERVIEW History of Kuparuk Unit Development Schedule Application for Additional Recovery GEOLOGIC DESCRIPTION Fullfield Structure Fullfield Stratigraphy Increment I Geology INCREMENT I WATERFLOOD PERFORMANCE Increment I Object ives Drill Site 1E Drill Site lA Directional Permeability Tests FI ELD WATERFLOOD OPERATIONS Surveillance Process Completion FULLFIELD WATERFLOOD PERFORMANCE Performance Prediction Methodology Performance Pattern Selection WATERFLOOD FACILITIES Intake Structure Seawater Treatment Plant Distribution Lines Local Injection Plant Drill Site Distribution System SUMMARY Special Requests May 23, 1984 BEFORE THE ALASKA OIL AND GAS CONSERVATION COMMISSION KUPARUK RIVER FIELD FULLFIELD WATERFLOOD PRO3ECT TESTIMONY FOR APPLICATION FOR ADDITIONAL RECOVERY BP Alaska Exploration Inc. (BPAE), w.ith approx.i,mately 28 percent .interest ,i..n the Kuparuk River Un.it, .i.s a sign.ificant working .interest owner. S.i,nce before unJ. tJ.zat,ion BPAE has been working actively with the Un.i,t Operator and other partners J,n the plann_i, ng of development and operat.ions for the f.ield. BPAE bel~i, eves that the performance to date of the Increment I Pilot Waterflood demonstrates the potent.i, al benefits to be ga.i,ned by the proposed FullfJ. eld Waterflood Project. Our own studies support those prov.i,ded by Arco Alaska Inc. (Arco) J,n its testimony and lead to the conclus.ion that waterflood of the Kuparuk River reservoir w.ill recover three times the quant.ity of o.i,1 that would be produced under natural depletion. BPAE, w,i. th other partners, has assJ.sted Arco J..n preparing the testJ,mony presented by them to the Commiss.i,on today and fully endorses the appl.i, cat.ion for the Kuparuk River Field Fullf.ield Waterflood Project. In add.i.t.ion BPAE jo.ins Arco in mak.i, ng the accompany..i, ng three special requests. We thank the CommJ.ss.i,on for this opportunity to submit testimony in support of this applJ,cation. 3ohn R. Grundon' President BP Alaska Exploration Inc. KUPARUK RIVER FIELD FULLFIELD WATERFLOOD PROJECT TESTIMONY FOR APPLICATION FOR ADDITIONAL RECOVERY May 23, 1984 TABLE OF CONTENTS Part I - Part II - Part III - Part IV - Part V - Part VI - Part VII - Part VIII - Part IX - Ov erv i ew Introduction Geologic Description of the Kuparuk River Field Increment I Waterflood Performance Field Waterflood Operations Fullfield Waterflood Performance Source Waters Waterflood Facilities S umm ar y PAGE 1 3 8 14 24 31 41 45 49 Part II - Part III - Part IV - EXHIBITS Description I ntroduct i on 1 Kuparuk River Unit Location 2 History of Unit Operations 3 Field Development, Year End 1983 Status 4 Field Development, Year End 1984 Status 5 Field Development, Year End 1985 Status .. 6 Field Development, Year End 1986 Status 7 Field Development, Year End 1987 Status 8 Field Development, Year End 1988 Status 9 Speci al Requests 10 Boundary Designations, Kuparuk River Field 11 Agenda of Testimony Geologic Description 12 Fullfield Structure Map 13 Fullfield Structural Cross-Section, East to West 14 Fullfield Fault Pattern, Kuparuk River Formation 15 Stratigraphy, Kuparuk River Formation 16 C Sand Areal Distribution 17 C Sand Cross-Section 18 A Sand Cross-Section 19 A Sand Areal Distribution 20 Location, Drill Sites lA and 1E within Fullfield F au 1 t Pattern 21 Dril 1 Site lA, Structure Map 22 Drill Site 1E, Structure Map Increment I Waterflood Performance 23 Increment I Waterflood Goals 24 Location, Drill Site 1E 25 Drill Site 1E, Waterflood Patterns 26 Drill Site 1E, Wells with Water Breakthrough, High GOR 27 Drill Site 1E, Performance 28. Drill Site 1E, Injection Profile, A and C Sand Injectors 29 Drill Site 1E, Confirmed Tracer Detections 30 Drill Site 1E, Pattern 1E-12 Performance 31 Location, Drill Site lA 32 Drill Site lA, Waterflood Patterns 33 Dri 11 Site lA, Performance 34 Drill Site lA, Wells with Water Breakthrough, High GOR 35 Drill Site lA, Well 1A-8 Performance 36 Drill Site lA, Injection Profile 37 Locations, Directional Permeability Test 38 Increment I Waterflood Results Exhibits Continued Part V Part VI Part VII - Field Waterflood Operations 39 Tracer Program, Tagged Injection Wells 40 Producing Wells, Days to Tracer Detections 41 Locations, Confirmed Tracer Detections 42 Profile Logging, Number of Wel 1 s 43 Bottomhole Pressure Monitoring, Number of Wells 44 Schematic, Single Completion 45 Schematic, Selective Single Completion 46 Specifications, Current Single Completion 47 Specifications, Selective Single Completion Fullfield Waterflood Performance 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 Pattern Model, Reservoir Description, A and C Sand Pattern Model, Performance, A and C Sand Pattern Model, Reservoir Description, A Sand Pattern Model, PerformanCe, A Sand Prediction Method for Drill Site Performance Fullfield Oil Production Rate, Waterflood vs. Natural Dep 1 et i on Fullfield Cumulative. Oil Production, Waterflood vs. Natural Depl eti on Fullfield Cumulative Solution Gas Production, Waterflood vs. Natural Depletion Fullfield Water Rates Direct Line Drive, 320-Acre Waterflood Pattern Infill Drilled, 160-Acre Waterflood Pattern Staggered Line Drive, 320-Acre Waterflood Pattern Five Spot, 320-Acre Waterflood Pattern Infill Drilled, 160-Acre and 80-Acre Waterflood Patterns Infill Drilling between Sealing Faults, Drill Site lA Well Count per Year, 160-Acre Well Spacing, Waterflood Development Source Waters 64 Location, Upper Ugnu Water Source Wells 65 Water Source Wells, Production History 66 Water Source Well Number 6, Log Traces 67 Water Source Well Number 1, Calculated vs. Actual Pressure Data 68 Produced Water History 69 Water Analyses Exhibits Continued Part VIII - Waterflood Facilities 70 Fullfield Water Facilities, System Overview 71 Site Plan at Oliktok Point 72 Schematic, Intake System 73 Schematic, Seawater Treatment Plant 74 Low Pressure Distribution Pipeline 75 Schematic, Local Injection Plant 76 High Pressure Waterflood Flowlines PART I - OVERVIEW TESTIMONY BEFORE THE ALASKA OIL AND GAS CONSERVATION COMMISSION ON KUPARUK RIVER FIELD FULLFIELD WATERFLOOD PROJECT Mr. Chairman, Members of the Commission, ladies and gentlemen, my name is Stephen M. Williams, and I am an attorney with ARCO Alaska, Inc. (ARCO), Unit Operator for the Kuparuk River Unit. The Kuparuk River Unit Working Interest Owners have requested this public hearing before the Alaska Oil and Gas Conservation Commission (Commission) for approval of an application for additional recovery through the im- plementation of a fullfield waterflood project. The application for additional recovery was filed with the Commission on March 23, 1984. The application contained the documentation required by 20 AAC 25.400, and was transmitted to all interested leaseholders within and adjacent to the Kuparuk River Unit. We request that the documents, including the Kuparuk River Field Fullfield Waterflood Project Application, along with the affidaNit and supporting documentation, be entered as part of the public record at this time. Several ARCO representatives will present testimony today on behalf of the Kuparuk River Unit Working Interest Owners. The testimony will discuss the criteria specifically required by the Commission regulation, and show how this project meets those criteria, promotes conservation, prevents waste, and increases recovery from the Kuparuk River Oil Pool. Our intent today Page 2 is to emphasize and discuss the items which we feel are the most important in implementing this project, and provide a forum from which the Commission may ask questions on project specifics. The following individuals 'will testify today- S. G. Suellentrop, W. D. Masterson, R. S. May, L. K. Blacker, and J. R. Brandstetter. At the end of the testimony, the witnesses would like to form a panel to respond to anY of the Commission's questions. The testimony has been prefiled, and each of the witnesses has included in that testimony, a statement of their respective qualifications. At this time, I would request that the Com- mission swear-in each of the witnesses. (After the witnesses have been sworn in.) We will begin our testimony today with Steve Suellentrop of ARCO Alaska, Inc., who will provide an introduction and overview of today's testimony. i, Page 3 PART II - INTRODUCTION Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Steve Suellentrop. I have received a Bachelor of Science and Master of Science Degree in Petroleum Engineering from the University of Missouri- Rolla. I have worked for nine years in varying aspects of reservoir engineering. The last four years have been spent in Alaska. I am pres'ently a Regional Reservoir Engineer for ARCO Alaska, Inc. I am responsible for all reservoir engineering studies relating to the Kuparuk River Field. I will make some introductory remarks for the technical presentations that will follow, review the schedule currently envisioned for fullfield water- flood development, and discuss the special requests that accompany the Application for Additional Recovery. The Kuparuk River Field is located in the North Slope Borough of Alaska as shown on Exhibit 1. The Kuparuk River Reservoir was discovered in April of 1969, with the drilling of Ugnu State No. I by British Petroleum and Sinclair Oil Companies. In the eleven year period between 1969 and 1980, more than 25 delineation wells were drilled by ARCO, B. P. Alaska Ex-~ ploration Inc., and Sohio Alaska Petroleum Company. In late 1980, ARCO requested that the Commission consider field rules for the development of the Kuparuk River Field as shown on Exhibit 2. These field rules were approved on May 6, 1981, as Conservation Order No. 173. On December 1, 1981, the Kuparuk River Field was unitized to prevent waste and to protect the correlative rights of the Working Interest Owners. The Kuparuk River Unit Agreement and the initial Plan of Development were approved by the Commissioner of the Department of Natural Resources. Further delineation and development drilling over the years has given a current estimate of oil in place in the Kuparuk River Field of 5.4 billion stock tank barrels. The Kuparuk River Field is a solution gas drive reservoir with no primary gas cap. Primary recovery of oil is through pressure depletion. Secondary recovery through waterflood is expected to~ yield an incremental 1.04 billion stock tank barrels of oil or nearly 19.5 percent of the original oil in place. This is expected to bring total field recovery to 1.6 billion stock tank barrels of oil. The Kuparuk Owners previously requested and received approval of an Application for Additional Recovery on February 8, 1982, to operate a pilot waterflood project in a limited portion of the Kuparuk River Field. The purpose of this pilot, called Increment I, was to optimize recovery and reduce the risks associated with a fullfield waterflood project. Water injection into the two drill sites involved in Increment I began in early 1983 as shown on Exhibit 3. During 1983, the three drill sites to the east and north of Increment I were used for gas injection. During the same period, the seven remaining drill sites were produced by natural depletion to Central Production Facility No. 1, or CPF-1. I would now like to provide a brief overview of field development. Upon approval of this fullfield application, waterflood operations will be expanded this year to Drill Sites 1F and 1G which are adjacent to Increment Page 5 {i' {' I as shown on Exhibit 4. Waterflood of these two drill sites will reduce their pressure decline, and solution gas production. The lowering of gas-oil ratios in these areas should allow more oil to be processed throUgh CPF-1. Central Production Facility No. 2, or CPF-2, will be operational in late 1984, and will process oil from drill sites in the southwestern portion of the Kuparuk River Field. Drill Site 2V in the CPF-2 area will be used initially for gas injection. As shown on Exhibit 5, during 1985 waterflood will continue on Drill Sites lA, 1E, 1F and 1G. No new drill sites will be waterflooded. Five ad- ditional drill sites will be brought on production, three to CPF-1 and two to CPF-2. In 1986 the second increment of this waterflood will begin as shown on Exhibit 6. Source water from the Beaufort Sea will be treated, and de- livered to the Local Injection Plants at CPF-1 and CPF-2. By year end, a total of eighteen drill sites will be waterflooded. CPF-3 is scheduled to start-up in early 1987, as shown on Exhibit 7. The CPF-3 facilities will include water injection facilities. Ten drill sites , in the CPF-3 area will be waterflooded before the end of that year. The majority of the drill sites within the Kuparuk River Field will be waterflooded by 1988 as shown on Exhibit 8. Ten drill sites in the CPF-1 and CPF-2 areas will be affected by injected gas and' will not be water- P age 6 flooded until the mid-1990's. Current waterflood development plans call for 160-acre development of the Kuparuk River Reservoir. As shown on Exhibit 9, three special requests are contained in this Application. First, we are asking for a minimum well spacing of 40-acres per well within the Waterflood Permit Boundary. Currently, Conservation Order No. 173 limits field development to 160 acre spacing. Imple- mentation of an efficient and effective waterflood may require closer well spacing in certain areas of the field. Forty-acre spacing should provide the optimum flexibility to enable implementation of the fullfield water- flood in the Kuparuk River Field. The second special request is that the effective date of this Application be the approval date by the Commission. This will allow the Kuparuk Owners to proceed with the 1984 waterflood plans to start water injection on two drill sites adjacent to Increment I. The third special request is that future modifications to the Waterflood Permit Boundary be approved administratively by the Commission to allow the Waterflood Boundary to coincide with or extend beyond the future boundary of the Kuparuk Participating Area. The requested Waterflood Permit Boundary is shown on Exhibit 10. As selected in this Application, the Waterflood Permit Boundary includes entire governmental sections when a portion of that section is included in the Kuparuk Participating Area. The Boundary also includes ADL 28242 owned by ARCO and Exxon Corporation, along the eastern side of the Kuparuk River Field. This tract will become part of the Kuparuk Participating Area in the near future. The selection of this Waterflood Permit Boundary reflects the intention of the Kuparuk Owners to effectively utilize the resources within the Kuparuk Reservoir. By providing a mechanism in the Order to administratively approve future boundary changes the Working Interest Owners will have the flexibility to optimize ultimate recovery from the Kuparuk River Oil Pool. I would like at this time to review the agenda of today's testimony as shown on Exhibit 11. Dallam Masterson will be presenting a description of the Kuparuk River Field geology; Laura Blacker will address the performance of Increment I Waterflood, and the implications of its results for future reservoir development; Robert May will present the operational aspects and surveillance of Increment I Waterflood Operations; I will then review the forecast for fullfield waterflood performance; Robert May will then review the source waters for use in fullfield waterflood; Joel Brandstetter will present the surface facilities that will be required to accomplish fullfield waterflood; and finally, I will summarize today's testimony. We will begin now our testimony with Dallam Masterson. Page 8 PART III - GEOLOGIC DESCRIPTION OF THE KUPARUK RIVER FIELD Mr. Chairman and members of the Commission, ladies and gentlemen, my name ! is D~allam Masterson and I am presenting geologic testimony on behalf of ARCO Alaska, Inc. I received a Master of Arts degree in geology from the University of Texas at Austin in 1981 and have been employed by ARCO as.a petroleum geologist since that time. I have spent the last two years studying the geology of the Kuparuk River Field and surrounding areas. My testimony will begin with a review of the structure and stratigraphy of the Kuparu.k River Field and will conclude with a review of the geology in the Increment I Waterflood area. The Kuparuk River Field is a combination structural ~and stratigraphic trap. The contour map of the top of the Kuparuk River Reservoir Structure shown in Exhibit 12 incorporates all non-confidential wells that were drilled prior to December 27, 1983. The depths shown are feet subsea. Note that faults have been omitted from this map in order to simplify the structure. On the west, the field is bounded by an erosional unconformity which truncates the Kuparuk reservoir rocks. The approximate position of this truncation is shown by a dashed, scalloped line. The southern extent of the field is delimited by decreasing reservoir quality in the Kuparuk sands.~' To the north and east the limits of the oil pool are determined by the intersection of' structural dip and the local oil-water contact. Page 9 {~' 'ii' Line C-C', a structural cross-section extending from west to east across the Kuparuk River Field, is shown on Exhibit 13. The depths shown on the left and right margins of the cross-section are feet subsea. Both geo- physiCal information 'and well control were used to construct the cross- section. At the eastern end of the cross-section, the Kuparuk River Formation intersects an oil-water contact which is at approximately -6560 feet subsea. The erosional surface which truncates the lower portion of the Kuparuk River Formation is represented with a heavy scalloped line. At the extreme western end of the cross-section, the unconformity has com- pletely removed the A and B Units of the Kuparuk River Formation. In some areas of the field such as Drill Site 1E the fault pattern is extremely compl ex. Exhibit 14 shows the distribution of faults which inter, sect the Kuparuk River Formation in the Waterflood Permit Area. These faults have been identified from well control and from geophysical information. Up to 300 feet of structural displacement is present along the faults. Two sets of faults are present, one set trending north-south and the other set trending northwest-southeast. Exhibit 15 summarizes the stratigraphy of the Kuparuk River Formation. The well log shown is 1A-13, which is a cored, water injection well in the Increment I Waterflood area. The Kuparuk River Formation is divided into an Upper and a Lower Member which are separated by an erosional uncon- formity. Unit D .is a siltstone unit and Unit B is a sequence of inter- bedded sandstone, siltstone and mudstone. The reservoir sands are found Page 10 (' { in the A and C Units, both of which are believed to have been deposited on a shallow marine shelf during Lower Cretaceous time. The C sands are quartzose, fine to coarse grained, poorly to moderately well sorted, bio- turbated, contain trace to abundant amounts of glauconite, and are often cemented by siderite, particularly in the C-4 and C-1 intervals. Naturally occurring fractures are observed in cores through the siderite-cemented C-4 and C-1 sands. Varying amounts of dispersed glauconitic clay, siderite cement, and fracturing cause wide variability in C sand porosity and per- meability. Exhibit 16 shows the distribution of Kuparuk C sandstone. The yellow coloring represents the approximate area with at least 10 feet of net C sand. The thickest accumulation of.C sand is in the CPF-1 area where the Increment I Waterflood is taking place. The C sand bodi'es pinch out into the CPF-2 and CPF'-3 development areas. The northwest trend of the C sands in the CPF-1 area is partially controlled by northwest-southeast trending faults which were active during deposition of the C interval. Stratigraphic cross-section A-A'is shown on Exhibit 17. The yellow colored areas on the cross-section are sand-rich zones within the C Unit. The lowermost sandstone, the C-1 sand, is thought t6 have been a trans- gressive marine sandstone which was desposited upon an eroded surface as the Cretaceous sea transgressed across the area. The C-1 sand can be locally discountinuous. The C-3/C-4 sandstone body is interpreted to 'have been an offshore marine bar which prograded out into deeper water to the northeast. The siderite cemented zones indicated in green, can be widely or only locally distributed. Thickened C and B intervals are often present on the downthrown sides of northwest-southeast trending faults. The Kuparuk A sands are more widespread than the C sands and will provide most of the production in the CPF-2 and CPF-3 areas. The A sands are quartzose, very fine to fine grained, and well sorted. The A Unit can be divided into at least six sandstone and mudstone packages which prograded towards the southeast, creating an imbricate stack of stratigraphically separated sandstone intervals. The progradational nature of the A sands is illustrated by stratigraphic'cross-section B-B', which is shown on Exhibit 18. The line of cross-section extends from northeast to southwest across the Kuparuk River Field. Sand-rich zones within each interval are colored in orange. Exhibit 19 shows the areal distribution of Kuparuk A sand intervals which have more than 10 feet of net sand. Note the location of cross-section B-B', which I showed you in Exhibit 18. The A sandstone bodies are elongated in a northeast-southwest direction and are truncated by the erosional unconformity at the western edge of the Kuparuk River Field. Because of the progradational nature of the A sands, pay zones overlap vertically in some areas of the field, and these areas are shown with darker tint. The interbedded sandstones, si ltstones, and mudstones of the A Unit are believed to have been deposited during storms on a shallow mari ne shelf. Page 12 I will now review the geology of the Increment I Waterflood area. Increment I is located in a complexly faulted area along the north-eastern flank of the field's structural closure. The location of Drill Sites lA and 1E is shown on Exhibit 20. Exhibit 21 is a structure contour map of the top of the Kuparuk River Formation at Drill Site lA. The depths are feet subsea, and faults are shown in red. Faulting in the Drill Site lA area has been defined by seismic mapping and well control. Reservoir rock is juxtaposed against non-reservoir rock across some of the larger faults, forming a local barrier to fluid movement. The portions of faults which are believed to act as barriers to fluid flow are cross-hatched. Reservoir quality sand at Drill Site lA occurs predominantly in the A-4, C-4, C-3 and C-I intervals and, to a lesser extent, in the A-3 and A-5 intervals. Exhibit 22, shows a structure contour map of the top of the Kuparuk River Formation at Drill Site 1E. Faults are colored red, and the depths are feet subsea. The one fault which is thought to act as a barrier to fluid flow is cross-hatched. Reservoir quality rock is found in the C-3, C-4, A-4 and A-5 intervals at Drill site 1E. Reservoir sands are also present in the C-1 interval in some Drill Site 1E wells. Page 13 < ( Natural fractures are common in the siderite-cemented C-1 and C-4 in- tervals at Drill Sites lA and 1E. The orientation of the fractures is thought to be parallel to the north-south trending fault system. The north-south trending faults and fractures are believed to have developed after deposition and cementation of the Kuparuk River Formation. In summary, the Kuparuk River Formation is divided into two reservoir zones with differing rock properties. The C Unit is characterized by gl auconite, siderite cement, and natural fractures in the C-1 and C-4 intervals. Thick accumulations of C sand are present at CPF-1 and to a lesser extent, at CPF-2. A regional erosional unconformity at the base 'of the C-1 interval seRarates the C Unit from the underlying A and B Units. The A sands differ from the C sands in grain size, grain composition, sorting, and depo- sitional history. Fractures are not common in.the A intervals. This concludes the geologic portion of the testimony. The following testimony by Laura Blacker will review the Increment I Waterflood performance. PART IV -'INCREMENT I WATERFLOOD PERFORMANCE .' Mr. Chairman and members of the Commission, l'adies and gentlemen, my name is Laura Blacker. I received a Bachelor of Science Degree in Chemical Engineering from Tulane University in 1976. I have been employed in the oil and gas industry since my graduation and by ARCO Alaska since November of 1980. Since that time, I have worked as both an Operations and Reservoir Engineer in the Kuparuk Engineering group. I am currently an Area Reservoir Engineer in charge of waterflood studies. My testimony will begin with a review of the objectives of the Increment I Waterflood. This project was started up as a pilot waterflood in early 1983. As shown on Exhibit 23, the overall goal was to optimize the recovery and reduce the risk associated with fullfield waterflood. In addition, specific objectives were to obtain reservoir information that would be used to attain this goal. The first of these was to determine reservoir properties which affect injectivity. The second objective was to determine reservoir properties affecting sweep. The third objective was to determine optimum well spacing, and lastly to obtain an estimate of ultimate recovery from waterflood. page 15 i' ~' As I present the Increment I performance in detail, I will review the information obtained from this pilot waterflood and how it relates to these specific objectives. I will review the performance of the two drill sites, One at a time, beginning with Drill Site 1E. E~hibit 24 shows the location of Drill Site 1E. It is located in the CPF-1 area and is one of' the five original Phase I drill sites in the Kuparuk.River Field. This drill site is located directly south of Drill Site lB, which has been used as a gas injection drill site since February of 1982. As you will see later, the performance of Drill Site 1E has been impacted by gas injection. Exhibit 25 shows the location of the patterns on Drill Site 1E. On the east side of the drill site, there are four 160-acre five spot patterns. The wells are drilled to 80-acre spacing in these patterns with the producer spacing at 160-acres. On the west side of the drill site are four 80-acre five spot patterns. Wells in 'these patterns are drilled to 40-acre spacing. One of these patterns, the one surrounding well 1E-12, is an A sand only pattern. The remaining patterns contain wells completed in both the A and C sands, in which injection and production are comingled. Currently, nine wells on Drill Site 1E have water breakthrough. Exhibit 26 shows the wells in which water breakthrough has occurred and in addition shows the wells which are shut-in due to high GOR. Water breakthrough has occurred in all but one of the ten active wells completed in the C sand. Seven wells are shut-in due to high GoR, these wells have all been impacted by injected gas from Drill Site lB. Injected gas migrated into Page 16 Drill Site 1E before the start of Increment I and most of the wells which are currently shut-in for high GOR were shut-in prior to the start of waterflood. The performance of Drill Site 1E under waterflood can best be described .by referring to a plot of rates vs time shown on Exhibit 27. I have shown on this plot, oil rate, GOR, water injection rate, and produced water rate between 1982 and 1984, to show both primary and waterflood performance. The oil rate reached its maximum immediately before the start-up of Increment I, due to producing additional Wells which had been drilled as part of Increment I. The rate declined at the start of waterflood, due to con- version of wells to injection, and has continued to decline since that time primarily because of shutting in high GOR wells. The waterflood has not prevented the further migration of gas into the drill site. The impact of injected gas can be seen by looking at the GOR performance. This has continued to increase even though we have been waterflooding the drill site. The slight decline at the end of 1983, is due to shutting in additional high GOR wells. The water injection rate has been level at about 18,000 barrels of water per day since April, 1983 when all of the water injectors were placed on injection. The produced water rate, shown in green, increasedPrapidly after initial breakthrough in March of 1983. It reached a peak of about 2,000 barrels of water per day in October of 1983. The slight decline in recent months is due to shutting in wells which produce high water cuts because of water handling capacity of the facility. The water injection rate greatly exceeds the produced water rate on this drill site indicating that even though breakthrough has occurred the majority of the water is continuing to displace oil. However, much of the waterflood response has been obscurred due to the effects of injected gas. One of the objectives of the Increment I Waterflood was to determine reservoir properties which affect injectivity. To accomplish this, we have run a number of surveys in both injection wells and producing wells which Robert May will review in more detail later. I will show you 'the average injection profile on Drill Site 1E determined from these surveys. The graph on Exhibit 28 shows percent of injection by sand along the x-axis. The y-axis indicates the percent of the total reserves of each sand. As shown, 86% of the water we are injecting into Drill Site 1E is entering the C-4 sand which contains only 22% of the reserves on the drill site. Eleven percent(Il%) of the water is entering the C-3 sand which contains about 41% of the reserves. Only 3% of the water is entering the A sand which contains 37% of the reserves. This percentage does not include the water which is being injected into the A sand only pattern. Based on the in- jection profile, we have identified two factors which affect injectivity. The first is that a disproportionate share of the water is entering the C sands relative to the C sand reserves. The second is that within the C sand itself, the majority of the water is entering into the natur, ally fractured high permeability C-4 sand. I would like to review the water breakthrough on Drill Site 1E further. Exhibit 29~shows the wells in which water breakthrc~ugh has occurred and also indicates, by arrows, 'from which injection wells the water came. This water breakthrough has been confirmed by tracer data. The breakthrough in all of the wells with the exception of 1E-2 has come from an injector either directly north or south of the producing well. There has been no confirmed break, through in the east-west direction. As I mentioned earlier, most of the water injection has occurred in the naturally frac- tured, high permeability layers of the C sands. Most of the water breakthrough has also occurred in these layers. Because the confirmed breakthrough has all been in the north-south direction, we have concluded that the fractured intervals of the C sands have a strong north-south preferential fluid movement. This preferential fluid movement could be caused by matrix permeability, natural fractures, faulting or a combination of any of these. This trend will be referred to as directional per- meability in this review. Directional permeability is responsible for early breakthrough which has occurred both on Drill Site 1E and Drill Site lA. Additional data which I will discuss later confirms this directional permeabi 1 ity. Bec'ause of the nature of the C sand, waterflood response discussed so far has been dominated by C sand performance. The A sand has exhibited a much different response to waterflood as I will now show by reviewing the performance of the A sand only pattern centered around well 1E-12. ~s~- pa~t.ti~n~a~s~.~i~`~i~te~U~!~m~u~c~h~.~d~i%~f~e~e~r`esp~h.se~`~w~~)~~'. Exh i b i t 30 shows rates vs time for well 1E-12. There were little or no withdrawals Page 19 il.. from this well prior to the start of the waterflood, therefore, the GOR at the start of the flood was essentially solution GOR and has remained at this level throughout the waterflood. The oil rate has increased indi- cating waterflood response in this well. The injection rate has fallen off slightly, possibly due to pressuring up around the pattern area. No water breakthrough has been noted in this well to date, even though the well spacing is close, indicating that we can successfully waterflood the A sands of the Kuparuk River Reservoir. I will now review the performance of Drill Site lA. This drill site is also located in the CPF-1 area and is directly west of the gas injection Drill Site lB as shown on Exhibit 31o Drill Site lA, was not as affected by injected gas as Drill Site 1E was at the start of the waterflood. Therefore its response is considerably different from that of Drill Site 1E. Eight 320-acre five spot patterns are included on Drill Site lA as shown on Exhibit 32. These patterns are shown as extending outside the Drill Site lA boundary because some of the wells in offset drill sites have been impacted by the waterflood on Drill Site lA. The performance of Drill Site lA from January, 1982, to the present as shown on Exhibit 33, indicates a very positive response to the waterflood, especially in the GOR performance. During primary production from January 1982 until January 1983, the GOR increased as would be expected in a solution gas drive reservoir and reached a maximum of 1200 standard cubic feet per stock tank barrel. Since the start of waterflood, the GOR de- Page 20 (' { creased quite rapidly and has leveled off to about 650 standard cubic feet per stock tank barrel. The oil rate dropped sharply at the start of the Increment I Waterflood due to converting half of the wells on the drill site to water injection. Since that time it'has continued to decline slightly. This is not due to the lack of waterflood response, but rather to operational constraints. The water injection rate, shown as a blue line on this slide, has remained constant at abOut 30,000 barrels of water per day. Water breakthrough first occurred in June of 1983 about six months after the start of water injection. The produced water rate is currently about 2000 barrels of water per day. Water breakthrough occurred earlier than expected after the start of water injection considering the well spacing on this drill site. This is due to the north-south directional permeability in the C sands and the fact that we have five-spot patterns with injection wells directly north or south of the producing wells. Exhibit 34 shows the wells which have water breakthrough in the Drill Site lA area. All of the active wells on Drill Site lA have water breakthrough except Well 1A-8. Break- through has also occurred in two wells on Drill Site 1F which are offset to injection wells 1A-7 and 1A-11. The two producing wells on the east side of the drill site, are shut-in due to high'GOR from injected gas at Drill Site lB. Well 1A-8 which is shown on this exhibit and has not had water break- through. This well was originally drilled as one of the delineation wells in the Kuparuk River Field, and as such, was not drilled in a regular Page 21 pattern location on this drill site. Consequently, the well is not directly north or south of an injection well. Because of its unique location, the performance of this well merits discussion. During primary production throughout 1982, the oil rate declined approximately 35% per year as shown on Exhibit 35. The oil rate decline leveled off at the beginning of the Increment I Waterflood and the rate has since increased, indicating positive waterflood response. It is currently producing at over 90% of its initial rate. The GOR performance of this well is also interesting. It continued to increase after waterflood began then dropped off sharply, then increased again, eventually leveling off. Recently, it has again begun to decline. The fact that there are two peaks on the GOR curve could indicate that a gas bank from one of the sands appeared before the gas bank in another sand. The total performance of this well is indicative of what we can expect with a line drive pattern° 1A-8 performance indicates that by lining up the patterns correctly we should be able to successfully water- flood this reservoir even though the C sands have north-south directional permeabi 1 ity. Before concluding my discussion of the Drill Site lA performance, I would like to review the average injection profile of the drill site. Exhibit 36 shows that the fractured C-4 interval is taking 65% of the water and contains about 25% of the reserves. This drill site also contains a con- siderable amount of the C-1 Sand, which you Will recall, is a thin high permeability sand. Twenty-five percent of the injected water is entering this sand which contains about 10% of the reserves. The unfractured C-3 interval is taking only 6% of the water and contains about 30% of the Page 22 reserves. The A sand is taking only 4% of the water and contains 35% of the reserves. I would like to emphasize that the differences in the C sand injectivity is not as severe a problem as it may seem. The water injection rate into this drill site is 30,000 barrels of water per day contrasted with a produced water rate of only 2,000 barrels of water per day. This indicates that mOst of the water is displacing oilo This concludes my discussion of the waterflood performance of the two Increment I Drill Sites. As I mentioned earlier, we are collecting data in other parts of the field to help confirm or disprove some of the infor- mation obtained from the Increment I Waterflood. This data will be used to help plan the full field waterflood. I would like to review the dir- ectional permeability tests conducted on two CPF-2 drill sites shown on Exhibit 37. The two drill sites are 2X in which we conducted a C sand only directional permeability test, and Drill Site 2C, in which we conducted an A sand only directional permeability test. Analysis of the test on Drill Site 2X has shown that the C sand does indeed have a directional per- meability in the north-south direction five times the permeability in the east-west direction. The results of the A sand test on Drill Site 2C were somewhat surprising, since this test indicated that the A sand has a directional permeability in the east-west direction with a magnitude of 3:1. This result is suspect because the producing well, 2C-8 was partially faulted. This may have affected the results of the test. Since the 2C test did not provide conclusive results, we plan to conduct a second A sand only directional permeability test on Drill Site 2F beginning in late May. P age 23 In summary, the information which we have obtained from the Increment I Waterflood has proven to be very valuable in our planning for fullfield waterflood. As shown on Exhibit 38, many of the objectives of the pilot project have been accomplished to some degree. We have determined reser- voir properties affecting injectivity with our injection profiles. These include the strong preference of injection into the C sand over the A sand, and to a lesser degree, the high injectivity into the fractured intervals of the C sand. Reservoir properties affecting sweep are dom- inated by the north-south directional permeability of the C sand. In the near future, we hope to gain conclusive information concerning A sand directional permeability. We have also shown that waterflood response can be obtained from 320-acre patterns on Drill Site lA. We have not yet determined optimum well spacing, but have identified situations which could require infill drilling. The information obtained from Increment I has also provided a basis for predicting recovery using reservoir models. The results of these models will be discussed in the fullfield waterflood performance section of the testimony. As Robert May and Steve Suellentrop go through their testimony, you will see how.this information is actually being used in our fullfield waterflood planning. Robert May will now present the testimony on Field Waterflood Oper at ions. PART V - FIELD WATERFLOOD OPERATIONS Mr. Chairman and members of the Commission, my name is Robert May. I am Regional Operations Engineer for ARCO Alaska, Inc. and am responsible for all operations engineering studies and field surveillance programs for the Kuparuk River Field. I received my Bachelor of Science degree in Mechanical Engineering from Southern Methodist University in 1970 and..have been employed bY ARCO as an engineer since that time. I spent 12 years in the Gulf Coast area prior my assignment in Alaska and have now spent the last 2 years in engineering positions for ARCO in the Kuparuk River Field. I would like to first cover the extensive surveillance programs undertaken by the Kuparuk River Unit Working Interest Owners for Increment I Waterflood. Following this I will outline some of the actions already taken in well completion design as a result of this program, and some of the ongoing efforts to mitigate the intrasand imbalances shown in the previous testimony. .The surveillance program for Increment I Waterflood is made up of two parts. First, the radioactive tracer program and second, extensive production/injection logging and bottomhole pressure work. Laura Blacker has already outlined the objectives of this work. I will describe their implementation. The radioactive tracer program undertaken on Drill Site 1E has provided a great deal of useful data. The program is composed of two parts: tagging and sampling. Radioactive tracers were placed in nine Drill Site 1E injectors between May 19 and June 6, 1983. Exhibit 39 shows the location of the tagged wells. The sampling program began almost immediately and tritium was first identified in Well 1E-28 about 5 days after tagging Well 1E-30. The high confidence radioactive tracer results to-date are listed in Exhibit 40. Exhibit 41 shows the location of these wells. We have seen tracer breakthrough in more wells than those shown, however, the ones shown are the most reliable. Other tracer breakthroughs have been detected specifically Nickel-63, however, because of their lack of repeatability they have been excluded from this exhibit. Throughout the program samples have been taken once a week on each producing well on the drill site. Considerable data has been gathered since startup of Increment I Water- flood from various wireline activities including injection profiles, produCtion profiles, and various types of bottomhole pressure measure- ments. All of the efforts reviewed here are in addition to the requirements set forth in Conservation Order No. 173, and were undertaken in order to gain as much meaningful data as possible during Increment I without severely impacting our day-to-day operations. l. Exhibit 42 shows the the number of wells' in which injection profiles have been run. A total of 19 injection profiles were initially run in injection wells on Drill Sites lA and 1E. This data was needed to determine the relative injection volume by zone, the results of which were already reviewed. These logs indicated predominate C-4 and C-1 sand injection. Injection profiles were originally run in all injection wells with the exception of Well 1A-13. Well 1A-13 had a malfunctioning subsurface safety valve (SSSV) which prevented an initial log. However, the well was repaired and included in the second set of injection profiles run in October 1983. This subsequent set were run on selected injection wells to see if there had been any profile changes 5 to 7 months after the initial runs. Exhibit 42 shows that 6 wells were included in this second program. If profile changes occurred, the program would have been expanded to additional wells. However, the results were consistent with initial results and no additional logs were run. Also shown on Exhibit 42 is a compilation of the production profile logging during the Increment I surveillance program. A total of 14 wells had production profiles run. Again these logs were run in addition to those required by Conservation Order No. 173. The initial logs, run as a part of the State requirement, were used as the basis to compare with the logs listed in this exhibit. The production profile logs were reviewed for zones of water entry and any zones of increased contribution. All production logs were run after water breakthrough. In order to monitor water breakthrough on Drill Site 1E priority wells were identified and shakeouts were taken three times per week. On Drill Site lA, well Page 27 {' i' tests, taken approximately once per week, were used. On offsets to Drill Sites lA and 1E well tests were again used. The criteria for water break- through was a repeated 1% water cut. An attempt was made to run all production surveys when the well reached a 10-20% water cut environment to provide accurate results. The production logs have confirmed that water is being produced from the C-4 sands in wells on Drill Site 1E and the C-4 and C-1 sands in wells on Drill Site lA. Additionally, data was acquired on the capa- bilities of various production logging tools and combinations of tools to optimize our surveillance of multizone producers in deviated wel 1 bores. Exhibit 43 is a summation of the various pressure surveys run in con- junction with Increment I. Pressure data is useful for three reasons. One, it is required to check injection pattern balance. Two, it aids in identifying problem wells that require stimulation. Three, it provides a data base which will aid in describing reservoir performance under water- f 1 ood. The areas of concern in waterflooding the Kuparuk River Field as identified by our surveillance program were reviewed earlier. I would like to 'further review the intrasand and intersand profile imbalances and how they relate to existing and future completions in the field. Page 28 il ( Exhibit 44 is a schematic of the existing completions in the Increment I Waterflood area. The profile imbalances currently exist in commingled wellbores. These wells are typically characterized by high production or injection in the C sand, primarily C-4 and C-1 depending on the area of the field, and much lower rates in the A sand. Areas affected by injected gas typically ~have high GOR C sand production usually resulting in shut-in of the well and shut-in of the A sand. Because of these imbalances between the A and C sands, new wells in which both sands are present are evaluated for completion in the manner depicted in Exhibit 45. This selective single completion allows separate stimulation of the two different sands with techniques designed for only that sand. Currently the C sand is acidized when required and the A sand is fracture stimulated to increase producti.vity/injectivity. The completion also allows isolation of the C sand from the A sand. The isolation capability allows continued production from the A sand when GOR from the C sand dictate that the interval be shut-in. Additionally this type of com- pletion will allow us to regulate concurrent injection into the A and C sand through downhole devices. Intrasand profile imbalances within the 'C sand during water in- jection have also been discussed this morning. Typically when the C-4 and/or C-1 sand is present, injection is primarily into those sands. Tests are currently being conducted on Well 1E-30 in the Increment I area to determine if the dominant injection profile can be altered by combining P age 29 polymer with the injection water. The polymer is designed to reduce flow into the highly permeable zones diverting water to other zones. Early work in this area is incomplete but encouraging. I would like to now review the completion specifications for Kuparuk wells. Exhibit 46 is the completion specifications for a typical single com- pletion. Exhibit 47 is the completion specification for a typical selective single completion. Not all wells fit these specifications exactly. We continually endeavor to optimize wellheads and downhole equipment based on the expected long term service of the wells. Wells are designed in anticipation of acidizing and fracturing requirements and long term service as water injectors during waterflood operations. The 7 inch completion string is cemented in place with the cement top located about 800 feet above the top of the Kuparuk interval. This is sufficient isolation during production/injection or stimulation operations to prevent fluid migration to any strata above the Kuparuk River Reservoir. Additionally, as a further safety precaution we routinely monitor the casing/tubing annulus pressures. Summarizing this part of the testimony, we have diligently pursued the Increment I Waterflood from an operations surveillance standpoint and have gained valuable data which will help us more effectively produce and waterflood the field. Key emphasis has already been placed in providing mechanical separation of the A and C sands in order to allow selective production/injection and sti,mulation and we are evaluating chemical means for intrasand redistribution. Page 30 i' ~ The Working Interest Owners request that no surveillance require- ments be issued for this Waterflood Permit in addition to those currently included in Conservation Order No. 173. The Unit Operator will continue to aggressively pursue waterflood surveillance to provide suf- ficient quantities of data to maximize waterflood efficiency and oil recovery. Steve Suellentrop will continue today's testimony with a review of full- field waterflood performance. PART VI - FULLFIELD WATERFLOOD PERFORMANCE I will now review our projection of fullfield waterflood performance, and compare that with anticipated primary performance. Before I do that, however, I would like to take some time to tell you how these forecasts were developed. These projections are those of the Operator. Our method to predict field performance used an areal simulator in com- bination with more rigorous pattern modeling. The purpose of this combined procedure was to take advantage of the strengths of the areal simulator as well as mitigate its perceived weaknesses. The use of the areal simulator is appropriate in undeveloped sections of the field where there will be little primary production prior to waterflooding. The areal model however, is not effective in accurately projecting waterflood performance after extended primary production. Neither is it effective in determining the impact of injected gas on primary and secondary performance. Pattern models have been developed to determine waterflood performance in these cases. The fullfield simulator is coarsely gridded into 80-acre cells areally, and two layers, the A and C Sands, vertically. The reservoir description incorporates our best understanding of net pay, porosity and permeability P age 32 distribution throughout the field. It also includes our latest under- standing of oil water contacts, fluid distribution and fluid properties. Despite some of its needed simplifications due to its size, we feel that it adequately projects performance in the currently undeveloped sections of the field. Most drill sites in the CPF-3 area and the peripheral drill sites in the CPF-1 and CPF-2 areas have been forecast with our areal model. Two general reservoir descriptions have been used in the pattern models -one with the A and C sands present, and one with the A sand only. The A and C sand description reflects our understanding of the Increment I Water- flood results. The A and C sand model layout is depicted on Exhibit 48. This model has five layers - four layers for the C sand and one layer for all of the A sand. The top layer of the C-4 interval has a high horizontal permeability in the x-direction of 800 millidarcies (md) to model the natural fractures, and a higher permeability of 4000 md in the y-direction to reflect directional permeability. This C-4 interval has a net sand thickness of four feet and consequently the smallest volume of all the layers. The rest of the sand in the C-4 interval is unfractured and has a permeability of 80 millidarcies. The C-3 interval has the largest net sand thickness of twenty-five feet. The C-1 interval is isolated from the rest of the C sands and from the A sand. It has an x-direction horizontal permeability of 200 millidarcies and a y-direction horizontal permeability of 1000 millidarcies, similar to the directional permeability in the C-4 fractured interval. A single A sand layer of 35 feet and a permeability of 65 millidarcies was used in this pattern model. Page 33 { ~" Exhibit 49 shows a typical waterflood performance of the A antiC sand model with a direct line drive pattern. After the start of water injection, pressure begins to increase, and reaches initial reservoir pressure in five to six years. The pressure drop in this case is 675 psi and is as- / · sociated with approximately 4% primary recovery. Peak oil rate response is seen after 2 years of waterflood. Water breakthrough occurs almost 3 years after the start of water injection. The second pattern model used to evaluate waterflood response was one with only A sands present. As presented in the geologic description, the A sand intervals overlap areally, but usually onlY two are present at any loca- tion. The A-4 and A-3 sand intervals, separated by an impermeable shale zone, are present in the CPF-2 area. The pattern model reflects this reservoir description.. A five-layered pattern model contains two layers for the A sands with equal permeability and no directional permeability as shown in Exhibit 50 The top A- layer is thinner to allow faster fluid · \ movement. A thin upper layer was also used for the upper A~i~Sand. Layers 4 and 5 contain the rest of the A~ net sand, and have identical properties. Exhibit 51 shows the performance of this pattern' model with a five-spot water injection pattern. The injection and production rate curves show the same characteristics as the A and C sand model, however, because of the lower permeability in the A sand, the time to waterflood response is longer. G0R responds the quickest to waterflood, collapsing within two , Page 34 years to solution GOR. Peak oil response occurs after 4 years of waterflood. Water breakthrough occurs almost 6 years after the start of water injection. The impacts of gas injection and encroachment have also been determined independently in pattern models similar in description to the A Sand only pattern models. GOR performance on those drill sites where gas injection or encroachment is anticipated has been modified according to pattern model predictions. Exhibit 52 shows the drill sites used in the performance prediction , and indicates the type of treatment accorded to each drill site. The drill sites shown in red are those drill sites whose performances were predicted using the areal model. The drill sites shown in green are those drill sites whose performances were determined using the A and C sand pattern models. The A sand only drill sites are shown in blue. Each of these drill sites waterflood response was determined independently as a function of its anticipated primary production. Those drill sites which have had their GOR and oil rate performance modified due to gas injection are shown in yellow. Those drill sites which have had modified behaviour due to gas encroachment are striped. Oil, gas and water rates were totaled by drill site and modified by facility limit constraints to yield fullfield performance. Oil production was deferred on those drill sites impacted by gas injection when the facility gas handling capacity was reached. Page 35 {!1- ~,' The oil rate projected by this method is shown in Exhibit 53. It shows that the startup of CPF-2 in 1985 increases the fullfield'rate to 181,000 stock tank barrels per day. A reduction in the oil r'ate to 165,000 stock tank barrels per day in 1986 occurs with the conversion of wells to water injection service. CPF-3 will start up in.1987 and oil production should increase to 228,000 stock tank barrels per day. The peak oil rate should occur in 1988 at 250,000 stock tank barrels per day, as a result of waterflood response. After 1989, the oil rate begins its decline at about 7% per year to the year 2017. The field has a relatively shallow decline rate due to staging in the waterflood on the gas injection drill sites and the deferred response to waterflood on some drill sites due to gas en- croachment. For comparison, the oil production from the Kuparuk River Field under natural depletion is also shown. The depletion mechanism for this case is solution gas drive with some immiscible gas injection support. These rates were obtained solely from our areal model using the same development schedule as the waterflood case and are for 320-acre development within the participating area. This case also assumes that most of the solution gas is not reinjected. In 1985, the oil rate would reach 127,000 stock tank barrels per day with the start-up of CPF-2, and peak at 143,000 STB/D in 1987 following the start-up of CPF-3. After its peak, the rate declines at 17% per year, until the year 2012. P age 36 Cumulative oil production for both primary and secondary recoveries are shown on Exhibit 54. After 30 years, natural depletion would yield 560 million stock tank barrels. In comparison, waterflooding the Kuparuk River Field is expected to yield approximately 1.6 billion stock tank barrels of oil, or over 1.04 billion stock tank barrels attributable to water- flooding. Primary recovery, would be 10.5% of the oil in place while secondary recovery under waterflood is expected to be 30% of the oil in place. Exhibit 55 shows projected cumulative solution gas production from both the primary and secondary cases. Under natural depletion, cumulative gas production is nearly 1.5 trillion cubic feet by year 2012. In the waterflood caSe, the cumulative gas produced to year 2017 is nearly 910 billion cubic feet. Injected water will be comprised of source water from the Beaufort Sea, and cycled produced water. As shown on Exhibit 56, peak source water plant requirements will be from 1986 through 1989 at nearly 340,000 barrels of water per day. In future years the source water requirements will decline as fill up occurs and produced water is reinjected. Significant produced water first occurs in 1988 with. the water coming primarily from the CPF-1 area. The produced water rate rises over the life of the field, reaching a producing water-oil ratio of 7:1 by year 2017. Page 37 ~" (' Pattern selection throughout the Kuparuk River Field will be based on results from the Increment I Waterflood, the directional permeability tests, and field performance. Our present understanding of fluid pro- perties in the Kuparuk River Reservoir indicate a mobility ratio of sligh~tly less than unity. While this is favorable for waterflood ef- ficiency, it limits the waterflood patterns to those with a 1:1 producer-injector ratio. A special request has been made to allow infill drilling to 40-acre spacing. Approval. of this request will allow flexibity in determining ultimate pattern density. It also represents the density currentlY existing on the western half of Drill Site 1E. Exhibit 57 shows a direct line drive pattern with injectors and producers in north-south rows on regular 160-acre spacing. The 320-acre waterflood pattern is shown with a dashed line. This pattern is preferred in areas of A and C sand development where drill sites have already been drilled on 160-acre spacing. One advantage of this pattern is that it optimizes recovery where strong directional permeability exists in the C sand. Another advantage of the pattern is that it allows infill drilling of a symmetrical five-spot pattern aligned 45° off north-south as shown on Exhibit 58. Infill drilling in this manner will result in 80-acre regular spacing with 160-acre waterflood patterns shown with a dashed line. Exhibit 59 shows a staggered line drive on 160-acre spacing. This type of pattern can be effectively utilized in areas of A and C sand development where drilling to !60-acre regular locations has not been completed. This results in the 320-acre waterflood patterns outlined on Exhibit 59. One Page 38 ! ~(' advantage of this pattern is a slightly higher sweep efficiency at water breakthrough and a shorter time to peak response compared to the direct line drive pattern. Exhibit 60 shows a regular 160-acre five-spot pattern containing 320-acre waterflood patterns. This patter, n is targeted for use in areas of A sand only development depending on the outcome of the directional permeability test. This configuration has a shorter injector-producer distance allowing for the quickest peak response time. It also yields symmetrical infill drilling configurations. Shown on Exhibit 61 are both 80-acre and 40-acre regular spacing. The 80-acre.spacing shown in the northwest quadrant results in 160-acre waterflood patterns similar to the infill results of the direct line drive. The 40-acre regular spacing shown in the southwest quadrant results in 80-acre waterflood patterns. In addition to infill drilling on regular spacing, approval of 40-acre spacing also provides the flexibility to handle special situations shou.ld the need arise. Drill Site lA depicted on Exhibit 62 with its existing injector-producer configuration shown in black triangles and circles, respectively. Also shown are the sealing faults reviewed in the geologic description of this testimony. Shown in red triangles and circles on this diagram is one potential method of optimizing oil recovery within these sealing boundaries. The realization of this option would require infill Page 39 drilling on 40-acre regular spacing. This diagram is used only for illustrative purposes and does not represent any current planned develop- ment bY the Kuparuk Owners. Activity within, the Kuparuk River Field as the result of waterflood development is illustrated in Exhibit 63 which shows the number of production wells and the number of water injection wells at any year. Before 1986, drill sites involved with Increment I Waterflood and its possible expansion contain the only water injectors. After 1986, with the startup of fullfield waterflood, the number of water injectors is ap- proximately half of the total number of wells in the field. When initial development is complete, we expect approximately 400 water injection wells and 400 producing wells within the Waterflood Permit Boundary. This well count represent fullfield development on 160-acre regular spacing° I , In summary, secondary recovery by waterflooding is expected to recover an additional 1,04 billion stock tank barrels of oil from the Kuparuk River Oil Pool above that recovery through the natural depletion. The recovery factor is anticipated to increase 19.5 percent to 30 percent of the original oil-in-place. Cumulative gas production is anticipated to decrease 590 billion standard cubic feet. Fullfield waterflood patterns are still being decided, but will probably be a 'combination of line drive and five-spot patterns depending on reservoir heterogeneities. Forty-acre spacing will allow us the flexibility to optimize pattern selection and waterflood development in the Kuparuk River Field. P age 40 This concludes my review of projected fullfield waterflood performance and development. Robert May will now review the source waters to be used in this development. Page 41 PART VII - SOURCE WATERS I will now review the source water currently in use in Increment I Water- flood and that planned for the fullfield waterflood. Additionally, I will review the current disposition of produced water in the Increment I area and the planned deposition of produced water during fullfield waterflood. Source water for use in the Increment I Waterflood is obtained from 10 Upper Ugnu source wells located on Drill Site lB. Their location is shown on Exhibit 64. Operating history of Increment I has demonstrated that the Upper Ugnu aquifer is a reliable source of high quality injection water. This source water is being successfully obtained with 10 gravel packed wells lifted with hydraulic jet pumps. Exhibit 65 shows the withdrawals from this reservoir. About 16 million barrels have been withdrawn to date. Exhibit 66 is a log of a typical Upper Ugnu interval as it appears in Water Source Well No. 6. The well contains about 300 feet of perforated and gravel packed interval. Downhole hydraulic pumps and gravel pack completions are performing as expected with no problems encountered to date. Bottomhole pressure monitoring of the Upper Ugnu aquifer was initiated early to give indications of reservoir limits which might affect the aquifer's ability to supply injection water for Increment I. Exhibit 67 is a summary of the pressure history to date. This exhibit also compares Page 42 actual pressure history to pressure predicted for an infinite acting aquifer. The prediction technique accounts for pressure responses due to the ten water source wells and uses daily allocated water production volumes from each well as input. The actual pressures compare favorably with predicted pressures until October 1983. The pressure in January, 1984 is lower than predicted, possibly indicating some boundary effects. The current bottomhole pressure depletion indicates, however, that this aquifer is capable of supplying sufficient rate for the current Increment I Waterflood and the proposed expansion. If the January, 1984 pressure does indicate a boundary the aquifer still would be large enough to supply all projected source water needs until startup of fullfieid waterflood. Additionally, the mechanical capability of increasing the net withdrawal rate from the source water wells has been evaluated. A high rate test was conducted on Water Source Well No. 4 in May 1983. Increased withdrawal rates were achieved without adversely affecting the gravel pack com- pletion. The mechanical completion used in this test will enable us to withdraw at rates approaching 58,000 barrels per day of water for the expansion of Increment I o Exhibit 68 shows the water production from the Increment I Waterflood. Until recently facility constraints limited the amount of produced water we could process. In March 1984 after extensive water compatibility work comparing Upper Ugnu source water, with both Kuparuk water and produced water, the decision was made to mix the produced and source waters. This has allowed some wells which had been cut back or shut-in because of Page 43 high water cut to be brought back on production. Water handling capa- bilities at CPF-1 are currently being optimized to process all available produced water. ,' With the startup of Kuparuk fullfield waterflood, water sources will consist of both produced water and treated Beaufort Sea water° Unlike the Upper Ugnu water and current produced waters, the Beaufort Sea water and produced water will be handled separately in order to prevent facil.ity problems associated with water incompatibility. Exhibit 69 shows water analyses of the current Upper Ugnu water source, the Kuparuk River Reservoir water, the current produced water and the Beaufort Sea water. When Beaufort Sea water and Kuparuk River Reservoir water are mixed, the potential exists for the formation of either barium sulfate or calcium carbonate scale. Summarizing this part of the testimony, at current withdrawal rates the Upper Ugnu aquifer is continuing to be a source of high quality water for Increment I, and will be able to continue to supply water in increased volumes for a 1984 expansion of waterflood. Additionally, after extensive compatibility testing the Upper Ugnu source water and the produced water are currently being mixed. This removes part of the facility limitation on produced water, thus allowing additional optimization of Increment I. The Beaufort Sea will replace the Upper Ugnu as the source with startup of the Fullfield Waterflood. The incompatibility of this Water with produced water will necessitate separate handling systems. Page 44 This concludes the water source part of the testimony. The following testimony by Joel Brandstetter will review the Fullfield Waterflood Facilities. P age 45 PART VIII - WATERFLOOD FACILITIES Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Joel Brandstetter. I received a Bachelor of Science degree in Mechanical Engineering from Texas A&M University in 1975. I have worked for ARCO from that time in many areas, including offshore operations, project staff and exploration. I am presently an Area Engineer in the Facility Planning Group for the Kuparuk River Field in charge of the waterflood facilities planning. I will review today the surface facilities needed to accomplish full field waterflood. The expansion of the Kuparuk River .Field Waterflood involves the fab- rication, erection and startup of a number of new sea water handling facilities indicated in this functional facility diagram in Exhibit 70. The first facility is an intake structure and seawater treatment plant at Oliktok Point. The intake will be located adjacent to the existing dock face, with the Seawater Treatment Plant (STP) attached via a short pipeway to the south; the second facility is a low pressure distribution system to transport treated water to the Local Injection Plants (LIP) at CPFs 1, 2 and 3, including pigging equipment to evacuate the low pressure system in case of plant shutdown; the third system is the local injection plants (LIPs) at CPF-1, 2 and 3, which boost the water up to injection pressure; and finally, the distribution flowlines which deliver this high pressure water to the drill sites for injection and associated pigging equipment for freeze protecti on. I will now review more closely each component in this system. As indicated on Exhibit 71, the face of the intake structure is a westward continuation of the existing dock face. This orientation was chosen to minimize problems with sedimentation blocking flow into the seawater .intakes. The intake configuration and marine bypass system shown in Exhibit 72, are based upon the Prudhoe Bay design with modifications for the shallower water depth and Kuparuk's 440,000 barrels of water per day peak flow requirement. There are four identical intake channels, each with seal bars to keep out marine mammals, a trash screen to stop floating debris and a primary diverter screen to move s~maller marine life beyond the pump suctions. This screen is oriented such that water velocity is ac- curately established and fish move directly into the bypass system without impingement upon the screens. The bypass system is sized to accommodate the largest fish species in the area. To maximize the use of water entering the plant, the four bypass streams are combined in two secondary diverter systems. Additional water is drawn off here for use in recycle lines and in the jet pump which moves the fish back to the Beaufort Sea. The major volume of water is transferred to the Page 47 { {' STP for further processing. There are additional minor return streams of hot water from the STP used to prevent ice formation on the seal guards, trash screens and diverters during winter months. Within the STP, as represented on Exhibit 73, water from the seawater intake is heated in titanium plate and' frame exchangers to approximately 60°F using glycol 'from fired heaters. The water is then filtered and deareated before being pumped to the Local Injection Plants at CPFs 1, 2 and 3. This deareation is accomplished using natural gas in packed columns which is combined downstream with makeup gas from the fuel gas system to provide fuel for the plant heaters. STP power is provided by two turbine driven generators. The processed water is transferred, as seen in Exhibit 74, from the STP in a 30 inch trUnk to the LIP at CPF-3 and continuing to the "Y" where 24 inch branch lines transport it to LIP at CPFs 1 and 2. The use of these large lines Optimized the pump size needed and, addi- tionally, increased line cooldown time during no-flow conditions resulting in a longer time before freeze up. These pipelines utilize pigging facilities for line evacuation in the event of an extended plant shutdown. Pigs, driven by natural gas, remove water from the lines to eliminate freezing problems. The pipelines will be warmed prior to startup with. gas obtained from the gas lift system which is heated to approximately 180 °F. In the Local Injection Plants depicted on Exhibit 75, the source water and produced water are handled in two completely isolated systems. Each water type is received in a separate surge tank. The tanks feed electric driven Page 48 booster pumps which supply intermediate pressurized water through a manifold system to turbine driven injection pumps where a final injection pressure of 2550 pounds per square inch is obtained. Each pump train is identical, and manifolding and valving allow handling of either produced or source water by any train as shown in this exhibit. Two pump trains will supplement the two existing Increment I pump trains at CPF-1 and four trains will be installed at CPF-2. Provisions have been made to add filtering equipment to the produced water system if needed later. A third Local Injection Plant will arrive with CPF-3 in the 1986 sealift adding two pump trains to the system. From the LIPs a radial network of flowlines shown in Exhibit 76, distri- butes the water, at injection pressure, to individual drill sites in each CPF area. These lines also contain pigging facilities for line evacuation in the event an extended shutdown occurs. This concludes the description of the facilities that will be needed for fullfield waterflood. Steve Suellentrop will now summarize today's testimony. Page 49 (:"~ ~ PART IX - SUMMARY In summary, the schedule for fullfietd waterflood development achieves water injection on major portions of CPF-1, CPF-2 and CPF-3 by the year end of 1987. Results from the Increment I pilot will be incorporated into fullfield waterflood plans. Injection well profiles have indicated pre- ferential water entry into the C sand interVals. A combination of A sand stimulation techniques, and alternative well completions, such as selective singles, are needed to balance water injection profiles. Radioactive tracer data and pressure testing indicate a north-south directional permeability in at least the C sands. Oil recovery can benefit from this permeability trend by proper orientation and selection of a waterflood pattern. Reservoir studies of waterflood performance indicate the production of 1.6 billion barrels of oil over a 35 year period for a 30% recovery of the original oil in place. Natural depletion only of the Kuparuk River Oil Pool would yield 560 million barrels of oil. Optimization of oil recovery will require addressing the concerns highlighted by Increment I Waterflood, and the flexibility to drill to denser spacing than the planned 160-acres per well when geological conditions control fluid movement. Major waterflood facilities will be operational by January, 1986. Approxi- mately 400,000 barrels of water per day of Beaufort Sea water will be filtered, deaerated, heated, and pumped through low pressure pipelines to Page 50 i" {' local injection plants at each CPF. The local injection plants will increase the pressure of the source and produced water streams for distribution through a high pressure radial trunk system to the drill sites and eventual injection into the Kuparuk Sands. Thank you for your attention, and that concludes the testimony of the app 1 i c ant. Kuparuk Prudhoe River Bay Field Field Ugnu State 1 Kuparuk River Unit EXHIBIT 1 Exhibit 2 Kuparuk River Field History Unit Operations Conservation Order No. 173 May 6, 1981 Unitization Agreement December 1, 1981 Plan of Development Application for Additional Recovery, Increment I Waterflood December 1, 1981 February 8, 1982 I ! Waterflood Permit Boundary. EXHIBIT 3 Year End 1983 Status Increment I Waterflood Natural Depletion Gas Affected Central Production Facility .No.10perationa EXHIBIT 4 l..:...:.:..:.., mi"CpF,2 :: .. Waterflood Permit Boundary i I Year End 1984 Status Increment I Waterflood and Expansion Natural Depletion Gas Affected CPF-2 Operational EXHIBIT 5 I I Waterflood Permit Boundary Year End 1985 Status Increment I Waterflood and Expansion Natural Depletion Gas Affected CPF-2 Operational Oliktok Pt. STP EXHIBIT 6 ! I Waterflood Permit Boundary Year End 1986 Status Increment II Waterflood Natural Depletion Gas Affected Seawater Treatment Plant Distribution Lines Two Local Injection Plants Oliktok Pt. STP EXHIBIT 7 Waterflood Permit Boundary Year End 1987 Status Waterflood Natural Depletion Gas Affected CPF-3 With LIP Operational Oliktok Pt. STP EXHIBIT 8 Waterflood Permit Boundary Year End 1988 Status Waterflood Natural Depletion Gas Injection Exhibit 9 Kuparuk 'River Field Application For Additional Recovery Fulifield Waterflood Special Requests - 40 Acre Well Spacing - Effective Date is Approval Date - Administrative Approval of Waterflood Boundary Modifications EXHIBIT 10 I I I l Kuparuk Unit ~ Boundary t. I I I ,__! Participating Area Boundary ..~.][ .... L. r.~~1' l I I I I I I I I I I I I I I I I I I I ...... -. I I I I Kuparuk River Field Boundary Designations Exhibit 11 Kuparuk River Field Testimony Agenda Geologic Description Increment I Waterflood Performance Field Waterflood Operations Fullfield Waterflood Performance Source Waters Waterflood Facilities Summary Truncation Of Kuparuk Lower Member C -5700 EXHIBIT 12 Waterflood Permit Bou Kuparuk River Field Structure Map Top Kuparuk River Formation C Drill C' West Site Ea 1E ~ - -5500 -5500 ' I -6000 -SS00 ! Oil -7000 I 2 Mile ! VerI.Exag. = 20x EXHIBIT 13 Stratigraphic Units: Water Kuparuk River Field Structural Cross-Section Kuparuk River Formation - -6000 - -6500 Waterflood Permit Boundary Kuparuk River Field Fault Pattern In Kuparuk River Formation EXHIBIT 14 EXHIBIT 15 0 Gamma Ray 150 I Resistivity 1000 'Subsea Inter- Unit Mem- Depths val ber _ ....-....~,v~ %000' ~,~4-, C-2 _ OW ..--.--- !¢'" C-1 _____ A'6~ c ~ - ,' 0 ---- , .'-~ _ Kuparuk River Field Kuparuk River Formation Well 1A-13 Sandstone Interbedded Sandstone, Siltstone, and Mudstone Siltstone I---~ Mudstone ['~ Glauconite 1 Siderite Cement Erosional Unconformity CPF-3 ' I I EXHIBIT 16 I Waterfiood A CPF-1 CPF-2 1 I Kuparuk. River Fie!d Kuparuk River Formation Unit C Permit Boundary I I Net Sand 10' or Greater A SW 1%10 PROJECTED ALONG STRIKE 1%12 1A-10 1A-5 1A-8 1A-3 1H-8 1H-6 1H-7 1H-5 C-2 UNIT D UNIT C A' NE UNIT B 50' SCALE FT'T ~ ~r 2000' F~. VERT. EXAG. = 40x I'~ SIDERITE CEMENTED ZONES IN C-1 & C-4 INTERVALS I---] KUPARUK SANDSTONE INTERVALS WITHOUT SIDERITE CEMENT ~ NORTHWEST-SOUTHEAST TRENDING FAULT EXHIBIT 17 Kuparuk River Field Stratigraphic Cross-Section Kuparuk River Formation Units B iC, and D B NW WEST SAK 1116 WEST SAK t12.3 (PROJECTED) A-1 UGNU tl l A-2 m m mm mm m m m mmmm~ ~ 1Y-2 [ 1A-15 a~ 1A-8 A-5 50' FT.I SCALE 0' ' ! 5000' FT. VERT. EXAG. = 5OX EXHIBIT 18 RESERVOIR SANDSTONE Kuparuk River Field Stratigraphic Cross-Section Kuparuk River Formation Unit A Truncation Of,/ Kuparuk Lower,,~ Member ^ CPF-3 /~ - /CPF-2 B! CPF-1 Kuparuk River Field Kuparuk River Formation Unit A Net Sand 10' or Greater Waterflood Permit Boundary EXHIBIT 19 Waterflood Permit Boundary Kuparuk River Field Fault Pattern In Kuparuk River Information ~i.~.;.~'"J Drill Site 1 A L~~ b__J Drill Site 1E EXHIBIT 20 Producer /~ Water injector -.. Down Up~ Fault '~ Barrier To Fluid Flow I Mile Kuparuk River Field Drill Site lA- Structure Map Top Kuparuk River Formation .. Contour Interval = 50' I::XHIRIT 21 6 ~ 0~ Kuparuk River Field Drill Site 1E- Structure Map Top Kuparuk River Formation Contour Interval = 50' Producer Water Injector Fault Barrier To Fluid Flow I Mile EXHIBIT 22 Exhibit 23 Increment I Waterflood Goal Optimize Recovery and Reduce the Risk of Fullfield Waterflood Objectives Determine: * Reservoir Properties Affecting Injectivity · Reservoir Properties Affecting Sweep · Optimum Well Spacing · Estimate of Recovery r- Waterflood Permit Boundary ilA lB 1E _ I I Kuparuk River Field Increment I Waterflood 1E-11 A Sand Only Pattern 1E-13 1E-15 1E-16A 1E-17 /X 1E-4 1E-10 1E-8 1E-9 1E-14 ~ ALE-3( 1E-29 1E-28 1E-24 1E-18 ALE-19 1E-5 1E-21 1E-7 A ALE.23 1E-lA ( 1E-2 1 E-26 1E-22 I Mile Boundary, A and C Sand Patterns Boundary, A Sand Pattern Water In~ector Producer Kuparuk River Field Drill Site 1E Waterflood EXHIBIT 25 1E-10 1E-11 A 1E-12 1E-13 ~, I 1E-15 1E-16A 1E-8 ALE-9 1E-25 1E-17 1E-4 1 E-30 {~! 1E-29 1E-28 1E-18 1E-24 IE-1A 1E:23A (~ (~ 1E-2 ALE-19 _ 1E-7 1E-20 ALE-21 1E-26 1E-3 · 1E-22 -1 Mile · Producer Producer With Water Breakthrough I '~1 Producer Shut-in, High GOR Water Injector Kuparuk River Field Drill Site 1E Water Breakthrough EXHIBIT 26 100000 Kuparuk River Field Increment I Waterflood DS-IE Performance A and C Sands Patterns O Oil Water Injection GOR Produced Water 100 Jan 1982 JaN 1983 Jan EXHIBIT 27 100 A KUparuK R~ver t'ie~(~ Drill Site 1E Injection Profile A and C Sand Injectors 86 11 3 _ 0 100°/~ Injection (~/o) EXHIBIT 28 1E-1 1E-11 1E-10 1E-8 1E-12 1E-15 1 E-25 1E-14~ ~E-~e ) "'-t"E.27A 1E-17 /X 1E-4 1E-30 1 E-28 (~ 1E-29 AlE-lA 1E-26 1E-18 · · ALE-19 ALE-21 1E-24 · 1E-7 1E-20 · 1E-3 · 1E-22 I Mile · Producer (~ Producer With Water Breakt[ Jgh ~ Water Injector Kuparuk River Field Drill Site 1E Confirmed Tracer Detections EXHIBIT 29 1500 Kuparuk River Field Increment I Waterflood Pattern 1E-12 Performance A Sand Only O 1000 Water Injection Oil GOR Jan 1983 Jan EXHIBIT 30 EXHIBIT 31 I I . J Waterflood Permit Boundary i I lA lB I'E Kuparuk River Field Increment I Waterflood 1G-5 Y-5 1A-15 _ ~,1A-16A 1A-3 1A-2 /X 1A-13 .1A-8 1A-14 /X 1A-12 A-5 1A-9 1A-1 1A-7 A-6' /X 1A-11 1B-1 Producer Water Injector 1F-1 1F-6 I Mile Kuparuk River Field Drill Site ~A 0 1000001 10000- Oil Kuparuk River Field Increment I Waterflood DS-lA Performance Water Injection 0 ,m 0 GOR Produced Water 100 Jan 1982 Jan 1983 I Jan EXHIBIT 33 1G-2 1G-5 1Y-50 2Z-5 1A-15 1A-2 /X 1A-12 1A-10 1A-1 /X 1A-13 1A-5 1A-8 · 1A-7 1A-6 /X 1A-9 1A-3 1A-4 1A-11~ 1B-2 Producer 1B-1 ~, Producer With Water Breakthrough Producer Shutin, High GOR Water Injector (~1F-1 I Mile Kuparuk River Field Drill Site lA (~1F-6 EXHIRIT 3000 20O0 1000 I Jan Oil Kuparuk River Field Increment I Waterflood Well 1A-8 Performance GOR 1982 I Jan 1983 I Jan EXHIBIT 35 100 - Kuparuk River-Field Drill Site lA Injection Profile C-4 C-3 C-1 A '6 65 25 Injection (%) 100% EXHIBIT 36 EXHIBIT 37 ,! ~J C Sands A Sands ,, A Sands f Waterflood Permit Boundary Kuparuk River Field Locations Directional Permeability' Tests Exhibit 38 Increment I Waterflood Results · Reservoir Properties Affecting Injectivity C Sand Preferential Injection C Sand Fractures Preferential Injection · Reservoir Properties Affecting Sweep C Sand Directional Permeability · Optimum Well Spacing Waterflood Response on 320-Acre Patterns Possible Situations Requiring Infill Drilling Identified · Estimate of Recovery Provided Basis for Recovery Estimates 1E-10__ 1E-8· 1E-18· · 1E-11 ~ 1E-7 1E-12 ~,1E-19 ,E-13 ~ · j~ 1E-9 1E-20 1E-25 · 1Eo15 · · I 1E-14~ 1E-5 1E-6 · ~1E-21 1E-16A 1E-30 1E-17 1E-28 1E-4 1E-27/~ 1E-29 A 1E-lA 1 E-26 1 E-24 1E'23~i, · 1E-2 1E-3 · 1E-22 Injected Tracers , Z~ Tritlated Water, HTO NI-63 Co-57 Co-60 Untagged I Mile Kuparuk River Field Drill Site 1E Tracer Program EXHIBIT 39 Exhibit 40 Kuparuk River Field Increment I Waterflood Surveillance Radioactive Tracer Detections Producing Days to Well Tracer Detection i _ _ JJJ ! i _ eel 1E-28 HTO 5 1 E-17 Co 57 34 1E-15 Co 57 105 1 E-6 Co 6O 109 1E-2 Co 60 148 1E-10 1E-8 1E-18 · 1E-11 A ~ · 1E-7 1E-12 ALE.19 1E-13 ~ · /~ 1E-9 1E-15 1E-16~ I~ _ 1E-17 1E-25 1E-27A _ 1E-4 1E-30 ~ 1E-29 1E-28 · 1E-5 1E-26 1E-24 1 E-20 ALE-21 j~k 1E.1A 1E-23/~ · 1E-3 · 1E-22 I Mile Injected Tracers //~ Trillated Water, HTO NI-63 Co-57 · Co-60 Untagged Kuparuk River Field Drill Site 1E Confirmed Tracer Detections EXHIBIT 41 Number of Wells ,. u p';;.'u E-.:I i 9'~'r Increment I Waterflood Surveillance Profile Logging 15 10 5 i _ i i i i i i ii Initial Subsequent Production Injection Injection Profiles Profiles Profiles EXHIBIT 42 Kuparuk River Field Increment I Waterflood Surveillance Bottom-hole Pressure Monitoring Number of Surveys 20 15- 10 5 F owingShut-in Pressure Pressure BHP BHP Falloffs Buildups EXHIBIT 43 Single Completion Tubing----- Production Casing K uparuk //////~ S aAn~'~////~ 1 .__ Gas Lift Mandrel ~Packer --KuPar~'~ River Field Selective Single Completion Tubing Production Casing Lift Mandrel Kuparuk ¢ Sand Production/ Injection Mandrels t Joint Production/ Injection Mandrel EXHIBIT 45 Exhibit 46 Kuparuk River Field Current Single Completion Specification Item Tree Conductor Surface Casing Production Casing Completion Assembly Specifications 5000#,-APi.75o - Approximate Setting Measured Depth 16", H-40 PEB, 65fl 9-5/s", J-55 HFERW, 36# 7" K-55 26# Top of Cement Located Approximately 800' Above Top of Kuparuk Interval 110' 3000' 8400' SSSV Tubing Packer Gas Lift Mandrels Hydraulically Actuated, Tubing Retrievable, Non-Equalizing 3-1/2'', J-55, 9.2# Hydraulically Set Retrievable Approximately 6 1900' Above Sands Spaced Above Packer Selective Single Completion Specifications Item Tree Conductor Surface Casing Production Casing Specification 5000#, APl-75° APproximate Setting- Measured Depth 16", H'40 PEB, 65# 9-5/8", J-55 HFERW, 36# 7" K-55, 26# Top of Cement Located Approximately 800' Above Top of Kuparuk Interval 110" 3000' 8400' Completion Assembly SSSV Tubing Upper Packer Lower Packer Production/Injection Mandrels Gas Lift Mandrels Blast Joint Hydraulically Actuated, Tubing Retrievable, Non-Equalizing 3-1/2" J-55 9.2# Hydraulically Set Retrievable Wireline Set Permanent 3 Side Pocket Approximately 6 Opposite C-Sand Perforations, 10' Each Side 1900' Above C-Sand Between C-Sand and A-Sand Between Packers Spaced Above Upper Packer Well Location EXHIBIT 48 / / / / / / / 1 C4 800 4b'00 10 20.0 4 5900 2 C4 80 80 8 24.5 7 5905 3 C3 60 60 6 23.0 25 5921 4 Cl 200 1000 20j; 24.0 6 6000 IIIIII IIIIlllllll: llllllllllllllllllllllllllllllllllll Illlllllllllllllllllllll Illlllllllll 5 A 100 100 10 28.0 28 6200 .264O ft. I 10 Cells Impermeable Boundaries Line Drive Operating Mode ~/'~ Water Injector OProducer Kuparuk River Field Pattern Model A and C Sands 4000' GOR Produced Water .--:-u ~u~i~r '~'-'-'- , ,l~l~ ' Model Performance A and C Sands Pressure Oil 0 I 2 3 4 5 6 7 8 9 10 Years EXHIBIT 49 Well Location EXHIBIT 50 · ,., . t / / /, '/ I, / [ 1 A4 45 45 4.5 22 2 6017 ~ 2 A4 45 45 4.5 22 8 6022 !~11111 Illlllllllllllll~llll rlllllllllll IIIIIIIiill ,lllllllllll IIIIIIIIIllllllllllllllll Illlllllllll llllll ~ 3 , ,. 90 90 9.0 23 2 6055 4 A3 90 90 9.0 23 9 6061 5 A3 90 90 9.0 23 9 6065 · / 2640 ft. 10 Cells Impermeable Boundary Five Spot Operating Mode Water Injector Producer Pattern Model A Sand Kuparuk River Field 2000 Kuparuk River Field Model Performance A Sand ~. 1500- 1000- Oil 500 GOR 0 · 0 r I I I O- I 2 3 4 5 6 7 8 9 10 Years EXHIBIT 51 Exhibit 52 Waterflood Permit Boundary Kuparuk River Field Prediction Method Drill Site Performance Areal Model A and C Sand Pattern Model A Sand Only Pattern Model Gas Injection Gas Encroachment - 300- Kuparuk River Field Oil Production Rates Waterflood vs Natural Depletion 250 - 200 - 150 - 100 - 50- Waterflood Oil Natural Depletion Oil 0 I I I I I I I 1980 1985 1990 1995 2000 2005 2010 2015 Year 2O20 EXHIBIT 53 EXHIBIT 54 2000, 1500_ 1000_ 500_ Kuparuk River Field Cumulative Oil Production Waterflood vs Natural Depletion O, ! I I I I I I 1980 1985 1990 1995 2000 2005 2010 2015 2O2O Year 1500 Kuparuk River Field Cumulative Solution Gas Production Waterflood vs. Natural Depletion EXHIBIT 55 1000 _ 500 _ 0 1980 1985 I I I 1990 1995 2000 Natural Depletion Gas Waterflood Gas I t i 2005 2010 2015 21)20 Year Kuparuk River Field Waterflood Development Fullfield Water Rates 400- Injected Water 300 200 100 Produced Water Source Water 0 1980 1985 1990 1995 2000 Year 2005 2010 2015 2020 EXHIBIT 56 320 Acre Pattern I I ~ I I ~ © Mile Kuparuk River Field Direct Line Drive Waterflood Pattern Water Injector (~) Producer EXHIBIT 57 160 Acre Patterns ! I i 0 ! ~ 0 ~ 0 ~ 0 I Mile Kuparuk River Field Infiil Drilled Five Spot Waterflood Patterns Water Injector 0 Producer Converted Producer 320 Acre Pattern I I I I ..... ~ ..... .. I Mile .© Kuparuk River Field Staggered Line Drive Waterflood Pattern Water Injector (~) Producer EXHIBIT 59 320 Acre Pattern A" o 'A o o "'/X" o A A o A o I Mile Kuparuk River-Field Five Spot Waterflood Pattern Water Injector 0 Producer, EXHIBIT 60 160 Acre Patterns 80 Acre Pattern I I ~1 0 I I I oZ~o o A A o o ~ A o I Mile Kuparuk River Field. Infill Drilled · Five Spot Waterflood Patterns Water Injector 0 Producer Converted Producer EXHIBIT 61 EXHIBIT 62 O A o O O O A ~ o A KUPARUK RIVER FIELD Drill Site lA Infill Drilling Between Sealing Faults 40 Acre Well Spacing Infill Injector Infill Producer Converted Producer · Producer Down Water Injector Fault Barrier To Fluid FIo I Mile 500 400 300 200 100 0 Kuparuk River Field Fullfield Waterflood Well Count 160 Acre Well Spacing i i i Water Injectors Producers ;-_. ~.- _ · ... _.... ........... . ..... 1984 1985 1986 1987 1988 Ultimate EXHIBIT 63 WSW-9 WSW-6 ~ ~ I~ ~ WSW-3 wsw4~ ~ WSW-8 ~li~ WSW-1 ~ WSW-2 ~ WSW-4 wsw'~l l WSW-7 ~ WSW-5 Waterflood Permit BOundary Kuparuk River Field Increment I Waterfiood Gas Injectors Producers Source Water Producers EXHIBIT 64 60000 EXHIBIT 65 50000'- 40000 - 30000 20000 - 10000 0 Jan 1983 , . Feb Kuparuk River Field Increment i Waterflood Production History Water Source Wells Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 1984 Gamma Ray Feet Laterolog I 10 lOO lOO0 Top Upper Ugnu Perforated Interval Base Upper Ugnu EXHIBIT 66 Kuparuk River Field Water Source Well No. 6 Log Traces vs. Measured Depth 1150 J 1100- 1050- 1000- 950- Kuparuk River Field Water Source Well No.1 Pressure vs. Time Calculated Values vs. Actual Data Legend Continuous Data Calculated Pressures X Spot Pressure Points 900, I ! I Feb Mar. Apr May Jun x I I I I I I Jul Aug Sept Oct Nov Dec 1983 EXHIBIT 67 Kuparuk River Field Produced .Water 6000- 5000- 4000- m 3000.- 2000- 1000- EXHIBIT 68 O- I I ! I ! I' I I Jan Feb Mar Apr May Jun Jul Aug Sep I I I I Oct Nov Dec Jan 1983 1984 Exhibit 69 Kuparuk River Field Water Analyses Key Components, MG/L Reservoir Produced Upper Ugnu Beaufort Sea _ Total Dissolved Solids 24,800 16,400 2,800 52,700 Barium 50 20 2 580 Chloride 11,700 7,100 1,300 26,900 Bicarbonate 4,000 3,400 450 0 Sulfate 0 0 0 4,100 Strontium 0 0 I 30 Calcium 70 7 60 580 CPF-3 LOCAL INJECTION PLANT 1111117111111111 INTAKE CPF-2 LOCAL INJECTION PLANT DRILL SITE SEAWATER TREATMENT PLANT LOW PRESSURE SUPPLY LINES CPF-1 LOCAL INJECTION PLANT HIGH PRESSURE DISTRIBUTION LINES DRILL SITE I INJECTION WELL J I i INJECTION WELL] DRILL SITE KUPARUK RIVER FIELD FULLFIELD WATERFLOOD ' FACILITIES SYSTEM OVERVIEW EXHIBIT 70 Disposal, Boat Ramp Utiliway Intake Facility Dock ter Treatment Plant Diesel Kuparuk River Field Site Plan Oliktok Point~ EXHIBIT 71 200 0 ~ I r I :. --:1 ' Scale In Feet 200 i Marine Life Outfall Line Seawater Intake Ports Trash Primary Rack Dive Secondary Diverter Primary Diverter Screen r Jet Pump Secondary Diverter Screen Marine Life By-Pass Piping Seawater Reservoir To STP ! I I I I I Hot Water Supply Lines Kuparuk River Field Intake System ~VWIRIT 79 From Sea To Sea To-. Sea Intake Structure Exchanger Filters Marine Life Bypass Exchange rLi DisposaISystem I Main Plant Outfall Waste Gas Fuel Gas '~i- Heatersi i~~ ~ DeaerationTransfer , To CPF's.~ . , - [ Pumps t Stripping as Lift Gas Kuparuk River Field Seawater Treatment Plant EXHIBIT 73 Seawater Treatment Plant CPF-3 Injection Plant Pig Station Kuparuk River Field Low Pressure Supply Pipelines -2 Injection EXHIBIT 74 Plant 24" o I CPF-1 Injection Plant 2 3 4 5 , I Miles Source~ Tank Water Produced ~ Tank / Water I I I I i-L.___L. Filters I L {_.Fut_u re)._ I Kuparuk River Field Local Injection Plant Low Pressure Manifold Booster Pumps Intermediate Manifold Heater Injection Pumps High Pressure Manifold To Drill Sites EXHIBIT 75 Oliktok Point 2N 3M 3Q 30 3H '3N 31 3J 3P 3K ~L ~ 2~ High Pressure 2L 2K 2J Waterflood Flowlines EXHIBIT 76 F d B L ~ C A T .[ U ~xr P. d, 99510--&049 S~¥OR[~!, ACCORDI~G TO hAW DECLARES: TSAT 6~E A~iC~C)RAGE T].~8, A PUP, LI'SBED i~i :I.'~i~; 'I'O~i~ Of Ai,~CHoRAGE I~ TflE .Tt,~IRD oUDiCIAb DIVISio~, STATE OF ~iaAShA, A~.4U ~i,'HgT T~.~ NOTICE Z. OF ,~,},t18 AD wAS............ ,' ':STATE OF,, A',LA$:I{A: '" At]i-OS 5533 1 05/07184 05/07/8~ · . .l~e': :The a~ii'c~i.n of 'ARCO ':'. ' ALASKA, INC. ~ot approval to . '"RI~r'UnlI. " . - '- Nific~ Is h~rebY given'- that '~RC~ .~laska, .: inc. has re- ~..t~ 'A}u~ka Oil. and. Ggs . ~ati6fi' '-co,miniOn' to . .~ue;:~n.'~F' p~uant '.to A~C;:~.~, aPPlYing a fullfleld ~1~ .,rol~ for that tlow6F~b? ~U~ruk.:.Rlver .... : suP~,'of'the-r~st..- ., ~%- ,. % I] , ·: . .', . T;he?.he~ll'ing-"wlll: be'-"held "of 9~.00~AM"0fl'Wedile'sda¥,..May 23, 1984';Jn. the: municipality.: of Ah- c_h0r~ .,'~,s~embly. Room, 3500 ~ast '.,.~.oo'. R~d, "Anchorage, Alaska:. All':' Interested persons and ~ertles ar6 invited to give testlmon, y. .: '" ""'," i, " '":' ,,' /'9 , TO flE,:F(3~E dE THIS................... NOTARY Pt:..J~.,suiiLC (,'~F litE' o,ATE OF AI~AgKA $ 1.3.50 April 18, 1984 Mr. J. D. Weeks Kuparuk Operations Manager ARCO Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510 Dear Mr. Weeks: We have received your letter of April. 4, ].984 requesting a waiver of 20 AAC 25.240(a) regarding the producing of oil wells with a gas-oil ratio in excess of 2,000 cubic feet of gas per barrel of oil. The Commission has determined that the current production practice in the Kuparuk 'River Field, Kuparuk River Oil Pool, is to inject the produced gas back into the same pool. This practice qualifies the wells producing from this pool to be waived from the gas-oil ratio limitations. Therefore by this letter, the Alaska Oil a~d Gas Conservation Commission, pursuant to 20 AAC 25,240(b)(2), waives the 2,000 to 1 gas-oil ratio lim~.tation for'all.wells producing from the Kuparuk River oil Pool for as long as the produced gas is being returned, to the I(uparuk River Oil Pool. Yours very truly, ,./....,:.'"">:' :, ........... ? ........ Harry W. Kugler/ Commissioner BY ORDER OF THE CO~ISSION be:l.K.240 cc: Mr. H. D. Haley, Conoco-AnChorage ARCO Alaska, Inc{' Post Office Box 100360 Anchorage, Alaska 99510 Telephone 907 265 6513 Leland E. Tare Vice President March 23, 1984 C. V. Chatterton Chairman Alaska Oil and Gas Conservation Commlss~on 3001 Porcupine Dr~ve Anchorage, AK RE: Kuparuk River Field Fullfield Waterflood Project Application for Additional Recovery Dear Mr. Chatterton, Pursuant to the provisions of 20 AAC 25.400, ARCO Alaska, Inc. (ARCO), on behalf of the Kuparuk River Unit Working Interest Owners, hereby applies for approval of the Alaska Oil and Gas Conservation Commission to implement a fullfield waterflood project for the Kuparuk R~ver O~1 Pool. Thls application lncludes the documentatlon requlred by 20 AAC 25.400. An affidavit of ma~ling indicating that the application has been transmitted to all interested leaseholders is attached to this letter. Ten copies of the appl~- cat~on have been provided for your use. Please advise us of the date set for public hearing. Representatives of ARCO and the other Working Interest Owners w~ll be available to discuss these matters, or provide additional ~nformation at your convenlence. Very truly yours, L. E. Tare LET/ksm Attachments cc: Kuparuk River Unit Working Interest Owners ARCO Alaska, Inc. is a Subsidiary of AtlanttcRichfieldCompany U O'D PROJECT ' · '" . .. ........... . . PL': ....,..,. ATIO. N ....... FO'" '" R::.::ADD'I"' ' ':'N:AL...,REC"~ O O AP lC ':' ': · .' · ':.':?' - - ' ' ' ." ' ?t'"' ';"' · ' i'." ' " '-'' . . . .. . . ...: . . . ....... ' ' '-'~'"" ;' · .".' '.'. .... , ..... .'. ' ", - ' '".'.':.."i:...',~'. , .. ..... .... . ' . .,'. ...: '.:'.'.'...:,..,,.,. .... .... -,.. ........ ....... ~'."~.~'." ".~' :..'?.~:.': '"'~ "i: :':": .~ ~'M'!AR.CH.? 19.8 4 ~. ' :' ',:..:..: :' ?.:....:..... ....... ... ~'~....~ :."....: :..-'.~....'. ~:~.~...,: ~.'"'."~'.:..':': :i:.!~ .~..." · .. ,' ' '.'.':. ' .. .... ~' ' ".'~ ,..". ," "'.' '"... ' ".' ~.'..' '...:' ,'." "' '..':'..' ..... ' ' .','i ": ," "" ':" "'. ' ' .'. "' ""'" : ': ' ' ':"'.' -': ' ' ' :" ' '" ' ". , ': ': · ' '" '"."' "' '.;,.: "' "'"' FULLFIELD WATERFLOOD PROJECT KUPARUK.RIVER FIELD APPLICATION FOR ADDITIONAL RECOVERY Pursuant to 20 AAC.25.400, ARCO Al~aska Inc. as Unit Operator, on behalf of the Kuparuk River Unit Working Interest Owners, hereinafter referred as the Kuparuk Owners, request approval to waterflood the Kuparuk River Oil Pool to increase oil recovery from an estimated 10% OOIP to a primary plus secondary oil recovery of about 30% OOIP. Based on current reservoir interpretation, fullfield waterflood is expected to yield approximately 1.6 billion barrels of oil under combined primary and secondary recovery. Under current development plans, water injection facilities will be operational by January, 1986 and will inject treated Beaufort Sea water and produced water into the Kuparuk River Oil Pool. · , In addition to approval to waterflood, the' Kuparuk Owners make the following Special Requests. 1. Waterflood Permit Area The Kuparuk Owners request that the Alaska Oil and Gas' Commission (AOGCC) allow the Waterflood Permit Area to be modified administratively upon application by the Unit Operator, so that its boundary coincides with or extends beyond the current Participating Area. The application to modify the waterflood boundary will set forth the changes to the Waterflood Permit Boundary by governmental section numbers, include a reasonable justification, and provide other supporting information. 2. Effective Date The Kuparuk Owners request that the effective date of this application be. the date of approval by the AOGCC. This timing will enable the Kuparuk Owners to proceed with 1984 waterflood plans. 3. Well Spacing Implementation of an efficient and effective waterflood could require well spacing closer than 160 acres per well as set forth in Conservation Order No. 173. Therefore, the Kuparuk Owners request that the AOGCC approve unrestricted well spacing within the approved Kuparuk Waterflood Permit Boundary within the Kuparuk River Field. Current Waterflood Permit Area Description (20 AAC 25.400 b.1,2,4) Water will be injected into the Kuparuk River Oil Pool, also referred to in this application as the Kuparuk River Reservoir. Rule 2 of Conservation Order No. 173 defines this pool as the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfield Company West -1- Sak River State No. 1 well between the depths of 6,474 and 6,880 feet md, or 6387.9 a'nd 6793..9 feet, subsea. The West Sak 1 well type log is shown on Exhibit 1. The ~Jaterflood Permit Area depicted in Exhibit 2 is the area of the Kuparuk River Reservoir for which the Kuparuk Owners are formulating water injection plans. The Waterflood Permit Boundary encircles the current Partici'pating Area, and follows the outer boundaries ~'f the governmental sections listed in Exhibit 3. The Kuparuk Owners expect the Kuparuk Participating Area to change as development of the Kuparuk River Reservoir yields new information on the extent of recoverable reserves. Therefore, the Kuparuk Owners make a special request to have the AOGCC administratively approve changes to the Waterflood Permit Area. Exhibit 2 also depicts the leased acreage held by the Kuparuk Owners and affected parties. ARCO Alaska, Inc. as operator for the Kuparuk River Unit will be operator of the fullfield'waterflood program. The names and addresses of the Kuparuk River Unit le-ase holders and other affected parties are listed in Exhibit 4. Waterflood Development Plan and Rate of Development (20 AAC 25.400.b.9) The Kuparuk Owners recognize that water injection is an effective secondary recovery method to help maximize oil recovery from the Kuparuk River Reservoir. Timely implementation of water injection will provide pressure support to help maintain oil production offtake and reduce solution gas production. Current design of the.waterflood project is based on the available reservoir performance data. It is necessary for the Kuparuk Owners to maintain flexibility in their plans and to modify development schedules and project scopes as new reservoir performance data and information requires. During 1982, the Kuparuk Owners received permission from the AOGCC to conduct Increment I ~aterflood as a pilot project to optimize and reduce the risks of a fullfield waterflood. Throughout 1983, water from the Upper Ugnu Formation has been injected into waterflood patterns on Drill Sites lA and 1E (Exhibit 5). Preliminary data from the pilot has yielded valuable information on directional permeability in the reservoir and water injection profiles that will be useful for well spacing and orientation of future waterflood patterns. In 1984, upon approval by the AOGCC of this fullfield Application, two drill sites adjacent to the Increment I Waterflood pilot, Drill Sites 1F and 1G, will be waterflooded using source water capacity from the Upper Ugnu formation and available produced water volumes (Exhibit 6). Expansion of the waterflood should reduce pressure decline and solution gas production on the two drill sites. This should reduce producing GOR's in these areas, allow more oil to be processed through Central Production Facility No. 1 (CPF-1), and accelerate waterflood response from these drill sites. Increment I ~'Jaterflood as expanded to Drill Sites 1F and 1G will continue in the CPF-1 area during 1985, but no new drill sites will be waterflooded. CPF-2 should be operational in late 1984, and will process oil from the southwest, em portion of the reservoir (Exhibit 7). -2- In 1986, treated Beaufort Sea water will be used to waterflood a total of eighteen drill sites in the CPF-1 and CPF-2 areas (Exhibit 8). CPF-3 is. currently scheduled to start up in early 1987, and will include water injection facilities. Ten drill sites in this area should be waterflooded before the end of that year (Exhibit 9). Drill sites developed after 1987 w~ll be waterflooded within twelve months after they are brought on production. Ultimately, the entire reservoir within the Waterflood Permit Boundary will be waterflooded (Exhibit 10). Injection Water (20 AAC 25.400.b.7) Waterflood of the Kuparuk River Reservoir currently uses source water from the water bearing sands of the Upper Ugnu Formation. After 1986, source water will be Beaufort Sea water. Produced water from the Kuparuk River Reservoir will also be reinjected through separate surface handling facilities to avoid mixing w-ith source water. The source and produced water rates are discussed below. Source Water Water from the Upper Ugnu Formation is currently produced from ten wells on Drill Site lB to supply.water for the Increment I Waterflood. An additional well is used to monitor pressure in the water bearing sands (See Exhibit 11 for listing, Exhibit 13 for lOcation). This source water supply will be used until early 1986, and'then discontinued. The source water well capacity from the Upper Ugnu Formation is estimated at 58,000 BW/D with existing downhole pumps. Average source water injection rate to date has been 48,500 BW/D. The Beaufort Sea source water will be filtered, chlorinated, and deoxygenated at the Seawater Treatment Plant (STP) located at Oliktok Point. The treated source water will flow through large diameter pipelines to local injection plants (LIPs) located at each CPF. The Beaufort Seawater Treatment Plant will have a nominal capacity of 400,000 BW/D. This capacity will be utilized for injection until about 1990 and then will decline as fillup occurs and as produced water rates increase. Produced Water Initial produced water rates from the Kuparuk River Reservoir will rise steadily over the life of the field. By the mid-1990's', approximately 300,000 BW/D or half of the peak water injection rate of 600,000 BW/D will be produced water. Well Descriptions (20 AAC 25.400.b.2,3,8) The locations of existing exploratory, production, and injection wells within the Waterflood Permit Area are shown on Exhibits 12 and 13. The completion interval for these existing wells is the Kuparuk River Reservoir. The exploratory wells within the Waterflood Permit Area have been either recompleted and renamed for use as producing wells, suspended, or abandoned (Exhibit 14). The status and a recent production test from each producing well in the current -3- producing area are listed on Exhibit 15. The wells in the field used ~urrently for gas injection are listed in Exhibit 16. Water Injections Wells Current Injection Wells (20 AAC 25.400.b.5) Drill Site lA has eight water -injection wells within 320-acre five-spot patterns. Drill Site 1E has 't~elve water injection wells within 80-acre five-spot patterns on the western side, and 160-acre five-spot patterns on the eastern side. The status of each water injector is shown in Exhibit 17. Logs of each water injection well are shown in Exhibit 18. Future Injection Wells (20 AAC 25.400.b.2) The locations of future water injection wells will depend upon the pattern selected for fullfield waterflood. The pattern is currently under evaluation. On a typical four section drill site, well locations for five-spot and line-drive patterns are shown on Exhibit 19. In either pattern, the drill site will have eight water injection wells, or two injection wells per section, to develop 320-acre patterns. Some peripheral drill sites will cover areas other than four governmental sections, and will have more or less water injectors than the typical eight. A map showing the currently planned drill sites and the proposed number of water injectors to develop 320 acre patterns is shown on Exhibit 20. The fieldwide total of 417 injection wells includes the twenty water injectors on Drill Sites lA and 1E. The number and location of water injection wells necessary to optimize waterflood recovery from the Kuparuk River Reservoir may change. Therefore, approval of unrestricted well spacing will provide flexibility to maximize recovery through varied pattern configurations and spacing. Injection Well Completions (20 AAC 25.410) The completion design used for Increment I Waterflood water injectors is shown on Exhibit 21. During completion operations, integrity is tested by displacing fluids in the production casing with NaC1/NaBr brine after cementing, and holding a 3000 psi pressure for 15 minutes. This or a similar casing test will be. performed on all future water injection wells. To detect any leaks which might occur after injection begins, the pressures in the annulus between the production casing and the tubing, and in the annulus between the producing casing and the surface casing are monitored daily. This practice will continue for ful lfield waterflood. Increment I Waterflood results have indicated that injection well completions need to allow for control of water injection profiles, particularly in areas of the Kuparuk River Reservoir where two sand units are present. Possible well completions for profile control are shown in Exhibit 22, although future completions will not be limited to these designs. The "single" completion is the design currently used. The "selective single" completion is being field tested in well 1E-14, and has been installed on wells in Drill Sites 1F, 1G, and 1Y to gain additional operational information. The "dual" completion is under · -4- study. All future water injection wells will be cased, cemented, and monitored as per 20 AAC 25.410 and Field Rule 4. Records and Reports (20 AAC 25.430) The operator will keep records of injected and produced fluid volumes, and reservoir and injection pressures, and will file reports to the AOGCC as required per 20 AAC 25.340. Notification (20 AAC 25.400.c) A copy of this application has been mailed to all the Kuparuk River Unit Working Interest Owners referenced on Exhibit 4 and parties owning acreage adjacent to the Kuparuk River Unit boundary. Attached to the cover letter transmitting this Application is an affidavit of mailing to the parties set forth on Exhibit 4. -5- KUPARUK RIVER FORMATION ....... .~ TYPE SECTION, WEST SAK RIVER ST. N°- ~ i --~0 ~~ ~i ~'1 , , , :, ~'- ~~ ',,, : ,. -'--"-c:: ...... ~'-~,-~ ' ' ~"'"'" ~ ' ~ ~ ' ~...~._'~- I .Z_L .......... ~.~. ,~. ~~ ~ : ~:'r ........... ,'" o ~- , , i ;~~ , · '~ "1 -m . ~,[.. 6656'- ........... :~,.~ , . -~ ~.~.._" :. -w ..... -~ _~ ~ ............ ~ ".. ., q ,, . -- ~~ 6774 -~-: ........................ %~L ....... ~ .................................... ~ .................... 0 ............ ~~~- ~.~ ~'; .~' ..... I -~ I -, ~ I! ~ ]~ KUmRUK RIVER UNIT ~ - I. ~[~' EXHIBIT I ~~ I[!~:~-- '-II EXHIBIT 3 KUPARUK RIVER FIELD WATERFLOOD PERMIT AREA DESCRIPTION BY SECTION T10N, R8E, U.M. !,~2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, ~1'4, 15, 16, 17 T10N, R9E, U.M. ~.1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 17, ~18 T10N, R10E, U.M. 6 T12N, R8E, U.Mo I, 2, 11, 12, 13, 14, 23, 24,. 25, 26, 35, 36 T12N' R9E, u.M. Ail T12N, R10E, U.M. 5, 6, 7, 8, 9, 15, 1.6, 1.7, 18, 19, ~20, 21, 221,, 213, 25, 26, 27, 28, 29,., 30, 31, 32., ~.3~ 34, 35, 36 T12N, RllE, U.M. 31 TllN, R8E, U.M. 1, 2, 11, 12, 13, 14, 22, 23, 24,~25, 26, 27, 28, 32, 33,".34, '35,~'36 Ti iN,' R9E, U~.,M. Ai'i Tll'N, R10E~ U~M. Ail TllN, RllE., 5, 6, 7, 8, '17, 1'8, 19,,"~ 20, 3O T13N, RSE., U..'M.. 13, 23, 24, 25, '2~'6,' 3'5, 36 T13N, .R9E', U.M'. 15, 16, 17, 18., 19, 20, '22, 25, 2.6, 27, 28, 2.9, 31, 32, 33., 34, 35, 36 EXHIBIT 4 KUPARUK RIVER FIELD LEASE HOLDERS J. C. Burnside AMOCO Production Co. 1670 Broadway Denver, CO 80202 L. E. Tate ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510 (Operator) M. G. Knowles BP Alaska Exploration Inc. One Maritime Plaza, Suite 500 San Francisco, CA 94111 T. A. Edmondson Chevron U.S.A. Inc. P. O. Box 8200 Concord, CA 94524 J. C. Bowen Exxon Company, U.S.A. P. O. Box 5025 Thousand Oaks, CA 91359 W. J. Clauser Mobil Oil Corporation. P.O. Box 5444, Terminal Annex Denver, CO 80217 T. J. Jobin Phil lips Petroleum Company 8055 E. Tufts Avenue Parkway Denver, CO 80237 G. J. Abraham Sohio Petroleum Company 50 Fremont Street San Francisco, CA 94105 R. M. Barnds Union Oil Co. of California P.O. Box 6247 Anchorage, AK 99502 OFFSET LEASE HOLDERS C. Burglin P.O. Box 131 Fairbanks, AK 99707 H. W. DeJong Diamond Shamrock 410 17th Street Denver, CO 80202 J. Y. Christopher Amerada Hess 1200 Milan, 6th Floor Houston, TX 77702 M. Thatch er Gulf Oil Corporation 5200 Stockdale Highway Bakersfield, CA 93309 H. D. Haley CONOCO Inc. 2525 C Street, Suite 100 Anchorage, AK 99503 J. W. Conwell Placid Oil Co. i 550 W. 7th Avenue, Suite 1100 Anchorage, AK 99501 E. P. Nelson Texaco Inc. P.O. Box 4-1579 Anchorage, AK 99509 Kuparuk Unit, Boundary I I I I I I I I I i I I I ! I i I I I I I I I I I I i I I I Exhibit 5 Waterflood Permit Boundary I I ! I r i- I i--J I ! I I I I I Year End 1983 Status Increment I Waterflood Natural Depletion Central Production Facility No.1 Operational Kuparuk Unit , Boundary I I I I I I I I I I I I I i I I Exhibit 6 I I I I I I I I Waterflood Permit i I' Boundary CPF-1 B__ r- r-tJ I I I I I Year End 1984 Status Increment I Waterflood and Expansion Natural Depletion Kuparuk Boundary I I ! I I Unit_..~ I I I I i ! ! ! i I I I I ! Exhibit 7 Waterflood Permit CPF-2 I! Boundary r I CPF-1 r~ I I I I Year End 1985 Status Increment I Waterfiood & Expansion [-----] Natural Depletion CPF-2 Operational [- I Kuparuk Unit....~ Boundary Boundary Waterflood Perrr it Exhibit 8 CPF-1 LIP I I r--I r I ! I I I I Year End 1986 Status Increment il Waterflood Natural Depletion Seawater Treatment Plant Distribution Lines Two Local Injection Plants Oliktok Pt. STP I ! I I I I Kuparuk U nit_...~ Boundary Exhibit 9 Waterflood Permit Boundary r I CPF-1 LIP I I ..I m-I I I I Year End 1987 Status ~ CPF-3 Waterflood Natural Depletion CPF-3 with LIP Operational Oliktok Pt. STP Kuparuk U nit_,.~ Boundary I I Exhibit 10 I i Waterflood Perm it Boundary I I I I Ultimate Status ~ Waterflood EXHIBIT 11 KUPARUK RIVER FIELD WATER SOURCE WELLS WELL STATUS Ail wells completed in the Upper Ugnu Formation. Refer to Exhibit 13 fo~ locations. API Number mid-Jan. Well 50- 1984 Drill site lB WSW 1 029-20537 WSW 2 029-20812 WSW 3 029-20817 WSW 4 029-20833 WSW 5 029-20838 WSW 6 029-20851 WSW 7 029-20861 WSW 8 029-20864 WSW 9 029-20868 WSW 10 029-20876 WSW 11 029-20882 observation well active active active active active ~actlve active act 1 ve active 'act lye I, EXHIBIT 14 KUPARUK RIVER FIELD EXPLORATORY WELLS WELL STATUS All wel.~s comPleted-i~ the ~uparuk River Reservoir. Wells Inside Current :Producilng..Ar.ea' API No., mi,~gn.~; :Shown on Well '":" 50--. ~':..' 19 8~ Ex.h ibit Drill site IA W. Sak 12 029.-20313 ~ow. lA-08 '1%..~ Drill site lB W. Sak 7 029-202g$~ now lB-05 .13 Drill site~ lC 'W. Sak 1 02:9-20096. suspended , 13 Drill S'.].'...t~e 1D W.~ Sak ~8 029-20266 now !D-08 c..,~13 .~Drill Site 1E W..Sak 2 .02'9-20134 suspended .!3 Drill site 2× W. Sak 9 029-20274 Suspended ].3 Wells. OutSide Cu'rreht Producing A~ea E. Ugnu 1 Mobil MP #1 17-11-11 Oliktok Pt. Ugnu 1 W. Sak 3 W. Sak 4 W. Sak 11 W. Sak 14 W. Sak 15 W. Sak 16 W. Sak 17 W. Sak 23 W. Sak 24 0 29'2 2 0 0 5 2 ,~ S,u.spe nd~ed :'. 12 029-20573 029-20701 029-20009 029-20139 029-20343 029-20275 029-20419 029-20013 02'9"20541 029-20542 029-20699 029-20723 suspe!.oded aba~ndoned suspended suspended abandoned .. sus~pended~ suspended. .... suspended suspended suspended suspended suspended 12 ~.13 12 12. 12,1.3 12,13 12 12 12 12 12 12 12,13 EXHIBIT 15 KUPARUK RIVER FIELD PRODUCTION WELLS WELL STATUS AND TEST SUMMARY Ail wells completed Refer to Exhibit 13 Well API Number 50- Drill site IA 1 029-20590 2 029-20599 3 029-20615 4 029-20621 5 029=20627 6 029-20630 8 029-20313 10 029-20673 Drill site lB 1 029-20465 2 029-20531 3 029-20588 4 029-20595 5 029-20237 6 029-20603 7 029-20616 8 029-20635 Drill site lC 1 029-20526 2 029-20532 3 029-20535 4 029-20547 5 029-20550 6 029-20564 7 029-20569 8 029-20585 in ~he Kuparuk · for locations. River Status mid-Jan. 1984 Test Date active active shut in shut in active active active active 01-12-84 01-11-84 01-08-84 01-09-84 01-12-84 01-11-84 shut in shut in shut in shut in shut in shut in shut in shut in shut in shut in shut in shut in shut in active shut in shut in 09-15-83 Reservoir. Production Rates Oil Water Gas STB/D STB/D MSCF/D 1724 580 758 3335 352 1668 2126 530 1223 1151 521 403 1635 0 2401 2351 18 1782 1736 28 1402 Exhibit 15' Well Status Page 2 and Well API Number 50- Drill site iD 1 029-20393 3 029-20408 4 029-20416 7 029-20430 8 029-20266 Drill site 1E 2 029-20472 3 029-20477 5 029-20479 6 029-20493 7 029-20495 8 029-20496 11 029-20787 12 029-20736 15 029-20769 17 029-20793 18 029-20904 20 029-20895 22 029-20884 24 029-20857 25 029-20844 26 029-20840 28 029~20832 29 029-20828 Drill site iF 1 029-20889 2 029-20881 3 029-20853 4 029-20846 5 029-20807 6 029-20820 7 029-20830 8 029-20836 9 029-20983 10 029-20984 11 029-20993 12 029-21012 Test Summary~ Status mid-Jan. r984 shut in shut in shut in shut in shut in active shut in shut in active shut in shut in shut in active active shut in shut in shut in active shut in shut in active shut in active active active active active active active shut in shut in active shut in active active Test Date 01-13-84 01-12-84 01-06-84 01-08-84 01-07-84 01-04-84 01-08-84 Production Rates Oil Water STB/D STB/D Gas MSCF/D 01-08-84 332 5 341 01-10-84 470 0 734 01-13-84 874 0 1365 01-03-84 985 0 1411 01-12-84 859 0 1016 01-06-84 2527 269 4758 01-03-84 445 0 318 01-05-84 1803 0 1844 01-09-84 59 0 88 256 34 988 635 0 663 404 46 537 543 1 894 1567 794 1649 552 149 2742 874 166 3498 .Exhibit 15 Well Status Page 3 and Well API Number 50- Drill site 1G 1 029-20805 2 029-20813 3 029-20824 4 029-20835 5 029-20908 6 029-20890 7 029-20872 8 029-20849 9 029-21001 11 029-21008 12 029-21009 13 029-21016 Drill site iH 3 029-20792 4 029-20770 5 029-20727 6 029-20741 7 029-20755 8 029-20763 Drill site 1Y 1 029-20933 2 029-20941 3 029-20943 4 029-20948 5 029-20966 6 029-20958 7 029-20950 8 029-20944 9 029-20935 10 029-20934 11 029-20926 12 029-20913 13 029-20903 14 029-20910 15 029'20919 16 029-20927 Test Summary Status m~d-Jan. 1984 shut in active active active shut in active active active active active shut in active active shut in plugged shut in active shut in active active active active shut in active active shut in active active active active active active active active Test Date 12-27-83 12-29-83 01-03-84 01-08-84 12-31.-83 01-01-84 01-12-84 01-11-84 01-09-84 Production Rates Oil Water STB/D 'STB/D Gas MSCF/D 2159 0 3460 2058 0 3947 1808 0 642 3762 0 6375 2233 0 1822 1800 0 664 72 0 3 1909 0 2957 1961 26 3638 01-13-84 328 0 328 11-09-83 312 0 374 856 0 2271 0 3393 0 3080 25 3769 0 3019 0 1777 0 2196 0 2406 0 3104 2 1849 0 199 0 2134 0 1096 0 01-05-84 01-13-84 01-01-84 12-29-83 01-07-84 01-02-84 01-08-84 01-04-84 01-11-84 01-10-84 12-31-83 01-01-84 01-11-84 01-03-84 1245 3750 6202 4920 4377 6006 3385 2093 1772 4597 1380 161 1290 848 Exhibit 15 Well Status Page 4 and Well API Number 50- Drill site 2C 1 029-20962 2 029-20972 3 029-20968 4 029-20973 5 029-20978 6 029-20979 7 029-20975 8 029-20974 Drill site 2F 13 029-21032 14 029-21048 Drill site 2X 1 029-20963 2 029-20982 3 029-20987 4 029-20995 5 029-20985 6 029-20988 029-20991 8 029-20992 Drill site 2Z 1 029-20953 2 029-20960 3 029-20964 4 029-20965 5 029-20956 6 029-20957 7 029-20946 8 029-20924 Tgst Summary Status mia-Jan. 1~84 active shut in active active active active active active drilled drilled active active active active shut in active active active active active active shut in shut in shut in active shut in Test Date Production Oil Water STB/D STB/D Rates Gas MSCF/D 01-06-84 35 0 99 01--02-84 356 0 72 01-01-84 304 0 423 01-11-84 225 0 164 01-05-84 0 0 0 01-09-84 100 0 157 01-10-84 1060 1 682 4388 20 8435 3885 0 3124 3132 2 3060 3926 2 351 4377 0 3479 1796 0 959 361 0 16 2134 0 236' 0 2903 0 1070 0 01-03-84 01-05-84 01-08-84 01-02-84 01-09-84 01-12-84 01-07-84 12-24-83 01-11-84 01-05-84 01-12-84 2601 296 2451 1950 EXHIBIT 16 KUPARUK RIVER F~ELD GAS INJECTION WELLS WELL STATUS Ail wells completed in'the Kuparuk River Reservoir. Refer to Exhibit,13 for locations. API Number mid-Jan. Well 50- 1984 Drill site lB 9 029-20655 active 10 029-2065.6 act ive 11 029-20657 active Drill site lC 9 029-20859 active 10 029-20865 active Drill site ID 2 029-20429 active 5 029-20417 active 6 029-20418 active Ail wells completed Refer to Exhibit 13 EXHIBIT 17 KUPARUK RIVER FIELD WATER INJECTION WELLS WELL STATUS in the Kuparuk for locations. River Well API Number 50- Drill 7 9 11 12 13 14 15' 16A Drill iA 4 9 10 13 14 16 19 21 23 27, 30 site IA 029-2 029-2 029-2 029-2 029-2 029-2 029-2 029-2 0658 0669 0685 0688 0700 0706 0711 0713-01 site 1E 029-20464-01 029-20478 029-20720 029-20725 029-20750 '029-20751 '029-20777 029-20905 029-20892 029-20858 029-20837 029-20814 Reservoir. mid-Jan. 1984 active active active active active active active active active active active active active active active active active active active active Refer to Exhibit EXHIBIT 18 KUPARUK RIVER FIELD WATER INJECTION WELLS LOGS 13 fo~. locations. Drill Site IA lA-07 1A-09 iA-ii lA-12 lA-13 lA-14 lA-15 1A-16A Drill Site 1E 1E-lA 1E-04 1E-09 1E-10 1E-13 1E-14 1E-16 1E-19 1E-21 1E-23 1E-27 1E-30 KUPARUK RIVER OIL P(JJJL 5858 TO 6188 FEET,( IBSEA WATER INJECTION WELL 1A-07 APl 5002920 65800 $ BM 8RMMR RR¥-PDN S D NEUT. POROSITY-FDN I I I ~ DENSIT¥-FDN so~ ~ SD RESI~TIVIT¥,,DEEP HEDIUH-DIL ........ , ........... ~0~ SHRLLON-DIL KUPARUK RIVER rOIL POOL 5984 TO 6264 FEET, i~ 'JBSEA WATER INJECTION WELL 1A-09 APl 5002920 66900 ORLIP~R-FDN ~RHHR RR¥-FDN R£SIS,?IVI?¥, 08£P ................... ~P~,~, MBO I UH-D I L ......... , ........... SHRLLON-DIL KUPARUK RIVEH UIL I"'UUL I 5991 TO 6245 FEET, ,~' '3SEA I WATER INJECTION WELL 1A-11 APl 5002920 68500 ORL I PER-FDN f I ,I I ~RMMR RR¥-FON S SD NEUT. POROSITY-PDN ' DENSITY-PDN RESISTIVITY, DEEP ,J ......... , ,,,,,,,, , , S MED ! UM-O I L 50~ ~ ~I ..................... H S O SHRLLON-D IL KUP'AMUK HIVbH UIL POOL I 5833 TO 6167 FEET, [ 'BSEA I JWATER INJECTION WE~_L 1A-12J J APl 5002920 68800 J ORLIPER-FON GRMMR RR¥-FDN S I 12'BU ~°~ M SD O 2OO TOP'~ £ ~ " --~., . ~TO RESISTIVITY, DEEP J .................... NEUT. POROSI?¥-FBN S MEB]UM-BIL · OENSIT¥-FDN S O SHALLOH-OIL KUPARUK RIVER OIL POOL 5935 TO 6291 FEET, ~ 9SEA WATER INJECTION WELL 1A-13 APl 5002920 70000 ORL I PER-FON S BRMMR RR¥-FDN S O ~ KUPRRL!K ~ CTTO'I ~ NEUT. POROSITY-FBN · DENSITY-FDN 5°4:, 8U H~~ SD RESISTIVITY, DEEP .................... MEDIUM-BIL ................... 1 SHRLLON-D IL KUPARUK RIVER OIL POOL §015 TO 6353 FEET, .~' '3SEA WATER INJECTION WELL 1A-14 APl 5002920 70600 @RMMR RR¥-PDN CRL I PER-FDN S NEU?. P[~ROS I I'¥-PDN ' ' "' ' % ~M~ .' ' ' S D · DENSITY-FD[.~ 3 200 , SD RESISTIVI?¥, DEEP ...................... ,t I~1:::t0.,. MEDIUM-OIL SHRLLON-D IL C~L IP£R-FDN' · ~' ' ,l , , BRMMR RR¥-FON IwKUPARUK RIVER OIL POOL 5894 TO 6210 FEET, ~"qSEA ATER INJECTION WEL-1A-151 APl 5002920 71100 $ SD O 2OO TOl~. ~' KOP_BR~ ~ ~S ' , NEUT. POROSI?¥-PDN · D£NSIT¥-PDN RESISTIVITY, D££P J ......... ~ ,,~I .... ~ ,~" · S M£DIUM-DIL S O SHRLLOW-DIL KUPARUK RIVER, O~L,,~OOL 5902 TO 6208 FEET,-~. ~SEA WATER INJECTION WELL 1A-16A APl 5002920 71301 CRL I PER-FEN BRMM~ RR¥-FON RESI~TIVITY~,DEEP .................. ~0~.0~.. HEDIUM-BIL ...... ,,~ , ~,,, ..... ,¢P~ SHRLLON-DIL KUPARUK RIVFR OIL~.i-I'~OOL I 59§4 TO 6268 FEET. ~.,SSEAI WATER INJECTION WELL 1E-lAI APl 5002920'4,8401 I ORL I PP.R-FON 8FIMMR RR¥-FDN S NP. UT. POROSI?¥-FDN S S D DENSITY-PON S D L~RTEROLO~, D£P.P ......... , , ..... ,i , . LRTEROLOL~,SHRLLOWI ....... ,i ~ ~ ..... ,i ,~P~q~ M!CRO SPHER. POC. KUPARUK RIVER OOL,~':'OOL 5860 TO 6095 FEET, t. JBSEA WATER INJECTION WELL 1E-04 · APl 5002920 47800 OBLIPER-?ON BRMMR RR¥-FBN S NEU?. POROSI'[7-F'DN[LS~I S S O ~ DENSItY-PON RESIS?IVI?¥, DEEP M£DIUM-OIL ............ , .... ; , , ~P~ SHRLLON-DIL KUPARUK RIVER OIL.i.DOOL 6075 TO 6344 FEET, ~ aSEA WATER INJECTION WELL 1E-09I APl 5002920 72000. ORL I PER-FBN @RMMR RR¥-FBN S NEUT. POROSIT¥-FON , ~*-~, ~~,¢ , , , , S B ;" BENSIT¥-FON KUPRRI K . tPRRL K RESISTIVITY, DEEP ,J .................. , , S MEDIUM-OIL so4~ ~ ~1 ................. , , , M S D SHRLLON-B I L IKuPARUK RIVER O~L Pf'").L 6084 TO 6360 FEET, WATER INJECTION WELL 1E-10/ APl 5002920 72500 ORL I PER-FBN S , , , , ,~...~ ~ -.'... !'1 @RHHR RR¥-FDN S D NEUT. POROSITY-FBN S · DENS I TY-FDN S B SHRLLOW-DIL ! i ! i Illll i I itllll r"rl[-1TlJ : KUPARUK RIVER OIL.POOL 60'89 TO 6373 FEET,'SUBSEA WATER INJECTION WELL 1E-131 APl 5002920 75000 CRL IP£R-FDN I I ~RMMR RR¥-FBN R£1SIS,?IVII'Y,,DEF. P ................ ', ~1 .~.. MEDIUM-0II. , ,, ................ SHRLLON-DIL KUPARUK RIVER O~L POOL 6067 TO 6347 FEET, SUE;SEA WATER INJECTION WELL 1E-14 APl 5002920 75100 ~ ORLIPER-FON BAMMA 'RR¥-FBN S SD ~ ~ KUPRRLK F ¢ , NEUT. POROSIT¥-FDN · DENSIT¥-FDN R£SIS,?IVIT¥,, DEEP 'j .................. S HEDIUH-DIL 504:, ~ ~, ........, ........... S O SHRLLON-D IL .5. KUPARUK RIVER OIL POOL 6053 TO 6341 FEET, 'SUBSEA WATER INJECTION WELL 1E-16 APl 5002920 77700 CRLIPER-FDN ~ I I BRMMR RR¥-FDN S NEUT, POROSIT¥-FDN S S O ' OENSIT¥-FDN S 0 RESISTIVITY, BEEP ' ; ........ , ,~,-',,[ i I .,,~ MEDIUM-BIL .......... ,, ,,~ ..... SHRLLON-B IL KUPARUK RIVER OIL POOL 6003 TO 6380 FEET, SUBSEA WATER INJECTION WELL 1E-19 APl 5002920 90500 CRLIP£R-FDN S @RHI'iR RR¥-PDN S O PflRL K NEUT. POROSIT¥-F'DN t I ~ ~ :' DENSIT¥-FDN 5% BU SD RESI~?I,VITY,,DEEP H~DIUH-DIL ........ , ........ , , SHRLLON-DIL KUPARUK RIVEJ~ Oil POOL' 5958 TO 6273 FEET, SUBSEA WATER INJECTION WELL 1E-21 APl ,5002920 89200 ORLIPER-FBN @RMMR RR¥-FON "~, K~ELK ~ D I" t RESISTIVITY, DEEP .................... ~P~ ~EBZU~-B~L ................. , ,,~P~ SHRLLON-BIL 1., KUPARUK RIVER OIL POOL 5907 TO 6190 FEET, SUgSEA WATER INJECTION WELL 1E-231 APl 5002920 85800 CRL I PF:.R-FDN ~ I I I I BRMMfl RR¥-PDN S NEUt. PORO$I?¥-FDN S D · DENSIT¥-FDN S D RESIS?IVIT¥~ DEEP .................... HEDIUH-OIL ......... ,,,,, ..... SHRLLON-OIL 1 ORLIPER-FDN I 13RMMR RR¥-FBN S SD KUPARUK RIVER OIL POOL 5924 TO 6212 FEET, SUBSEA WATER INJECTION WELL 1E-27 APl 5002920 83700 KUPRRLK . NEUT. POROSI?¥-FDN ~ DENSITY-FDN RESISTIVI?¥~ DEEP S MEDIUM-OIL so~ ~ ~1 ................., ,, M " S D SHRLLON-D IL KUPARUK RIVER OIL P~OL 6048 TO 6328 FEET, SU~SEA WATER INJECTION WELL 1E-30 APl 5002920 81400 CRL IPER-FON ~ ' I I @RMMR RR¥-PDN S NEUT. POROSIT¥-FDN S S O · DENSITY-FDN S O RESISTIVITY, DEEP ............. ,,,,, , HEBIUM-OIL .................... SHRLLOW-DIL ,.. Kuparuk River Field Waterflood Patterns On Drill Site Of Four Governmental Sections Five-Spot Pattern Line-Drive Pattern Producer ~ Conversion to Water Injector Exhibit 19 I I I I I I I Kuparuk Unit .....~ Boundary I I I I I I I rm Exhibit 20 ,,~12 O 8 ~8 ~10 o10 ~8 O8 ~10 Z~8 O10 ~8 I I 04 ~8 o8 A8 02 ~8 08 ~,8 08 O8 ~8 o8 ~8 Kuparuk River Field ~. ...... -~ Well Count per Drill Site ~ ....... .~ 320 Acre Pattern Waterflood Development ..................... ~ /X Water Injectors 403 Total Waterflood Permit Boundary © Producers 417 Total I Central Production Facilities Kuparuk River Field Present Completion Design Water Injection Well- Increment I Waterflood 1. Tubing Hanger 2. Tubing Retrievable SSSV 3. Gas Lift Mandrel 4. Seal Bore Assembly 5. Packer 6. No-Go Landing Nipple 7. 31/2'' 9.2# J-55 BT&C Coated Tubing 10-3/3" 45.5# * K-55 Surface Casing Exhibit 21 *Current well completions use 9-5/8" surface casing 7" 26# K-55 Production Casing Kuparuk River Field Completion Alternatives Water Injection Well - Full Field Waterflood SELECTIVE SINGLE SINGLE DUAL TUBING PRODUCTION CASING GAS LIFT MANDREL GAS LIFT MANDREL GAS LIFT MANDREL KUPARUK C SAND ~--,PACKER I PRODUCTION/ INJECTION MANDRELS BLAST JOINT PRODUCTION/ INJECTION MANDREL ~ PACKER 2 PACKER PACKER BLAST JOINT CIRCULATING SLEEVE PACKER 2 KUPARUKA SAND Exhibit 22 AFFIDAVIT OF SERVICE BY MAIL STATE OF ALASKA ) ) ss THIRD JUDICIAL DISTRICT ) Mary L. Weber, .being first duly sworn, upon her oath, deposes and says: I am a citizen of the United States of America, over the age of 19 years, and employed as a secre- tary for ARCO Alaska, Inc. That on the ~ day of 7/'/~~/.~ , 1984, I deposited in the United States mail a true and correct .copy of the document titled "Kuparuk River Field, Fullfield Waterflood ProjeCt, Ap- plication for Additional Recovery" to each of the lease holders shown on Exhibit 4 of that same document. 1984. DATED at Anchorage, Alaska, this day of ~, Subscribed and sworn to before me this ~~ day of Notary Public in and for Alaska My Commission EXpir~e~3: ~ ~F,/~~ ~EgEND PRODL~ I NO HELL o ~ B,,H, LOC~TI~I I~lnER INJECTION hI~LL · e~"fme ~ LgC~TZ(~I INJECTION NELL M~POI~D B.H. M3CATTO# WflT~ SOURCE ~ ,/,,~ ~.: KUPARU~[ ENGINEERING DEPT. ,/~ ,~_ ~.~ AUPARU}{ OPERATIONS itAP '"'":' ':?~""' C:FF=I / CFF=~ Ai~i-:A FEBRUP~RY 28, 1984 0 2,BO0 ~;.000 10,000 SCALE IN FEET Conservation Commission Meeting October 19, 1983 Attendance List Name \ Ted Morcomb Karl Schaeffer Herb Vickers, Jr. Jim Merritt '~~ Masterson Don Drinkard St~ve Shockley St'eve Sills ~/ Darrel Bose Dan Caffrey Harry Kugler Chat Chatterton Title Regional Operations Engr. Regional Reservoir Engr. -- Senior Reservoir Engr. Senior Facility Planning Engr. KRU Planning Subcommittee Rep. Area Geologist - Operations Geologist Area Operations Engr. Area Reservoir Engr. Senior Reservoir Engr. Kuparuk Engineering Mgr. Senior Operations Engr. AOGCC AOGCC Russ Douglass AOGCC L. C. Smith ~)~f~v-~ AOGCC ' . Phone Number 263-4203 263-4323 263-4398 263-4328 263-4252 263-6316 265-6828 263-4324 263-4343 263-4384 263-4205 263-4272 279-1433 279-1433 279-1433 279-1433 February 8, 1982 Mr. ~?. I:I. ~:c?~.~;i 1 I i an Acting Kuparuk Engineering ~,anager ARCO Alaska, Inc. P. O. Box 366 Anchorage, Alaska 9951~ Dear Bi 1 1, Your application for additional recovery for ~(uparuk River Field Increment I ~.~at er f lood dated December I6, 1981 was Com~.,~lssion on December 16, 1981 received by the ' '' . The Coma~ission understands that your plans at this time are for a 'field demonstrat ion.. or "pilot" project. A' similar application for field-wide ~.'¢aterflood will bo made if the field demonstration indicates this is ~'¢arranted, The Commission hereby approves your additional recovery appli- cation for Increment I tYaterflood in the Euparuk River ()il Pool with the following stipulations: The C°n~m, ission will require semi-annual'reports on impleri.~entation, t;,rogress and injection well per- fo~:~ance during. Increment I ~?atevflo~d. Start in with the first rer~ort in January, I983, th~ reports are to be filed each July and January. Any proposed changes must be submitted to the Co=:~nission for al}proval, before these changes , .. be ~ple~en~ed . As the additioh'al- recov'ery'prbgran~ progre~ee~ the Cc~'~mission may find it necessary to i:~,pose other stipulations. ., Sincerely' yours, C. V . Chatterton Ch a i ~a n
