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Home My WebLink AboutAIO 014 AINDEX AREA INJECTION ORDER NO. 14A Prudhoe Bay Field Niakuk Oil Pool 1. March 26, 2001 BPXA’s request for AIO 2. April 21, 2001 Notice of public hearing, affidavit of publication, mailings 3. May 1, 2001 BPXA’s submittal of supplemental information 4. May 29, 2001 Revised notice of public hearing, affidavit of publication, mailings 5. July 24, 2001 Application for revised AIO 6. August 2, 2001 E-mails 7. August 13, 2001 BPXA’s submittal of supplemental information 8. October 19, 2001 BPXA’s application for revised AIO 9. October 30, 2001 BPXA’s submittal of confidential maps (held in secure storage) 10. September 27, 2004 Public notice to amend underground injection orders to incorporate consistent language addressing the mechanical integrity of wells 11. September 8, 2005 BPXA’s request for pilot injection in NK 65A and extension of GOR Waiver for NK-38A (AIO 14A.001) 12. June 19, 2006 E-mail from AOGCC re: withdrawal of NK-65A IO 13. October 31, 2007 BPXA’s request to continue water injection operations (AIO 14A.002) 14. January 8, 2008 BPXA’s request to continue water injection operations (AIO 14A.002 Amended) 15. October 27, 2009 BPXA’s request to cancel AIO 14A.002 (AIO 14A.002 Cancellation) 16. September 22, 2010 BPXA’s email re: question regarding authorized fluids 17. January 4, 2011 Article "BP Closes Site Over Loss in Slope Rent Dispute" 18. April 30, 2012 BPXA’s request for standardization of authorized fluids for EOR and pressure maintenance 19. May 28, 2015 BPXA’s request for approval to continue water injection operations into NK-10 (AIO 14A.004) 20. September 3, 2024 Hilcorp request approval for continued water injection into NK-18 (AIO 14A.005) INDEX AREA INJECTION ORDER NO. 14A '. . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP ) Area Injection Order No. 14A EXPLORATION (ALASKA) INC. ) for an order allowing underground ) Prudhoe Bay Field injection of fluids for enhanced oil ) Niakuk Oil Pool recovery in the Niakuk Oil Pool, ) Prudhoe Bay Field ) ) December 31,2001 IT APPEARING THAT: 1. By letter dated March 26, 2001, and received by the Commission March 27, 2001, BP Exploration (Alaska) Inc. ("BP") requested that the Alaska Oil and Gas Conservation Commission ("Commission") revise Area Injection Order No. 14 ("AIO 14") for expansion of injection operations in Niakuk Oil Pool ("NOP"). The expansion area requested included sections 15,22 and 27 ofT12N, RISE UM. 2. The Commission published the first notice of opportunity for public hearing (June 12, 2001 hearing date) on April 21, 2001. 3. The Commission published the second notice of opportunity for public hearing (July 24, 2001 hearing date) in the Anchorage Daily News on May 29, 2001. 4. The Commission did not receive a protest or written request for public hearing. 5. BP provided supplemental application materials in support of the amendment to AIO 14 on July 23,2001. 6. On August 20, 2001, the Commission approved Administrative Order 14.001 allowing water injection into well NK-28 until November 1, 2001 to gather information to support expansion of AIO 14. 7. By letter dated October 19, 2001, and received by the Commission on October 26, 2001, BP submitted a revised application for the expanded Niakuk Area Injection Order. 8. On November 14, 2001, the Commission approved Administrative Order 14.002 allowing continued injection of water into well NK-28 until February 1, 2002. 9. Additional information pertaining to the application was received December 3,2001. Area fujection order. December 31, 2001 - Page 2 FINDINGS: 1. Authority 20 AAC 25.460 Commission regulation 20 AAC 25.460 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. 2. Summary of Injection Projects AlO 14, originally issued March 22, 1995, authorized enhanced recovery injection operations within the NOP. Conservation Order 329A (June 3, 1996) and Administrative Order 329.005 (January 12, 1998) designate pool rules for the affected area. Conservation Order 329A approved expansion of the pool to include additional acreage in the western area of the field. The proposed revision to AlO 14 is to expand water injection operations into the Western portion of the Niakuk Oil Pool. Specifically, expansion ofthe Area Injection Order was proposed for conversion of well NK-28 from production to water injection service to provide pressure support for well NK -08A. 3. Injection Area (20 AAC 25.402(c)(1», Pool Description (Pool Information (20 AAC 25.402(c)(5» a) Niakuk Injection Area ("NIA"): BP has requested the expansion of injection operations to include sections 15,22 and 27 ofT12N, R15E UM. With inclusion of the proposed expansion, following area is included in the NIA: T12N, R15E UM, Sections 13-15 (all); 22-27 (all); and 36 (NE/4) TI2N, R16E UM, Sections 28 (W/2, NE/4, W/2 ofSE/4, SE/4 ofSE/4); 29-30 (all); 31 (N/2); and 32 (N/2) b) Niakuk Oil Pool: The NIA includes the Niakuk Oil Pool ("NOP") in the Kuparuk River Formation ("Kuparuk"). The Kuparuk is defined in the pool rules as the stratum that is common to and correlates with the accumulation found in the Niakuk 6 well between the measured depths ("MD") of 12,318 and 12,942 feet. 4. Operators/Surface Owners (20 AAC 25.402(c)(2) and 20 AAC 25.403(c)(3) BP has provided all designated operators and surface owners within one-quarter mile radius of the NIA with a copy of the application for amendment of AlO 14. Those Area Injection Order 1. December 31, 2001 e Page 3 surface owners and operators are: BP, Mr. Leroy Oenga, Ms. Georgene Shugluk, BIA / Heirs of Jenny Oenga, Mr. Michael M. Delia, Mr. Wallace Oenga and the State of Alaska, Department of Natural Resources. 5. Description of Operation (20 AAC 25.402(c)(4)). The NOP has been developed from two drill sites, Heald Point and Lisburne DS L-5. There are 13 producers and 7 water injectors currently active on Heald Point and one producer on DS L-5. Produced water for re-injection is transported from the Lisburne Production Center through an 8" pipeline. Prior to year 2000, seawater injection was used to provide pressure support within the NOP. Current injection capacity is approximately 60,000 BWPD. Future injection requirements may require the use of one or more booster pumps at the drill site in order to provide sufficient water for injection. BP indicates there is potential to return to seawater injection at a future date. 6. Geologic Information (20 AAC 25.402(c)(5) The following is a summary of the geologic information for the NOP. a) Introduction: Three structurally defined areas are present in the NIA. Two east- west oriented grabens separated by a paleohigh that lacks Kuparuk sediments are present in the southern portion of the area. In the Northwestern portion of the NIA is a platform with numerous, west-northwest trending normal faults. b) Reservoir Interval: The NIA includes the NOP in the Kuparuk. The Kuparuk is defined in the pool rules as strata that are common to and correlate with the accumulation found in the Niakuk 6 well between 12,318 and 12,942 feet MD. c) Stratigraphy: The NOP consists of the Kuparuk that was deposited in an Early Cretaceous age marine environment. Within the expanded NIA, the Kuparuk consists of a stratigraphically complex accumulation of shale, siltstone and sandstone. These sediments are characterized by rapid changes in thickness, sedimentary facies, and cementation. Within the NIA, predominately fine grained Kuparuk basin fill initially accumulated north of the NiakukField Fault in the West Niakuk Graben (designated by BP as "Segment I") and East Niakuk Graben (designated by BP as "Segment 2"), to a gross thickness exceeding 500 feet. The basin fill sediments are generally below the oil water contact in both grabens. A period of non-deposition or erosion separates the basin fill sequence from a thick (100's of feet) series of predominately fine grained, aggradational, shoreface sandstones with a high net to gross ratio. The shoreface sands are present throughout the NIA and contain the majority of the oil in place. d) Structure Overview: The West Niakuk and East Niakuk Grabens (Segments I and 2) are fault-bounded depocenters cut by faults that are en echelon to the Niakuk Field Fault. The West Niakuk Platform (designated by BP as "Segment Area Injection Order 1. December 31, 2001 . Page 4 3/5") consists of a system of horsts, grabens and half-grabens created by a series of high angle, principally normal faults that lie parallel with, and en echelon to, the Niakuk Field Fault. The top of the Kuparuk ranges from a high of -8800 feet True Vertical Depth sub-sea ("TVDss") in West Niakuk and dips to a low of - 9800 feet TVDss in the eastern portion of East Niakuk. Most of the accommodation related to faulting in the NIA occurred during Kuparuk deposition, with significant fault displacement at the base of the interval and much smaller fault offsets at the top. e) Confining Intervals: The Kuparuk is bounded below by the Jurassic age Kingak Formation over most of the NIA. The Kingak Formation is a highly impermeable, low resistivity (2 - 3 ohm-meters) shale with a thickness varying from 400 to 800 feet. In the extreme SE comer of the Injection Area, the Kingak Formation has been interpreted as absent on seismic. In this small area, confinement of injected fluids will be provided by Lower Kuparuk siltstones and shales. The Kuparuk is overlain by the Lower Cretaceous age Highly Radioactive Zone ("HRZ") interval over the entire Injection Area. It is comprised of a 200 foot thick, black, organic rich, impermeable shale. f) Oil and Rock Properties: Oil gravity averages about 25 degrees API, with observations between 20-30 degrees API. Initial reservoir pressure was approximately 4500 pounds per square inch ("psi") at a datum of 8900' TVDss and the initial temperature ranged from 171 to 182 degrees F. The bubble point pressure is approximately 4200 psi, with solution gas/oil ratios of 600-700 Standard Cubic Feet per Stock Tank Barrel ("SCF/STB"), and oil formation volume factor of approximately 1.3 Reservoir Barrel per Stock Tank Barrel ("RVB/STB"). Initial solution gas/oil ratios are approximately 300 SCFIBBL. Pay averages about 16-21% porosity and 100-300 millidarcies ("md") permeability. Net sand to gross sand ratios vary from .20 to .9. g) Compartmentalization: Within the NIA, the Kuparuk reservoir is compartmentalized. Three separate oil-water contacts have been identified within the injection area: West Niakuk Graben (Segment 1) at 9240 feet TVDss, the West Niakuk Platform (Segment 3/5) at 9285 feet TVDss, and at 9535 feet TVDss in the East Niakuk Graben (Segment 2). h) Original Oil in Place: Estimated total original oil in place ("OOIP") in the NOP is approximately 310 MMSTB. Cumulative production to date is 59 MMSTB. East Niakuk Graben (Segment 2) OOIP is estimated at 120 MMBO. West Niakuk Graben (Segment 1) OOIP is estimated at about 85 MMBO. West Niakuk Platform (Segment 3/5) is estimated at about 105 MMBO. 7. Injection Fluids (20 AAC 25.402(c)(9). Injection will utilize either produced or source water. The wells are currently configured to allow 60,000 Barrels of Water per Day ("BWPD") total, with a maximum injection of up to 70,000 BWPD. The produced water will be a mix of Pt. McIntyre, West Beach, North Prudhoe Bay, Area Injection Order 1. December 31, 2001 e Page 5 Lisburne and Niakuk produced water separated through the Lisburne Production Center ("LPC"), with the majority coming ftom Pt. McIntyre. Seawater has been injected as well. SEM, XRD and ERD analyses conducted on Niakuk core indicate very low clay content in reservoir intervals. As a result no significant problems with formation plugging or clay swelling due to fluid incompatibilities is expected. Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. 8. Well Logs (20 AAC 25.402(c)(7)): The logs of existing injection wells are on file with the Commission. Specific to this application, the bond logs ofNK-28 have been reviewed, and sufficient cement exists above the Kuparuk interval. 9. Mechanical Integrity (20 AAC 25.402(c)(8)): NK-28 is the only well currently planned to be converted to an injector. A Segmented Bond Tool was run in the well in July 1995. The tool shows good bond above and below the perforations. A mechanical integrity test was performed on the well on 8/12/01, which showed good mechanical isolation. All wells used for injection will be cased and cemented in accordance with 20 AAC 25.412. In drilling all NOP injection wells, the casing is pressure tested in accordance with 20 AAC 25.030. The NOP injection wells are designed to comply with the requirements specified in 20 AAC 25.412. 10. Injection Pressures (20 AAC 25.402(c)(1O)): The estimated average and maximum wellhead injection pressure for the NOP water injection project is as follows: Surface Operating Pressure, pounds per square inch, gauge ("psig") Service Water Injection Maximum 2850 Average 2450 11. Fracture Information (20 AAC 25.402(c)(11)): Injection in the Kuparuk at pressures above ftacture parting pressure may be necessary to allow for additional recovery of oil. Water injection at the pressures proposed by BP should not initiate or propagate ftactures through the confining strata. There are no fteshwater strata in the area of Issue. No ftacture gradient has been obtained in the Kuparuk interval at Niakuk; however it is expected that the ftacture gradient will be similar to that of the Kuparuk interval of Pt. McIntyre and West Beach Pools, or .60-.63 psi/ft. The Kuparuk Formation is overlain by the HRZ shale. Leakoff test data for NK-05 and NK-06 indicate a fracture gradient of over .82 psi/ft. Surface injection pressures in excess of 3200 psi would be required to initiate a ftacture into the HRZ. Area Injection Order 1. December 31, 2001 e Page 6 12. Water Analysis (20 AAC 25.402(c)(12): Produced water analysis from the NOP indicates 25,000 parts per million ("ppm") total dissolved solids (TDS). Calculation of TDS from wire line logs indicates NaCI equivalents of greater than 10,000 ppm in the fonnations above the Kuparuk Fonnation. Therefore, aquifer exemption is not required. 13. Hvdrocarbon Recovery (20 AAC 25.402(c)(14»: BP projects waterflood overall recoveries of approximately 35-38% in the Segments 1 and 3/5 of the western Niakuk, (67 to 72 MMSTBO), and 24-27% Segment 2 of the eastern Niakuk region (or 29-33 MMSTBO). Recovery by primary depletion alone is estimated at about 13%. Waterflood has been ongoing in Niakuk since 1994. These recovery figures include wells drilled and completed to date, including the NK-28 conversion, but not future development. Incremental recovery of 1.2 MMBO is projected as a result of conversion ofNK-28 to water injection. a) Water Management Areas: The Niakuk accumulation is managed as three main pools - Segment 1, Segment 3/5, and Segment 2. b) Reservoir Surveillance Results: Initial reservoir pressure is estimated at 4500 psi. Production prior to 1996 dropped reservoir pressures in some areas. After injection started in 1995, pressures stabilized at approximately 4000 psi in the Segments 1 and 3/5 in the western Niakuk. Segment 2 in the eastern Niakuk has shown mixed results from water injection because there is structural and stratigraphic compartmentalization that is not as evident in the western Niakuk. Segment I (West Niakuk Graben): Production in the Segment I began in April 1994. Injection began approximately one year later with the conversion of NK-I0. Production has been sustained via pressure maintenance from this single injector. Aquifer support to the west may also be present, but has not been verified. Recent increases in oil production are attributed to redrilled well NK -07 A. Although injection is currently adequate in this area, future conversions may be considered. Segment 3/5 (West Niakuk Platfonn): Production in Segment 3/5 began in January 1995. Injection began approximately two years later at NK.-15. Production has been sustained via pressure maintenance from this one injector, although injection has also been attempted at NK-17 with poor injectivity caused by poor rock quality. Injection in the Segment 3/5 is currently not balanced with voidage, in part due to production from recently redrilled well NK-08A. Another reason is the reduction in injectivity at NK-15 since its conversion from seawater to produced water injection roughly one year ago. BP anticipates conversion of NK-28 to injection service will alleviate this situation and optimize recovery from NK-08A. NK-28, which has produced over 2 MMBO, has watered out, Area Injection Order 1. December 31, 2001 e Page 7 and was recently converted to injection. While injection has not fully matched production, the segment has shown low decline relative to the to the other segments. BP indicates that additional aquifer support to the west may be present, but has not been verified. Segment 2 (East Niakuk Graben): Segment 2 is more complex relative to the West Niakuk Graben and West Niakuk Platfonn. Production in Segment 2 began in April 1994. Injection began approximately one year later when NK-16, NK-23, and NK-38 were put into injection service. NK-65 was later put on injection in mid-1998. Production has been maintained to varying degrees via pressure maintenance from these injectors. NK-19 is an exception to this because it is completed in a relatively small isolated block that receives no pressure support. This well produced less than half a million barrels of oil before gassing out and dying due to low reservoir pressure and lack of injection support. NK-18 has had similar perfonnance, but is not located in a completely isolated fault block. NK-18 was recently converted to injection in anticipation of production from the redrill ofNK-19A. Because of the greater complexity and reservoir compartmentalization, BP states that well configuration and recovery perfonnance in East Niakuk may differ substantially from what is seen in the west. c. Reservoir Simulation: BP has developed two reservoir models in the evaluation of the waterflood, infiH drilling, water conversion candidates and future development options. Both models were built using a detenninistic methodology. Kuparuk tops and bottoms were defined by seismic data, along with internal stratification where it could be seen. Well control was honored in defining the structure. Geologic descriptions from core, coupled with log data, were used to interpret internal stratigraphy, and fonned the basis for an internal zonation scheme and the final simulation grid. Porosity in both models was derived trom core data where available and an interpreted log model elsewhere. Porosity/penneability crossplots were derived trom the cored intervals. The log model incorporates density, sonic, and neutron measurements along with adjustments for shale volumes, heavy minerals, and cementation, which are zone-specific in some cases. Initial water saturations are assigned by functions developed trom core that incorporate porosity, height above the water column, saturation exponents (Archie model), and Waxman-Smits parameters. Relative penneability experiments have not been conducted with Niakuk rock samples. Accordingly, scalable relative penneability curves developed trom Prudhoe Bay samples have been employed and are assigned based on initial water saturation. The lithologic description used in the current reservoir simulation contains 32 layers for Segment 2 in eastern Niakuk and 13 layers for Segments 1 and 3/5 in the western Niakuk. Simulation grids that averaged less than 15% porosity or 10 md permeability were zeroed out. BP provided results of the history matches obtained in the West and East Niakuk Area Injection Order 1. December 31, 2001 e Page 8 models. BP indicated some adjustments to description were required to obtain the match, particularly with respect to fault locations. 14. Mechanical Condition of Adjacent Wells (20 AAC 25.402(c)(15). BP is utilizing injection wells previously covered by AIO 14. To the best of BP's knowledge, the wells within the Niakuk and Western Niakuk Participating Areas were constructed, and where applicable, have been abandoned to prevent the movement of fluids into rreshwater sources. Information regarding wells that penetrate the injection zone within ~ mile radius of injection wells has been filed with the Commission. 15. Incorporation of AIO 14 Findings: The findings of fact in AIO 14 and amendments thereto are incorporated herein to the extent not inconsistent with this order. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An order permitting the underground injection of fluids on an area basis, rather than for each injection well individually, provides for efficiencies in the administration and surveillance of underground fluid injection operations. 3. The waters are currently injected under prior Commission approval of AIO 14. Core tests indicate minimal plugging problems with injected water. No problems with compatibility of the fluids have been observed. 4. Revision of AIO 14 to expand the effected area is appropriate in accordance with 20 AAC 25.450 and 20 AAC 25.460. 5. NK-28 is the only existing well planned for water injection conversion in the expanSIOn area. 6. Injection of water in NK-28 is needed to maintain pressure and improve recovery in the Western region of the Niakuk. 7. All injection wells are designed to comply with the mechanical integrity requirements specified in 20 AAC 25.412. Mechanical integrity ofNK-28 has been demonstrated by mechanical integrity test. 8. An order for temporary water injection into NK-28 was approved by the Commission on August 20,2001, and extended by order dated November 14, 200l. 9. Fluids injected for enhanced recovery will consist of a mix of either produced waters processed in the Lisburne Production Facilities, or water rrom the Prudhoe Bay Unit Seawater Treatment Plant. Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. 10. The proposed injection operations will be conducted in permeable strata that can Area Injection Order Ie December 31, 2001 . Page 9 reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 11. There are no USDW's within the project area. 12. Injection of water will significantly increase hydrocarbon ultimate recovery above primary production. 13. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the water injection project or disclose possible abnormalities. 14. The conclusions in AIO 14 and the amendments thereto are incorporated herein to the extent not inconsistent with this order. NOW, THEREFORE, IT IS ORDERED; 1. Except as otherwise provided herein, this order supersedes Area Injection Order No. 14 and previous revisions. 2. The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), govern enhanced oil recovery injection operations in the NOP in the affected area defined below. Umiat Meridian Township Range Sections T12N RISE 13-15 (all); 22-27 (all); 36 (NE/4) R16E 28 (W/2, NE/4, W/2 ofSE/4, SE/40fSE/4); 29-30 (all); 31 (N/2); 32 (N/2) T12N Rule 1 Authorized Injection Strata for Enhanced Recovery and Authorized Injection Fluids Enhanced recovery operations as described in the operator's applications are approved for the NOP within the Prudhoe Bay Field subject to these rules. 1) Authorized Injection Strata: Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those that Area Injection Order 1. December 31, 2001 e Page 10 correlate with and are common to the fonnations found in BP Niakuk No. 6 between the measured depths of 12,318 - 12942 feet. 2) Authorized Injection Fluids: Fluids authorized for injection for the NOP: a. Produced water from LPC operations; b. Beaufort seawater; c. Trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process; and d. Fluids injected for the purposes of stimulation per 20AAC24.280(2). Rule 2 Fluid Injection Wells The injection of fluids must be conducted 1) through a new well that has been pennitted for drilling as a service well for injection in confonnance with 20 AAC 25.005; or 2) through an existing well that has been approved for conversion to a service well for injection in confonnance with 20 AAC 25.280. Rule 3 Monitorine the Tubine-Casim! Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to confinn continued mechanical integrity. Rule 4 Demonstration of Tubine-Casin!! Annulus Mechanical Intep"ritv A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. Rule 5 Notification of Well Inte2ritv Failure Whenever injection rates or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission by the first working day following the observation, and submit a plan of corrective action on Fonn 10-403 for Commission approval. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 6 Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 1, above, without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the Commission, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Area Injection Order 1. December 31, 2001 Rule 7 Other Conditions e Page 11 a. It is a condition of this authorization that the operator complies with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 8 Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated December 31,2001. r i1 I J' A !l.. l1!¡yWvv~/ (YL{.i ì.I)..~ :Já.L/K..11. ( . ~ Cammy Oe hsli Taylor, Chait) ~~d Gæ Co~=ation Commission Daniel T. SeamoIDÍt, Jr., Commissioner Alaska Oil and Gas Conservation Commission ~M.~ Julie M. Heusser, Commissionner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30 day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 SD DEPT OF ENV & NA TRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 e OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LIBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 IOGCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 H J GRUY, A TTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 e ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 2121 NORTH BAYSHORE DR #616 MIAMI, FL 33137 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 TEXACO INC, R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 JIM WHITE 4614 BOHILL SAN ANTONIO, TX 78217 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 EVERGREEN WELL SERVICE COMPANY, JOHN TANIGAWA 1401 SEVENTEENTH STREET STE 1200 e GAFFNEY, CLINE & ASSOC., INC., LIBRARY 1360 POST OAK BLVD., STE 2500 HOUSTON, TX 77056 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 PO BOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 INTL OIL SCOUTS, MASON MAP SERV INC PO BOX 338 AUSTIN, TX 78767 DIANE SUCHOMEL 1 0507D W MAPLEWOOD DR LITTLETON, CO 80127 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 e MURPHY EXPLORATION & PRODUCTION CO., BOB SAWYER 550 WESTLAKE PARK BLVD STE 1000 HOUSTON, TX 77079 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 C & R INDUSTRIES, INC." KURT SALTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 e NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORa NEGRO, INC., 9321 MELVIN AVE NORTH RIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 e RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 PRESTON GATES ELLIS LLP. LIBRARY 420 L ST STE 400 ANCHORAGE. AK 99501-1937 DEPT OF NATURAL RESOURCES. DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE. AK 99501-3510 DEPT OF NATURAL RESOURCES. DIV OIL & GAS WILLIAM VAN DYKE 550 W 7TH AVE. SUITE 800 ANCHORAGE. AK 99501-3560 DEPT OF NATURAL RESOURCES. PUBLIC INFORMATION CTR 550 W 7TH AVE. SUITE 800 ANCHORAGE. AK 99501-3560 BRISTOL ENVIR AND ENG SERVICE. MIKE TORPY 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE. AK 99502-1116 ANADARKO. MARK HANLEY 3201 C STREET STE 603 ANCHORAGE. AK 99503 ANADRILL-SCHLUMBERGER. 3940 ARCTIC BLVD #300 ANCHORAGE. AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE. AK 99504-4209 US BUREAU OF LAND MNGMNT. ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE. AK 99507 UON ANCHORAGE. INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE. AK 99508 e ALASKA DEPT OF LAW. ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE. AK 99501-1994 DEPT OF REVENUE. OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE. AK 99501-3540 DEPT OF NATURAL RESOURCES. DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE. SUITE 800 ANCHORAGE. AK 99501-3560 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE. AK 99501-3560 HDR ALASKA INC. MARK DALTON 2525 C ST STE 305 ANCHORAGE. AK 99503 BAKER OIL TOOLS. ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE. AK 99503 FINK ENVIRONMENTAL CONSULTING, INC.. THOMAS FINK. PHD 6359 COLGATE DR. ANCHORAGE. AK 99504-3305 US BUREAU OF LAND MNGMNT. ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE. AK 99507 BUREAU OF LAND MANAGEMENT. GREG NOBLE 6881 ABBOTT LOOP ROAD ANCHORAGE. AK 99507 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 e GAFO,GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE. AK 99501-2101 DEPT OF NATURAL RESOURCES. DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE. SUITE 800 ANCHORAGE. AK 99501-3560 DNR. DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE. SUITE 800 ANCHORAGE. AK 99501-3560 DEPT OF NATURAL RESOURCES. DIV OF OIL & GAS JIM STOUFFER 550 W 7TH AVE. SUITE 800 ANCHORAGE. AK 99501-3560 N-I TUBULARS INC. 3301 C Street Ste 209 ANCHORAGE. AK 99503 ALASKA OIL & GAS ASSOC. JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE. AK 99503-2035 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE. AK 99504-3342 AMERICNCANADIAN STRATIGRPH CO. RON BROCKWAY 4800 KUPREANOF ANCHORAGE. AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE. AK 99508 VECO ALASKA INC.. CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE. AK 99508 US BLM AK DIST OFC, GEOLOGIST ARTHUR BANET 949 EAST 36TH AVE STE 308 ANCHORAGE, AK 99508 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 e US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4302 GORDONJ.SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 AL YESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGEiAK 99516-6510 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 e US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577. DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 RON DOLCHOK POBOX 83 ' KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 e HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 196168 ANCHORAGE, AK 99519-6168 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 PENNY VADLA PO BOX 467 NINILCHIK, AK 99639 e TESORO ALASKA COMPANY, PO BOX 196272 ANCHORAGE, AK 99519 ENSTAR NATURAL GAS CO, PRESIDENT TONY IZZO POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 VALDEZ PIONEER, POBOX 367 VALDEZ,AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG PO BOX416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 e JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ, AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 e KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 COOK AND HAUGEBERG, JAMES DIERINGER, JR. 119 NORTH CUSHMAN, STE 300 FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DRAKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 e ~~!Æ~! (fiF !Æ~!Æ~~~!Æ e AI,ASIiA OIL AlWD GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO AI014B.l Mr. Mark Weggeland GPMA Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Weggeland, In accordance with 20 AAC 25.402, BP Exploration (Alaska) Inc. ("BPXA"), by letter dated September 8, 2005 has requested that the Alaska Oil and Gas Conservation Commission administratively amend AIO 14B to allow pilot water injection for enhanced recovery purposes into the Well NK-65A within the Ivishak Formation ("Raven" undefined oil pool) in the Prudhoe Bay Field. In addition, BPXA requested extension of a GOR waiver for producer NK-38A, also within the Raven accumulation. Authority 20 AAC 25.402 provides authority to issue an order governing underground injection of fluids. 20 AAC 25.240(b)(l) allows the Commission to waive the gas-oil-ratio limitation of 20 AAC 25.240(a) if an enhanced recovery project operates in the pool from which the well is producing. Rule 8 of AIO 14B gives the Commission flexibility to administratively waive or amend the order if the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. ADMINISTRATIVE APPRIAL 14B.001 September 12,2005 Page 2 of 4 e Background Injection is proposed to support production from NK-38A. NK-38A produced under tract operations from March 2005 to July 2005. In April 2005 the Commission granted a waiver to the GOR requirements of 20 AAC 25.240. The waiver expired on July 31, 2005 and the well has been shut-in since that time. Continued production without pressure support will negatively affect ultimate recovery. BPXA originally applied for injection into NK-65A on May 18, 2005. Notice for hearing was published May 27, 2005 for hearing July 7, 2005. Due to lack of quorum on that date, the hearing was to reconvene on July 13,2005. There were no protests or requests for hearing from the public. However, the Commission requested additional information be supplied at the hearing. BPXA withdrew their application on July 11,2005. The new application provides the additional information requested by the Commission Findings: 1. The surface location of NK-65A is within Section 36, TI2N-RI5E Umiat Meridian. The bottomhole location ofNK-65A is within Section 30, TI2N-RI6E, Umiat Meridian. The Raven accumulation lies within Sections 23, 24, 25, and 36 of T12N-RI5E and Sections 29, 30, 31, and 32 of TI2N-RI6E. The Raven reservoir strata are those that correlate with and are common to the formations found in BP Niakuk No. 65-A between the measured depths of 13,700 and 14,135 feet. The Raven accumulation lies entirely within the affected area of AIO 14B. 2. BP provided all designated operators and surface owners within one-quarter mile radius of NK65-A with a copy of the application for amendment of AIO 14B. Operators and Surface Owners within the areas are BPXA, Department of Natural Resources and heirs of Andrew Oenga. 3. The NK-65A water injection will be conducted from the PBU DS NK Pad, which was built for Niakuk Field development. 4. NK-38A produced a total of roughly 148 MSTB oil, 378 MMSCF gas, and 0.5 MSTB water from March to July, 2005. It has a production capacity of over 3000 STB/D, however it was choked back due to increasing GOR. 5. Initial reservoir pressure of the Raven is estimated at 4995 psi. As a result of production from NK-38A, the reservoir pressure has dropped to around 4300 psi. 6. Estimated total oil recovery is expected to increase from about 11 % OOlP (primary production only) to approximately 30-35% OOlP with water injection from the NK-65A well. 7. BPXA plans to replace reservoir voidage resulting from production of NK-38A with water injection in NK-65A. This injector/producer pair will be operated to maintain a V oidage Replacement Ratio (VRR) of 1.0 within normal operating ranges. 8. Production surveillance activities for the Ivishak Raven Accumulation will include bottomhole pressure surveys, production logging and well testing in NK- ADMINISTRATIVE APpA AL 14B.00 1 September 12,2005 Page 3 of4 e 38A and injection logging. 9. There are no underground sources of drinking water within the proposed affected area. 10. The Kavik shale is 188' thick in the nearby NK-04 well and forms the lower confining zone, below the lower Ivishak. Over 200' of Kingak shale provides the upper confining interval. 11. It is anticipated that injection pressures greater than fracture pressure will be required, but the fracture pressure is significantly less than that of the confining shales. The estimated maximum and average injection pressures will be 2,500 psi and 1,500 psi, respectively. 12. There are no wells that penetrate the Ivishak injection zone within a quarter mile radius of well NK-65A. 13. Seawater from the Prudhoe Seawater Treatment Plant will be injected during the period of the pilot program. The same water has been injected within the Ivishak Formation of the Prudhoe Oil Pool without apparent compatibility problems. 14. The logs of NK-65A are on file with the Commission. Specific to this application, the bond logs ofNK-65A have been reviewed, and sufficient cement exists above the Raven interval. 15. NK65-A was cased and cemented in accordance with 20 AAC 25.412. Conclusions: 1. The application requirements of20 AAC 25.402 have been met. 2. The proposed project will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. 3. An order permitting the underground injection of water into the Raven will allow for production of NK-38A, will provide valuable information for ultimate waterflood planning, and will significantly improve overall recovery. 4. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the well bore and appropriate operating conditions. 6. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests will demonstrate performance ofthe water injection project. 7. The proposed injection operations will not cause contamination of any underground sources of drinking water. ADMINISTRA TIVE APP" AL 14B.00 1 September 12,2005 Page 4 of 4 e 8. Proposed injection fluids are compatible with formation fluids. 9. Injection of water will significantly increase hydrocarbon ultimate recovery above primary production. Rule: The Commission approves BPXA's request for pilot water injection into the Raven accumulation within NK-65A subject to the applicable rules adopted in Area Injection Order No. l4B and subject to the conditions, limitations, and requirements set out in statewide requirements under 20 AAC 25 (to the extent not otherwise superseded by AIO l4B). The authorized injection strata are those that correlate with and are common to the formations found in BP Niakuk No. 65-A between the measured depths of 13,700 and 14,135 feet. The operator shall monitor wells NK-65A and NK-38A daily to check for sustained pressure to ensure there is no pressure communication or leakage in any casing, tubing or packer, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. During the period of pilot water injection into NK-65A, the Commission waives the gas- oil ratio requirements of 20 AAC 25.240(a) so long as the monthly injection volume within NK-65A meets or exceeds the monthly reservoir voidage volume from NK-38A. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Alaska and dated September 12,2005. Daniel T. Seamount, Jr. Commissioner Various Administrative Approvals and Storage Injection Orders e . Subject: Various Administrative Approvals and Storage Injection Orders From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 13 Sep 2005 13:56:11 -0800 To: undisclosed-recipients:; BeC: Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.okus>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, ros ragsdaIe <roseragsdale@gci.net>, trmjrl <trmj jbriddle <jbriddle@marathonoil.co >, shaneg <shaneg@ a com>, jdarli <jdarlington@forestoil.com>, el Ie cboddy <cboddy@usibelli.com , Mark <mark @hd m annon Donnelly <shannon.donnelly ocoph s.com>, "Mark P. Worcester" <markp.worcester@conocoph ips.com>, Bob <bob@inletkeeper.o >, tjr <tjr@dnr.state.ak.us>, bbrit <bbritch@alaska.net>, mjnelson < ~n Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" < "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <Ro <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon "Francis S. Sommer" <SommerFS P.com>, Mikel Schultz < . el. ltz@BP.co Glover" <GloverNW@BP.com>," 11. Kleppin" <KleppiDE P.com>, "Jane <PlattJD@BP.com>, "Ros eM cobsen" <JacobsRM@B , ddonkel <dd mckay <mckay@gci.net>, b llmer <barbara.f.fullmer conocophillips.com>, <bocastwf@bp.com>, Ch Bark <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark <yesno l@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@she Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones <jejones@aur dapa <dapa@alaska.net>,jroderick <jroderick@gcLnet>, eyancy <e cy@seal-tite Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <m.apalas @ak.net>,jah <jah@dnr.state.ak.us>, Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buonoje@bp.com Mark Hanley <mark_hanley@anadarko.com>,loren_leman <loren_Ieman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan_hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenaLak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.al mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary-,-schultz@dnr.state.ak.us>, W e Rancier <RANCIER@petro-canada.ca>, Bil <Bill_Miller@xtoalaska.com>, Br n Gagnon <bgagnon@brenalaw.com>, Paul Wi <pmwinslow@forestoil.com>, G Catron <catrongr@bp.com>, Sh aine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, K 11 Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>,jack newell <jacknewell@acsalaska.net>, James Scherr <james _ scherr@yahoo.com>, david roby <David.Roby@mms.gov>, Tim Lawlor lof2 9/13/2005 1 :56 PM Various Administrative Approvals and Storage Injection Orders e e <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, Jerry Dethlefs <n1617@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.GoItz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy <mlewis@brenalaw.com>, Harry Lampert <harry.1ampert@honeywell.com>, Karl Mori <moriarty .or >, Patty AID lfaro o.com>, Jeff <s tank.aj@unocal.c <ToddKr n. >, G gers _ rs@reve . us h <Arthur_ los@d state.ak Phillip Ayer mayers >, Ken <ken@secorp~inc.com ,Cynthi Mciver <bren_ iver@ad ak.us> Administrative Approval AIO 10B.003 Administrative Approval AIO 14B.1 Administrative Approval AIO 5.005 Administrative Approval CO 477.006 Administrative Approval AIO 10B.002 Storage Injection Order #4 PBU Schrader Bluff PBU Niakuk Trading Bay Unit Graying 16 PBU Schrader Bluff PBU Schrader Bluff Pretty Creek Unit #4 ,ì :AI014B.OO1.pd , ontent- Type: ontent-Encoding: base64 Content- Type: application/pdf C0477.006.pdf Content-Encoding: base64 , Content-Type: application/pdf AIOIOB.002.pdf' Content-Encoding: base64 '.. ,.. ... ...j ëontent-Type:· app a AI05.005.pdf: i Content-Encoding: base64 20f2 9/13/2005 I :56 PM e ~~~~E illJF ~~~~~~~ e ~1,A.SIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CORRECTED ADMINISTRATIVE APPROVAL NO AI014A.l Mr. Mark Weggeland GPMA Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Weggeland, In accordance with 20 AAC 25.402, BP Exploration (Alaska) Inc. ("BPXA"), by letter dated September 8, 2005 has requested that the Alaska Oil and Gas Conservation Commission administratively amend AIO 14A to allow pilot water i~ection for enhanced recovery purposes into the Well NK-65A within the Ivishak Formation ("Raven" undefined oil pool) in the Prudhoe Bay Field. In addition, BPXA requested extension of a GOR waiver for producer NK-38A, also within the Raven accumulation. Authority 20 AAC 25.402 provides authority to issue an order governing underground injection of fluids. 20 AAC 25.240(b)(1) allows the Commission to waive the gas-oil-ratio limitation of 20 AAC 25.240(a) if an enhanced recovery project operates in the pool from which the well is producing. Rule 8 of Ala 14A gives the Commission flexibility to administratively waive or amend the order if the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. ADMINISTRATIVE APpAAL 14A.00l September 14,2005 Page 2 of 4 e Background Injection is proposed to support production from NK-38A. NK-38A produced under tract operations from March 2005 to July 2005. In April 2005 the Commission granted a waiver to the GOR requirements of 20 AAC 25.240. The waiver expired on July 31, 2005 and the well has been shut-in since that time. Continued production without pressure support will negatively affect ultimate recovery. BPXA originally applied for injection into NK-65A on May 18,2005. Notice for hearing was published May 27, 2005 for hearing July 7, 2005. Due to lack of quorum on that date, the hearing was to reconvene on July 13,2005. There were no protests or requests for hearing from the public. However, the Commission requested additional information be supplied at the hearing. BPXA withdrew their application on July 11,2005. The new application provides the additional information requested by the Commission Findings: 1. The surface location of NK-65A is within Section 36, T12N-RI5E Umiat Meridian. The bottomhole location ofNK-65A is within Section 30, TI2N-RI6E, Umiat Meridian. The Raven accumulation lies within Sections 23, 24, 25, and 36 of TI2N-RI5E and Sections 29, 30, 31, and 32 of TI2N-RI6E. The Raven reservoir strata are those that correlate with and are common to the formations found in BP Niakuk No. 65-A between the measured depths of 13,700 and 14,135 feet. The Raven accumulation lies entirely within the affected area of AIO 14A. 2. BP provided all designated operators and surface owners within one-quarter mile radius of NK65-A with a copy of the application for amendment of AIO 14A. Operators and Surface Owners within the areas are BPXA, Department of Natural Resources and heirs of Andrew Oenga. 3. The NK-65A water injection will be conducted from the PBU DS NK Pad, which was built for Niakuk Field development. 4. NK-38A produced a total of roughly 148 MSTB oil, 378 MMSCF gas, and 0.5 MSTB water from March to July, 2005. It has a production capacity of over 3000 STB/D, however it was choked back due to increasing GOR. 5. Initial reservoir pressure of the Raven is estimated at 4995 psi. As a result of production from NK-38A, the reservoir pressure has dropped to around 4300 psi. 6. Estimated total oil recovery is expected to increase from about 11% OOIP (primary production only) to approximately 30-35% OOIP with water injection from the NK-65A well. 7. BPXA plans to replace reservoir voidage resulting from production of NK-38A with water injection in NK-65A. This injector/producer pair will be operated to maintain a Voidage Replacement Ratio (VRR) of 1.0 within normal operating ranges. 8. Production surveillance activities for the Ivishak Raven Accumulation will include bottomhole pressure surveys, production logging and well testing in NK- ADMINISTRATIVE APpA AL 14A.OO 1 September 14,2005 Page 3 of 4 e 38A and injection logging. 9. There are no underground sources of drinking water within the proposed affected area. 10. The Kavik shale is 188' thick in the nearby NK-04 well and forms the lower confining zone, below the lower Ivishak. Over 200' of Kingak shale provides the upper confining interval. 11. It is anticipated that injection pressures greater than fracture pressure will be required, but the fracture pressure is significantly less than that of the confining shales. The estimated maximum and average injection pressures will be 2,500 psi and 1,500 psi, respectively. 12. There are no wells that penetrate the Ivishak injection zone within a quarter mile radius of well NK-65A. 13. Seawater from the Prudhoe Seawater Treatment Plant will be injected during the period of the pilot program. The same water has been injected within the Ivishak Formation of the Prudhoe Oil Pool without apparent compatibility problems. 14. The logs of NK-65A are on file with the Commission. Specific to this application, the bond logs ofNK-65A have been reviewed, and sufficient cement exists above the Raven interval. 15. NK65-A was cased and cemented in accordance with 20 AAC 25.412. Conclusions: 1. The application requirements of20 AAC 25.402 have been met. 2. The proposed project will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. 3. An order permitting the underground injection of water into the Raven will allow for production of NK-38A, will provide valuable information for ultimate waterflood planning, and will significantly improve overall recovery. 4. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 6. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests will demonstrate performance of the water injection project. 7. The proposed injection operations will not cause contamination of any underground sources of drinking water. ADMINISTRATIVE APpAAL 14A.001 September 14,2005 Page 4 of 4 e 8. Proposed injection fluids are compatible with formation fluids. 9. Injection of water will significantly increase hydrocarbon ultimate recovery above primary production. Rule: The Commission approves BPXA's request for pilot water injection into the Raven accumulation within NK-65A subject to the applicable rules adopted in Area Injection Order No. 14A and subject to the conditions, limitations, and requirements set out in statewide requirements under 20 AAC 25 (to the extent not otherwise superseded by AIO 14A). The authorized injection strata are those that correlate with and are common to the formations found in BP Niakuk No. 65-A between the measured depths of 13,700 and 14,135 feet. The operator shall monitor wells NK-65A and NK-38A daily to check for sustained pressure to ensure there is no pressure communication or leakage in any casing, tubing or packer, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. During the period of pilot water injection into NK-65A, the Commission waives the gas- oil ratio requirements of 20 AAC 25.240(a) so long as the monthly injection volume within NK-65A meets or exceeds the monthly reservoir voidage volume from NK-38A. As provided in AS 3l.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. This approval expires April 1, 2006. aska and dated September 14,2005. This approval corrects and inistrative approval dated September 12,2005 that was 10 14B.001. J . N"lrman ../ Chairman "--"" AIO 5.006 Trading Bay Unit G-22 and Corrected AI014A.00l e e Subject: AIO 5.006 Trading Bay Unit G-22 and Corrected AI014A.00l From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Thu, 15 Sep 2005 10:31 :21 -0800 To: undisclosed-recipients:; BeC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hanse c.hansen@iogcc.state.okus>, Terrie H <hubblet1@bp.com>, Sondra Ste WInaS .com>, Scott & C Ta lor <staylor@alaska.net>, stanekj·<s ocal.c olaw <ecol @trust <roseragsdale@gci. , trmjrl oLco dIe <jb @ <shaneg@evergree as.com>, jdarlington <jdarlin restcii <knelson@petroleumnews.com>, cboddy <cboddy usibel <markdalton@hdrinc.com>, Shannon Donnelly <shanno Worcester" <markp.worcester@conocophillips.com>, Bo < 0 <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbr <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'd ell@veco.com>, <SkilleRL@BP~com>, "Deborah J. Jones" <Jo 6@BP.com>, "St <RossbeRS@BP.com>, Lois <lois@inletkee .org>, Dan Bross Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS <MikeLSchultz@BP.com>, "Nick W. Glover" <GloverNW@BP.c <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Ro M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbarà F Fullmer <barbara.f.fullmer@conocophillips.com>, bocastwf <bocastwf@bp.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobiLcom>, Mark Kovac <yesno l@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones . nes@aurorapower. <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancy <eyancy eal-tite.net>, "J <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska .net> ah <jah@dnr Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buon >, Mark H <mark_hanley@anadarko.com>, 10ren_Ieman <loren_Ieman@go . tat .us>, Julie <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan_ hill@dec.state.ak.us>, tablerk <tablerk@unocaLcom>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobiLcom>, marty <marty@rkindustriaLcom>, ghammons <ghammons@aoLcom>, rmclean <rmclean@po mkmnoo <mkm7200@aoLcom>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L B <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Bill Miller <Bill_Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoiLcom>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoiLcom>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocaLcom>,jack newell <jacknewell@acsalaska.net>, James Scherr lof2 9/15/2005 10:31 AM AIO 5.006 Trading Bay Unit G-22 and Corrected AI014A.00l e e <james_sche ahoo.com>, david roby <David.Roby@mms.gov>, Tim Lawlor <Tim_Lawlo .blm.gov>, Lynndà Kahn <Lynnda...:.K s. >, Jerry Dethlefs <Jerry.C.Dethlefs@conocophilIips.co erry Dethle 1617 onocophillips.com>, crockett@aoga.org, Tamera Sheffield <s effield@aoga.org>, Jon Goltz <Jon.GoItz@conocophilIips.com>, Roger Belman <roger.belman@conocophillips.com>, Min IS <mlewis@brenalaw.com>, Harry Lam <harry.1ampe oneywell.com>, Kari Mo . <moriarty@aoga.org>, Patty Alfaro <p o@yahoo.co , Je <smetankaj@unoca odd Kratz <ToddKratz@chevron.com>, Gary Rogers <g ogers@r e. .ak. , Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Phillip A <pmayers@uno en <ken corp-inc. com>, Steve Lambert <sal @unocal.com> Content- Type: plication/pdf AI014A.OO1.pdf . Content-Encodmg: base64 Content-Type: . AI05.006.pdf C E d· ontent- nco m 20f2 9/15/2005 10:31 AM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchìck, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 e Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 e David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 SOldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 ~ ~ I\~ «~~\ Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 . Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, W A 98119-3960 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 \ W/Yt?:ì ~c\0 • • " ~ o ~ ~ ~ SARAH PALIN, GOVERNOR f~ 1LUAa7~A OIIJ ~ vny7 333 W. 7th AVENUE, SUITE 100 COI~TSERQATIO~T COl-'II-IIS51OIQ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 14A.002 Mr. Steve Rossberg Wells Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: PBU NK-16 (PTD 1940220) Request for Administrative Approval Dear Mr. Rossberg: In accordance with Rule 8 of Area Injection Order ("AIO") 14A.000, the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission") hereby grants BP Exploration (Alaska) Inc. ("BPXA")'s request for administrative approval to continue water injection in the subject well. Niakuk Oil Pool (part of the Prudhoe Bay Unit) well NK-16 exhibits inner annulus repressurization that is being managed by periodic pressure bleeds. BPXA initiated diagnostic testing and notified the Commission regarding increased inner annulus pressure on October 8, 2007. However, pressure records show that the first indication of increasing inner annulus pressures occurred in late August 2007. You are reminded that AIO 14A, Rule 5 requires notification by the first working day following observation of pressure communication or leakage. It appears that notice should have been made to the Commission in early September. AOGCC finds that BPXA has elected to perform no corrective action at this time on PBU NK-16. The Commission further finds that, based upon reported results of BPXA's diagnostic procedures and wellhead pressure trend plots, PBU NK-16 exhibits two competent barriers to the release of well pressure. Accordingly, the Commission believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's administrative approval to continue water injection in PBU NK-16 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; • AIO 14A.002 November 29, 2007 Page 2 of 2 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and IA pressure bleeds; 3. BPXA shall perform an MIT-IA every 2 years to 1.2 times the maximum anticipated well pressure; 4. BPXA shall limit the well's IA pressure to 2,000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection, and 7. The MIT anniversary date is October 28, 2007. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless reconsideration has been requested. a and dated November 29, 2007. ~~~ Daniel T. Seamount, Jr. Commissioner ,~ Cathy . Foerster Commissioner Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 30, 2007 8:48 AM Subject: A104C-015 cancellation and A1014A-002 PBU Admin Approvals Attachments: aio14a-002.pdf; aio4c-015 cancellation.pdf BCC:McIver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR); 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'carol Smyth'; 'Cary Carrigan'; 'Catherine P Foerster'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr ; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net ; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac ; 'Mark P. Worcester'; 'Marquerite kremer'; 'marty'r 'Matt Rader'; 'mckay ; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean ; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly ; 'Walter Quay'; 'Wayne Rancier' Attachments:aiol4a-002.pdf;aio4c-015 cancellation.pdf; 11 /30/2007 • Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ~?a~/ /3~i~ • ~~p~ ~ u~ Q~~~f~a / ,,.,~~.,,~o~ew ALASSA OII, A1~TD GAS 333 W. 7th AVENUE, SUITE 100 COI~TSERQA7'IOr1T COMDII5SI01'1T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 14A.002 (Amended) Mr. Steve Rossberg, Wells Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: PBU NK-16 (PTD 1940220) Request for Administrative Approval Dear Mr. Rossberg: In accordance with Rule 8 of Area Injection Order 14A.000, the Alaska Oil and Gas Con- servation Commission ("AOGCC" or "Commission") hereby grants BP Exploration (Alaska) Inc. ("BPXA")'s request for administrative approval to inject water in the sub- ject well. Niakuk Oil Pool (part of the Prudhoe Bay Unit) well NK-16 exhibits inner annulus rep- ressurization that can be managed by pressure bleeds. BPXA initiated diagnostic testing and notified the Commission regarding increased inner annulus pressure on October 8, 2007. Administrative approval was conditionally granted to BPXA on November 29, 2007 with specific operating limits, including maintaining inner annulus pressure at or below 2000 psi. The Commission was advised on January 8, 2008 by BPXA of difficulties in maintaining inner annulus pressures below 2000 psi and requested an increase of the maximum al- lowable inner annulus pressure to 2500 psi. At the Commission's request, inner annulus pressure bleeds were suspended and BPXA was allowed to continue injecting with moni- toring to determine where the increasing inner annulus pressure would stabilize. BPXA and the Commission hypothesized that pressures would equalize at or near the injection pressure at the surface. BPXA provided supplemental information on February 11, 2008 showing the equalization of inner annulus pressure with the injection tubing pressure at approximately 2200 psi. The Commission finds that PBU NK-16 exhibits two competent barriers to the release of well pressure. AOGCC further finds that BPXA is able to manage the inner annulus pressure with periodic pressure bleeds. To minimize the bleed frequency, it is appropri- ate to revise the maximum allowable pressure for the inner annulus. The Commission AIO 14A.002 (Amended) February 11, 2008 Page 2 of 2 believes that well operation in water injection service only will not threaten the environ- ment or human safety. AOGCC's administrative approval to inject water in PBU NK-16 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and IA pressure bleeds; 3. BPXA shall perform anMIT-IA every 2 years to 1.2 times the maximum antici- pated well pressure; 4. BPXA shall limit the well's IA pressure to 2,500 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection, and 7. The MIT anniversary date is October 28, 2007. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsid- eration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless reconsideration has been requested. DONE at Anchorage, Alaska and dated February 11, 2008. Daniel T. Seamount, Jr. Cathy . Foerster o Orman Chair Com issioner Com 'ssio~er • Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, February 11, 2008 3:05 PM Subject: A0114A.002 (Amended) PBU Niakuk Attachments: A1014A.002 (Amended).pdf BCC:Johnson, Elaine M (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR); 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'many'; 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro ; 'Paul Decker'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:AI014A.002 (Amended).pdf; Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 *Note new email address 2/11/2008 • • Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas + ,. Arctic Slope Regional Corporation ~ C,J Land Department PO Box 129 ~ ~' Barrow, AK 99723 • e Da SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COXIMSSIOIQ ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 CANCELLATION ADMINISTRATIVE APPROVAL NO. AIO 14A.002 Mr. Steve Rossberg, Wells Manager Attention: Well Integrity Engineer, PRB -20 BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 RE: Cancellation of Administrative Approval AIO 14A.002 Prudhoe Bay Unit Well NK -16 (PTD 1940220) Niakuk Oil Pool Dear Mr. Rossberg: Pursuant to BP Exploration (Alaska) Inc. (BPXA)'s request dated October 27, 2009 Alaska Oil and Gas Conservation Commission (AOGCC or Commission) hereby cancels Administrative Approval AIO 14A.002, which allows continued water injection in Prudhoe Bay Unit (PBU) well NK -16. This well exhibited tubing by inner annulus communication and BPXA did not at the time propose repairing the well to eliminate the problem. The Commission determined that water injection could safely continue in the well, but subject to a number of restrictive conditions set out in the administrative approval. BPXA has since shut in PBU NK -16 and will not operate the injection well due to instantaneous communication to a nearby producer. Consequently, Administrative Approval AIO 14A.002 no longer applies to operation of this well. Instead, injection into PBU NK -16 will be governed by provisions of the underlying AIO No. 14A. DONE at Anchorage, Alaska and dated November 4, 2009. The Alaska Oil an G s nservation Commission ° "ie1 T. Seamount, Jr. Vin m , . N an Cathy . Foerster Chi m' sinner Com issioner Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, November 05, 2009 3:34 PM To: 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Bowen Roberts'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; caunderwood @marathonoil.com; 'Charles O'Donnell'; Chris Gay; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; Deborah Jones; Decker, Paul L (DNR); 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2 @mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin,'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'Janet D. Platt; 'jejones'; 'Jerry Brady'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; Joseph Darrigo; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson @petroleumnews.com; 'Krissell Crandall'; 'Kristin Elowe'; 'Laura Silliphant'; 'mail= akpratts @acsalaska.net'; 'mail= foms @mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; Melanie Brown; 'Michael Nelson'; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Winslow'; 'peter Contreras'; Rader, Matthew W (DNR); Raj Nanvaan; 'Randall Kanady'; 'Randy L. Skillern'; 'Rob McWhorter'; rob.g.dragnich @exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Rudy Brueggeman'; 'Sandra Pierce'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Susan Roberts'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; 'Ted Rockwell'; 'Temple Davidson'; Teresa Imm; 'Terrie Hubble'; 'Thor Cutler'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Von Hutchins'; 'Walter Featherly'; Williamson, Mary J (DNR); 'Aaron Gluzman'; 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Crisp, John H (DOA); Darlene Ramirez; Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: C0626 (Paxton #3) and various cancelled Admin Approvals Attachments: co626.pdf; aio3 -020 cancellation.pdf; aio3 -015 cancellation.pdf; aiol4A -002 cancellation. pdf Jodi• J. Colombie Special Assistant Alaska Oil and Gas C'onservalion Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102 -6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201 -3557 408 18th Street President Golden, CO 80401 -2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr. #5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508 -4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669 -7714 Soldotna, AK 99669 -2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K &K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 • • 0 _E A � a A SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 14A.003 Ms. Allison Cooke UIC Compliance Advisor BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 RE: Authorized Fluids for EOR and Pressure Maintenance of the Niakuk Oil Pool Dear Ms. Cooke: By letter dated April 30, 2012, BP Exploration (Alaska) Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) administratively amend the following Area Injection Orders (AIO): 3A, 4E, 14A, 20, 22E, 24B, 25A, 26B and 31. BPXA requested the amendments in an effort to standardize the fluids authorized for injection for enhanced recovery and pressure maintenance for the oil pools in the Prudhoe Bay Field. BPXA requested the standardization due to the complexity of managing injection operations for multiple pools, with different lists of authorized fluids, which are served by common production facilities. In accordance with terms set forth below, BPXA's request is partially APPROVED, with a minor change to the wording proposed by BPXA. BPXA's request to inject produced gas and enriched hydrocarbon gas is hereby DENIED. BPXA proposes that AIO No. 14A be modified to approve the following for EOR and pressure maintenance injection. - Produced water and gas; - Enriched hydrocarbon gas; - Non - hazardous water and water based fluids — (includes seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 10 degrees F); - Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Includes but not limited to: o Freeze protection fluids; o Fluids in mixtures of oil sent for hydrocarbon recycle; o Corrosion/scale inhibitor fluids; AIO 14A.003 • • September 4, 2012 Page 2 of 3 o Anti -foams /emulsion breakers; o Glycols - Non - hazardous glycols and glycol mixtures; - Fluids that are used for their intended purpose within the oil production process. Includes: o Scavengers; o Biocides - Fluids to monitor or enhance reservoir performance. Includes: o Tracer survey fluids; o Well stimulation fluids; o Reservoir profile modification fluids. As shown above, the list of fluids for which BPXA seeks approval uses the terms "includes" and "includes but not limited to." Words such as "includes" and "including" along with phrases such as "includes but is not limited to" inappropriately delegate to BPXA the authority to determine what additional fluids are approved. Therefore, this approval modifies BPXA's proposal to delete the use of any such language as set forth below. In support of its application, BPXA submitted a fluid compatibility review based on previous orders and laboratory testing. This review showed that the proper handling and treating, including the use of scale inhibitors, of the injection fluids as well as the proper operation and maintenance, including the pumping of scale remover and acid treatments, of the injection wells will prevent or counteract incompatibility effects. Thus there are no operational risks associated with injection of the proposed fluids in this pool. It has not been demonstrated that the produced of roduced gas or enriched hydrocarbon gas will J enhance recovery from this pool. Therefore, BPXA's request to allow gas injection in this pool is denied. The change proposed by BPXA will result in increased production, is based on sound engineering and geotechnical reasons, does not promote waste or jeopardize correlative rights, and will not result in increased risk of fluid movement into freshwater. Correlative rights are protected because all lands subject to these orders have been unitized. Freshwater is protected by the proper design and completion of the wells, ongoing /periodic mechanical integrity evaluation required for all injection wells and review of the offset wells to ensure that they won't act as conduits to fluid movement. NOW THEREFORE IT IS ORDERED THAT: Part 2 of Rule 1 of AIO 14A is repealed and replaced by the following: 2) Authorized Injection Fluids: a. Produced water from Prudhoe Bay Unit processing facilities; b. Non - hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based AIO 14A.003 • • September 4, 2012 Page 3 of 3 fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 10 degrees F); c. Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti - foams /emulsion breakers; v. Glycols d. Non - hazardous glycols and glycol mixtures; e. Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides f. Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; � OIL q,Vb iii. Reservoir profile modification fluids. •TY 5 ,\ ; i / . r DONE at Anchorage, Alaska and dated September 4 2012. ��. v +{ w • /� , V' ,B !E 9 `N - � �k��T10N vo Daniel T. " eamount, Jr. o 1 . o rman Commissioner issioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within l0 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Thursday, September 06, 2012 1:49 PM To: 'Aaron Gluzman'; 'Aaron Sorrell'; 'Bruce Williams'; Bruno, Jeff J (DNR), ; 'CA Underwood'; 'Casey Sullivan'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Eric Lidji'; 'Erik Opstad'; Franger, James M (DNR); 'Gary Orr; 'Graham Smith'; 'Greg Mattson'; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Jennifer Starck'; 'Jill McLeod'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; OilGas, Division (DNR sponsored); 'Patricia Bettis'; Perrin, Don J (DNR); 'Peter Contreras'; Pexton, Scott R (DNR); 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster; 'Wendy Wollf; 'William Hutto'; 'William Van Dyke'; '( michael .j.neison @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWeIIlntegrityCoordinator; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Bruce Webb'; 'Claire Caldes'; 'Cliff Posey; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Harbour; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Scott; 'David Steingreaber; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'Francis S. Sommer; 'Gary Laughlin'; 'Gary Schultz (gary.schultz @alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'Gregory Geddes'; 'gspfoff; 'Jdariington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones (jeff.jones @alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'Jon Goltz'; Jones, Jeffrey L (GOV); 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Kari Moriarty; 'Kayneli Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen @alaska.gov)'; 'Luke Keller; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark P. Worcester; 'Marguerite kremer (meg.kremer @alaska.gov)'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike Morgan'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'Paul Mazzolini'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Stephanie Klemmer; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tim Mayers'; 'Tina Grovier; 'Todd Durkee'; 'Tony Hopfinger; 'trmjrl'; Vicki Irwin'; 'Walter Featherly; Williamson, Mary J (DNR); 'Yereth Rosen'; Bailantine, Tab A (LAW); Bender, Makana K (DOA); 'Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov)'; 'Colombie, Jody J (DOA) (jody.colombie @alaska.gov)'; 'Crisp, John H (DOA) (john.crisp @alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies @alaska.gov)'; Ferguson, Victoria L (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov)'; 'Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov)'; 'Laasch, Linda K (DOA) (linda.laasch @alaska.gov)'; 'McIver, Bren (DOA) (bren.mciver @alaska.gov)'; 'McMains, Stephen E (DOA) (steve.mcmains @alaska.gov)'; Mumm, Joseph (DOA sponsored); 'Noble, Robert C (DOA) (bob.noble @alaska.gov)'; 'Norman, John K (DOA) (john.norman @alaska.gov)'; 'Okland, Howard D (DOA) (howard.okland @alaska.gov)'; 'Paladijczuk, Tracie L (DOA) ( tracie .paladijczuk @alaska.gov)'; 'Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov)'; 'Regg, James B (DOA) (jim.regg @alaska.gov)'; 'Roby, David S (DOA) (dave.roby @alaska.gov); 'Scheve, Charles M (DOA) (chuck.scheve @alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount @alaska.gov)'; Wallace, Chris D (DOA) Subject: aiol4a -003 Niakuk Oil Pool Attachments: aiol4a -003. pdf 4 • • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515-4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough , Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669 -7714 c(\ 4 \ / 0 916 \\ AtiOF T�� • • THE STATE Alaska Oil and Gas „ALAsKA Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue of Q. Anchorage, Alaska 99501 -3572 ALA Main: 907.279.1 433 Fax: 907.276.7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 14A.003 AMENDED Ms. Alison Cooke UIC Compliance Advisor BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 RE: Authorized Fluids for EOR and Pressure Maintenance of the Niakuk Oil Pool Dear Ms. Cooke: The Alaska Oil and Gas Conservation Commission has amended the Administrative Approval to correct an error in the description of non - hazardous water based fluids. The correction occurs in two locations and is shown in underlined text below. By letter dated April 30, 2012, BP Exploration (Alaska) Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) administratively amend the following Area Injection Orders (AIO): 3A, 4E, 14A, 20, 22E, 24B, 25A, 26B and 31. BPXA requested the amendments in an effort to standardize the fluids authorized for injection for enhanced recovery and pressure maintenance for the oil pools in the Prudhoe Bay Field. BPXA requested the standardization due to the complexity of managing injection operations for multiple pools, with different lists of authorized fluids, which are served by common production facilities. In accordance with terms set forth below, BPXA's request is partially APPROVED, with a minor change to the wording proposed by BPXA. BPXA's request to inject produced gas and enriched hydrocarbon gas is hereby DENIED. BPXA proposes that AIO No. 14A be modified to approve the following for EOR and pressure maintenance injection. - Produced water and gas; - Enriched hydrocarbon gas; - Non - hazardous water and water based fluids — (includes seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); - Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the AIO 14A.003 Amended • October 9, 2012 Page 2 of 4 produced water stream after oil, gas, and water separation in the facility. Includes but not limited to: o Freeze protection fluids; o Fluids in mixtures of oil sent for hydrocarbon recycle; o Corrosion/scale inhibitor fluids; o Anti -foams /emulsion breakers; o Glycols - Non - hazardous glycols and glycol mixtures; - Fluids that are used for their intended purpose within the oil production process. Includes: o Scavengers; o Biocides - Fluids to monitor or enhance reservoir performance. Includes: o Tracer survey fluids; o Well stimulation fluids; o Reservoir profile modification fluids. As shown above, the list of fluids for which BPXA seeks approval uses the terms "includes" and "includes but not limited to." Words such as "includes" and "including" along with phrases such as "includes but is not limited to" inappropriately delegate to BPXA the authority to determine what additional fluids are approved. Therefore, this approval modifies BPXA's proposal to delete the use of any such language as set forth below. In support of its application, BPXA submitted a fluid compatibility review based on previous orders and laboratory testing. This review showed that the proper handling and treating, including the use of scale inhibitors, of the injection fluids as well as the proper operation and maintenance, including the pumping of scale remover and acid treatments, of the injection wells will prevent or counteract incompatibility effects. Thus there are no operational risks associated with injection of the proposed fluids in this pool. It has not been demonstrated that the injection of produced gas or enriched hydrocarbon gas will enhance recovery from this pool. Therefore, BPXA's request to allow gas injection in this pool is denied. The change proposed by BPXA will result in increased production, is based on sound engineering and geotechnical reasons, does not promote waste or jeopardize correlative rights, and will not result in increased risk of fluid movement into freshwater. Correlative rights are protected because all lands subject to these orders have been unitized. Freshwater is protected by the proper design and completion of the wells, ongoing/periodic mechanical integrity evaluation required for all injection wells and review of the offset wells to ensure that they won't act as conduits to fluid movement. NOW THEREFORE IT IS ORDERED THAT: Part 2 of Rule 1 of AIO 14A is repealed and replaced by the following: AIO 14A.003 Amended • October 9, 2012 Page 3 of 4 2) Authorized Injection Fluids: a. Produced water from Prudhoe Bay Unit processing facilities; b. Non - hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); c. Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti -foams /emulsion breakers; v. Glycols d. Non - hazardous glycols and glycol mixtures; e. Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides f. Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. NUNC PRO TUNC September 4, 2012 j oILA% DONE at Anchorage, Alaska and dated October 9, 2012. , / � ♦ 1J�y .y` Daniel T. Seamount, Jr. � ' . No an �k Commissioner I mmi : oner li Ti N o'' AIO 14A.003 Amended • • October 9, 2012 Page 4 of 4 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston St., Ste. 200 5333 Westheimer, Ste. 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 18th President 40818 St. 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil pools P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Fairbanks, AK 99711 Anchorage, AK 99503 Anchorage, AK 99515-4295 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Cir. P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669 -7714 \c'kcVL \V t \cD(_e_3`2 • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, October 09, 2012 3:37 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); 'Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov)'; 'Colombie, Jody J (DOA) (jody.colombie @alaska.gov)'; 'Crisp, John H (DOA) ohn.cris alaska. ov '; 'Davies, Stephen F (DOA) ( )U p@ 9 ) ; (steve.davies @alaska.gov) ,Ferguson, Victoria L (DOA); Foerster, Catherine P ( DOA ) (cathy.foerster @alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov)'; 'Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov)'; 'Jones, Jeffery B (DOA) (jeff.jones @alaska.gov)'; 'Laasch, Linda K (DOA) (linda.laasch @alaska.gov)'; 'McIver, Bren (DOA) (bren.mciver @alaska.gov)'; 'McMains, Stephen E (DOA) (steve.mcmains @alaska.gov)'; Mumm, Joseph (DOA sponsored); 'Noble, Robert C (DOA) (bob.noble @alaska.gov)'; 'Norman, John K (DOA) (john.norman @alaska.gov)'; 'Okland, Howard D (DOA) (howard.okland @alaska.gov)'; 'Paladijczuk, Tracie L (DOA) ( tracie .paladijczuk @alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual @alaska.gov)'; 'Regg, James B (DOA) Dim.regg @alaska.gov)'; 'Roby, David S (DOA) (dave.roby @alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve @alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount @alaska.gov)'; Singh, Angela K (DOA); Wallace, Chris D (DOA); 'Aaron Gluzman'; 'Aaron Sorrell'; 'Bruce Williams'; Bruno, Jeff J (DNR); 'CA Underwood'; 'Casey Sullivan'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Eric Lidji'; 'Erik Opstad'; Franger, James M (DNR); 'Gary Orr; 'Graham Smith'; 'Greg Mattson'; Heusser, Heather A (DNR); 'James Rodgers'; 'Jason Bergerson'; 'Jennifer Starck'; 'Jill McLeod'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Matt Gi ll'; 'Ostrovsky, Larry Z (DNR)'; 'Patricia Bettis'; Perrin, Don J (DNR); 'Peter Contreras'; Pexton, Scott R (DNR); 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster; 'Wendy Wollf; 'William Hutto'; 'William Van Dyke'; '( michael .j.nelson @conocophillips.com)'; '(Von.L. Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Bruce Webb'; 'Claire Caldes'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Harbour; 'Dave Matthews'; 'David Boelens'; 'David Duffy'; 'David House'; 'David Scott; 'David Steingreaber; 'Davide Simeone'; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elowe, Kristin'; 'Francis S. Sommer; 'Gary Laughlin'; 'Gary Schultz (gary.schultz @alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'Gregory Geddes'; 'gspfoff; 'Jdarlington Darlington @gmail.com)'; 'Jeanne McPherren'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'John Garing'; 'John Spain'; 'Jon Goltz'; Jones, Jeffrey L (GOV); 'Judy Stanek'; 'Julie Houle'; 'Julie Litt le'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen @alaska.gov)'; 'Luke Keller; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark P. Worcester; 'Marguerite kremer (meg.kremer @alaska.gov)'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike Morgan'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'Paul Mazzolini'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Stephanie Klemmer; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Thor Cutler; 'Tim Mayers'; 'Tina Grovier; 'Todd Durkee'; 'Tony Hopfinger; 'trmjrl'; 'Vicki Irwin'; 'Walter Featherly'; 'Yereth Rosen' Subject: aiol4a -003 amended Attachments: aiol4a -003 amended.pdf 1 THE STATE Alaska Oil and Gas °fALAS_KA Conservation Commission GOVERNOR BILL WALKER ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 14A.004 Mr. Douglas A. Cismoski Well Intervention Manager BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-15-022 Request for administrative approval to allow well NK-10 (PTD 1931840) to be online in water only injection service with known inner annulus repressurization. Prudhoe Bay Unit (PBU) NK-10 (PTD 1931840) Prudhoe Bay Field Niakuk Oil Pool Dear Mr. Cismoski: By letter dated May 28, 2015, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 8 of Area Injection Order (AIO) 014A.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 1, 2015 which indicates that NK-10 exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 83 psi/day and AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 14A.004 June 4, 2015 Page 2 of 2 AOGCC's approval to continue water injection only in PBU NK-10 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2500 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is May 1, 2015. DONE at Anchorage, Alaska and dated June 4, 2015. Cathy . Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. 'that appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, June 04, 2015 2:06 PM To: DOA AOGCC Prudhoe Bay; Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWeIIIntegrityCoordinator Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff, Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey, Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCa►eb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Hulme, Rebecca E (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty, Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke Subject: AIO 14A.004 and AIO 18C.003 Attachments: aiol8c-003.pdf, aiol4a-004.pdf Aio 14A-004 (BP) PBU NK-10 Administrative Approval Aio 18C-003 (CPA) CD4-17 Administrative Approval Bernie Karl James Gibbs Jack Hakkila K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Douglas A. Cismoski Richard Wagner Darwin Waldsmith Well Intervention Manager P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99519-6612 Angela K. Singh Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 14A.005 Mr. Bo York Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-24-028 Request for Administrative Approval to Area Injection Order 14A; Water Injection Prudhoe Bay Unit (PBU) NK-18 (PTD 1931770), Niakuk Oil Pool Dear Mr. York: By emailed letter dated September 3, 2024, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water injection with a known inner annulus repressurization. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue water only injection in the subject well. Hilcorp reported a potential Inner annulus (IA) repressurization to AOGCC on July 23, 2024, and initiated additional diagnostics and monitoring. Hilcorp completed a passing state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 2,440 psi) on August 25, 2024. This indicates that NK-18 exhibits at least two competent barriers to the release of well pressure. Hilcorp maintains live transmitters on the inner and outer annulus (OA) and alarm functions in the Supervisory Control and Data Acquisition (SCADA). AOGCC believes Hilcorp can safely manage the slow IA repressurization with periodic pressure bleeds by maintaining the IA to a pressure not to exceed 2,100 psi and OA not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue water only injection in PBU NK-18 is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) Hilcorp shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; AIO 14A.005 September 12, 2024 Page 2 of 2 4) Hilcorp shall limit the well’s inner annulus operating pressure to 2,100 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8) The next required MIT shall be completed before or during the month of August 2026. DONE at Anchorage, Alaska and dated September 12, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.12 15:25:16 -05'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.12 12:39:49 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 14A.005 (Hilcorp) Date:Thursday, September 12, 2024 12:48:41 PM Attachments:aio14A.005.pdf Docket Number: AIO-24-028 Request for Administrative Approval to Area Injection Order 14A; Water Injection Prudhoe Bay Unit (PBU) NK-18 (PTD 1931770), Niakuk Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 14A.005 AMENDED Mr. Bo York Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-24-028 Request for Administrative Approval to Area Injection Order 14A; Water Injection Prudhoe Bay Unit (PBU) NK-18 (PTD 1931770), Niakuk Oil Pool Dear Mr. York: By emailed letter dated September 3, 2024, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water injection with a known inner annulus repressurization. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue water only injection in the subject well. Hilcorp reported a potential Inner annulus (IA) repressurization to AOGCC on July 23, 2024, and initiated additional diagnostics and monitoring. Hilcorp completed a passing state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 2,440 psi) on August 25, 2024. This indicates that NK-18 exhibits at least two competent barriers to the release of well pressure. Hilcorp maintains live transmitters on the inner and outer annulus (OA) and alarm functions in the Supervisory Control and Data Acquisition (SCADA). AOGCC believes Hilcorp can safely manage the slow IA repressurization with periodic pressure bleeds by maintaining the IA to a pressure not to exceed 2,500 psi and OA not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue water only injection in PBU NK-18 is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) Hilcorp shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; AIO 14A.005 Amended September 19, 2024 Page 2 of 2 4) Hilcorp shall limit the well’s inner annulus operating pressure to 2,500 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8) The next required MIT shall be completed before or during the month of August 2026. DONE at Anchorage, Alaska and dated September 19, 2024, Nunc pro tunc September 12, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.19 08:23:16 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.19 08:32:21 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 14A.005 Amended (Hilcorp) Date:Thursday, September 19, 2024 9:08:28 AM Attachments:aio14A.005 amended.pdf Docket Number: AIO-24-028 Request for Administrative Approval to Area Injection Order 14A; Water Injection Prudhoe Bay Unit (PBU) NK-18 (PTD 1931770), Niakuk Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 20 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 09/03/2024 Commissioner Jessie Chmielowski and Commissioner Greg Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Niakuk well NK-18 (PTD #193177). Request for Administrative Approval to allow continued water injection operations. Commissioner Jessie Chmielowski and Commissioner Greg Wilson, Hilcorp North Slope, LLC requests administrative approval to allow for continued water injection into Naikuk well NK-18 with slow tubing x inner annulus (IA) communication. Water injection well NK-18 was initially flagged as having possible slow IA re-pressurization on 07/23/2024. The well was immediately reported to the AOGCC with a plan to continue monitoring the IA pressure for indication of tubing x inner annulus (IA) communication. On 07/29/2024, NK-18 was placed under evaluation and the AOGCC notified due to continuing IA repressurization trends. The tubing hanger passed a pressure test to 5000 psi on 07/25/2024. An AOGCC witness MIT-IA was conducted on 08/25/2024 and passed to 2440 psi confirming the integrity of the primary and secondary well barriers. The maximum anticipated injection pressure for NK-18 is approximately 2360 psi. Hilcorp North Slope, LLC has determined that well NK-18 is safe to operate in its current condition and requests administrative approval based on the following conditions: x IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. x Passing pressure test of the primary and secondary barriers. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic By Samantha Coldiron at 1:03 pm, Sep 05, 2024 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2024.09.03 13:13:12 - 08'00' Bo York (1248) Niakuk Well NK-18 Technical Justification for Administrative Approval Request 09/03/2024 Well History and Status Well NK-18 was a drilled in 1993 as a sea water injector (SWI). NK-18 was initially flagged as having possible slow IA re-pressurization on 07/23/2024 while on injection and was then placed under evaluation on 07/29/2024 due to continuing IA repressurization trends. The tubing hanger passed a pressure test to 5000 psi on 07/25/2024. An AOGCC witness MIT-IA was conducted on 08/25/2024 and passed to 2440 psi. Recent Well Events: 12/12/2021 AOGCC MIT-IA passed to 2441 psi 07/23/2024 AOGCC notified of suspected IA repressurization. 07/25/2024 PPPOT-T passed to 5000 psi 07/29/2024 Well placed under evaluation. 08/25/2024 Online AOGCC witnessed MIT-IA passed to 2440 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing online pressure test conducted on 08/25/2024, to 2440 psi, which tested both barriers, demonstrates competent primary and secondary barrier systems. Due to the low IA repressurization rate, no logging or further repair attempt is planned at this time due to the low likelihood of locating the leak point. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rates daily; 2. Submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Perform a MITIA every two years to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 5. Limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6. Monitor the inner and outer annulus pressures in real time with SCADA system; 7. Immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; TIO/ Injection Plot Wellbore Schematic 19 BP Exploration (Alaska) Inc. Douglas A. Cismoski, P.E., BPXA Wells Intervention Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 May 28, 2015 RECEIVED by JUN O 1 2015 AOGCC Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Niakuk well NK-10 (PTD # 1931840) Request for Administrative Approval to Continue Water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue water injection operations into Niakuk well NK-10. Well NK-10 exhibits manageable inner annulus repressurization of -83 psi/day. A pressure test of the inner annulus passed to 2500 psi on 5/1/2015, indicating the tubing and production casing are competent. For continued operation of the well the inner annulus operating pressure shall be maintained below the MOASP of 2500 psi. In summary, BPXA believes Niakuk well NK-10 is safe to operate as stated above and requests administrative approval for continued water injection operations, managing the IA repressurization with periodic annular bleeds. If you have any questions, please call me at 564-4303 or Whitney Pettus/ Kevin Parks at 659-5102. Sincerely, Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Pettus/ Parks GPMA Operations Team Leader Travis Alatalo Ryan Daniel Prudhoe Bay Well NK-10 Technical Justification for Administrative Approval Request May 28, 2015 Well History and Status Niakuk well NK-10 (PTD #1931840) exhibits manageable inner annulus repressurization indicated by wellhead pressure trends on the TIO plot. A MIT -IA to 2500 psi passed on 05/01/2015 indicating competent tubing and production casing. The recorded IA build up rate while the well was on injection between 05/05/2015 and 05/11/2015 was -83 psi/day and can be managed with periodic IA bleeds. Recent Well Events: ➢ 05/01/2015: MIT -IA passed to 2500 psi ➢ 05/11/2015: 83 psi/day IA build up rate ➢ 05/19/2015: PPPOT-T passed to 5000 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A pressure test of the inner annulus passed to 2500 psi, demonstrating competent primary and secondary barriers systems. Pressure on the inner annulus is maintained below the normal operating limit of 2500 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a monthly report of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT -IA to maximum injection pressure. 4. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well NK-10 TIO Plot NK-10 TIO PIo1 Dale 4an,'End 5/10201a i 5ROg0t5 Reload Plot 1 TO G,,d 5 e 1. _ Ctiaaoa�d '', Gunn. Vdue %F05/16 -2014 V r 3.335 Well NK-10 Injection Plot Date Stw/Endd 5'�< 5247J,5 --%J r Mg God r Log Scale To Qpggmtl C—Vakn XFI-073 pid v (- %dso TREE- 4-1/16' -5MCFN 1351W-5MFW Y�LtfAD UNVER5AL SLPA DLE ACTUATOf+= BAD KB EEV = 61.1' BF B-EV = 23.6' KOf — 700, Max Angle - 56 @ 4400' Datum M) = 13210' Diatum TVD= 92W SS 10-3J4- tSG, 45.5A, W-80, D = 9.953- 668T Minimum ID = 3.725" @ 13010' 14-1r2" HES'XN' NIPPLE SAFETY NOTES. WELL REQUIRES SSSY N K- ■ O —� 2144' �--� 41l2' FES CTx2 TRSSSV . ID = 3 813' GAS LIFT MANS TVD OEV TYF£MAN STA MD LATCH 6 3680 2947 ! 55 OTIS TH3M BK-5 5 7704 5328 53 OTIS TM30X BK-5 4 10542 7010 53 OTIS TM41X BK 5 !. 3 12032 W85 31 OTIS TM'DX B145 2 12691 8683 16 OTIS TMCX BK-5 1 12837 8824 14 OTIS TM CX BK-5 4.1 Q- NP, HES X. ID = 3.813- 12962' 7-5W X 4-112' R(R BAKER SABI VWANCNOR LA1(?I, D = 3 93?- 12992' 4 112" MP, IES X, D - 3.813- 13010' N 4-V2" NP, HES XN, D= 3.725" 1 T F 4-112' T8G. 12.6A, L-80, 0.0152 6pf. D = 3.458' 33037 13632' 4-1/7 TUBING TAIL MEG, 1)= 4.00" 12946' EL TT - LOGG®03106� PERFORATION SUMMARY REF LOG. SBT 01t06194 ANGLE AT TOP PERF 9 @ 13132 wwe- u to. +.. 9*M.-i— FIR tot h-tercal oeti data SIZE SPF z GATE 33f8' 6 13132-13192 O 03106/94 3-3/8" 5 1319Z-13202 O 17J14195 3-3/8' 6 13202-13248 O 06i02M 3.318" 6 13272-13296 O 06102196 PBTD 1-516- LNK 29-7A. NI-95 H5, 0-0459 Opt, D = 6.81! 1 13730' 1 DATE REV BY ODUMME JTS DATE REV BY COARueJTS 12121190 ORIGINAL COMPLEnON 091D8f06 CSIP.IC TV 1Y M) ❑ATlld CORRFC it) ---_--- 02/18111 M IAD ADDED SSSV SAFETY NOTE _ 03/23/14 1 GJH PJC TRSSSV U MTE M AKU< UHT VV8.1: NK-10 FRWT No 93,184 AR W 50-029-22425-00 Sec. 36. T12N R1 *- 1043.63 FEL 2329.21 FNL BP BwwaUon Wwka) 418 bp • • BP Exploration (Alaska) Inc. E 0. Box 196612 900 E. Benson Boulevard Anchorage, AK 99519 -6612 USA CERTIFIED MAIL # 7011 2970 0003 5821 9955 ECEI E April 30, 2012 MAY 0 2 2012 Kathy Foerster, Commissioner AOGCC Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Prudhoe Bay Field Area Injection Orders, Standardization of Authorized Fluids for EOR and Pressure Maintenance Dear Ms. Foerster, This letter is to request a change to Prudhoe Bay Field (PBF) Area Injection Orders (AIO) to standardize the language in the rule referencing the fluids authorized for injection for enhanced recovery and pressure maintenance. BP Exploration (Alaska) Inc. (BPXA) is requesting this change in order to address the complexity of field operations with multiple pools serviced by common facilities and potential confusion that results from the differing language in the various orders. This proposed change is intended to clarify and document the fluids that are authorized for enhanced oil recovery (EOR) and pressure maintenance injection within the PBF and provide greater compliance assurance for our field operations. A review of AIOs for pools in the PBF indicates that some contain very general language and some are very specific in defining which fluids are authorized for injection. The language defining fluids that may be injected has changed over time in successive versions of some of the orders. For instance, AIO 4 language has changed from "non- hazardous fluids ", to "Class II fluids" to "authorized fluids ". In addition, some fluids have received specific authorization via administrative approvals. The diversity of language and changes over time has resulted in confusion over which fluids are actually authorized for injection. The enclosed list (Attachment A) shows the various PBF pools, AlOs, and a summary of the current rule and /or administrative approvals that authorize fluids that may be injected for purposes of pressure maintenance and enhanced recovery. Also included is a summary of findings regarding the compatibility of fluids authorized for injection. As discussed with your staff, BPXA proposes to standardize the list of authorized fluids for the various pools within the PBF. Attachment B is proposed language for this change. In some pools, additional clarification may be required to capture specific conditions or restrictions contained in current orders. Attachment C is a list of historical fluids injected for EOR and pressure maintenance Alaska Oil and Gas Conservation Commission April 30, 2012 Page 2 Should you have any questions, or require additional information, please contact me at 564- 4838. Sincerely, Alison Cooke UIC Compliance Advisor Attachments cc: Jim Regg AOGCC Dave Roby AOGCC Alaska Oil and Gas Conservation Commission • April 30, 2012 Page 3 Attachment A Prudhoe Bay Field: fluids specifically authorized for enhanced recovery and pressure maintenance in Area Injection Orders AIO Rule Pool Fluids Authorized Compatibility with Formation 3 1 Prudhoe non - hazardous fluids; Area Injection Order Application for PBU WOA Bay AIO 3.03 rinsate (minus FOR and Fluid Disposal Wells: Section I: 1. (West) solids) from cleaning aerial Water: Beaufort Sea water and Produced gas coolers; Sadlerochit water; Compatibility: Water AIO 3.018 filtered and sensitivity tests on core samples showed no chemically treated lake significant problems with formation plugging or water used for hydrotesting clay swelling over the anticipated operating range replacement pipeline of salinities for produced and Beaufort Sea water; segments; 2. Miscible Gas from CGF; Compatibility: Full AIO 3.028 mixtures of glycol compatibility - reinjected into producing zone; 3. and water Produced Gas from Sadlerochit and Sag River reservoirs; Compatibility: Full compatibility - reinjected into producing zone 4E 1 Prudhoe authorized fluids; AIO4D, Finding 12: The main fluid source will be Bay (East) AIO 4C.02 rinsate (minus source water from the Seawater Treatment Plant. Put River solids) from cleaning aerial No significant compatibility issues are anticipated Lisburne gas coolers; between the formation and injected fluid. Pt. AIO 4E.022 filtered and Analyses of core samples from Put River McIntyre chemically treated lake Formation sandstone in Prudhoe Bay West water used for hydrotesting Unit Well 2 -14 demonstrate similar clay mineral Beach replacement pipeline types and proportions as those in Kuparuk River Stump segments for Greater Point Formation reservoirs in adjacent North Slope Island McIntyre; fields. Each of the analog fields has a successful AIO 4E.023 filtered and history of waterflooding and based on these chemically treated lake comparisons the water used for hydrotesting Put River Formation is not anticipated to have replacement pipeline compatibility issues related to seawater injection. segments for Prudhoe Bay A1O4C, Finding 20: Seawater is currently injected Unit fields; in the Pt. McIntyre waterflood. It is possible that AIO 4E.034 mixtures of produced water will be used later in the project. glycol and water Both water sources have previously been approved in Area Injection Order No. 4B Finding 34: Laboratory testing, core analyses and geochemical modeling indicate no significant problems are likely due to clay swelling or in -situ fluid compatibility problems between WBOP and Tertiary formation waters. Finding 35: WBOP waterflood source water from the Sagavanirktok Formation is expected to have excess barium ion which could precipitate barium sulfate scale if mixed with PMOP produced water. WBOP produced water will be inhibited upstream of the commingling point with PMOP fluids to prevent scale precipitation. • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 4 PBU EOA Area Injection Order Application, Section I Enhanced Recovery type of fluid: A. source water - treated seawater; Compatibility: no significant problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated; B. produced water from Flow Stations and LPC; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated; C. Natural Gas and NGL; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated; D. Miscibile Injectant; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated. 14A 1 Niakuk produced water from LPC, AIO14A, Finding 7: Injection will utilize either Beaufort seawater, produced or source water. The wells are currently trace amounts of scale configured to allow 60,000 Barrels of Water per inhibitor, corrosion inhibitor, Day ( "BWPD ") total, with a maximum injection of emulsion breakers, other up to 70,000 BWPD. The produced water will be products used in production a mix of Pt. McIntyre, West Beach, North process, stimulation fluids Prudhoe Bay, Lisburne and Niakuk produced water separated through the Lisburne Production Center ("LPC"), with the majority coming from Pt. McIntyre. Seawater has been injected as well. SEM, XRD and ERD analyses conducted on Niakuk core indicate very low clay content in reservoir intervals. As a result no significant problems with formation plugging or clay swelling due to fluid incompatibilities is expected. Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. 20 1 Midnight fluids appropriate for A1020 Finding 21: Geochemical model results Sun enhanced recovery; indicate that a combined Tertiary water and AIO 20.001 filtered and connate water is likely to form calcium carbonate chemically treated lake and barium sulfate scale. Similar scale water used for hydrotesting precipitation is anticipated for produced water. replacement pipeline Scale will be controlled with commonly available segments inhibitors. • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 5 22E 10 Aurora produced water, Prince A1022B, Finding 9: The compositions of injection Creek source water*, water and AOP connate water were provided in enriched hydrocarbon gas *, Exhibit IV -4 of the original AIO application. Water immiscible hydrocarbon analysis from the nearby Milne Point Prince gas *, tracer survey fluid, Creek Formation was provided in the April 28, non- hazardous filtered 2003 application for rehearing water from pads and cellars *conditions for authorization are included in the current order 24B 2 Borealis produced water, non- A1024A, Finding 9: As previously approved by hazardous filtered water the Commission, produced water from GC -2 is from pads and cellars, used as the primary water source for Borealis tracer survey fluid, treated injection. Injection performance, core, log and seawater, enriched pressure - buildup analyses indicate no significant hydrocarbon gas *, Prince problems with clay swelling or compatibility with Creek source water; in -situ fluids. BPXA analysis of cores from the AIO 24A.001 filtered and BOP wells indicates relatively low clay content. chemically treated lake Petrographic analysis indicates that clay volumes water used for hydrotesting in the better quality sand sections ( >20 md) are in replacement pipeline the range of 3 - 6 %. Clay volumes increase to segments approximately 6 - 12% in rock with permeabilities in the range of 10 - 20 md. Below 10 md, clay volumes increase to a range of 12 - 20 %. Most of the identified clay is present as intergranular matrix, having been intermixed with the sand through burrowing. The overall clay composition is a mixture of roughly equal amounts of kaoiinite, illite and mixed layer illite /smectite. No chlorite was reported during petrographic analysis. The presence of iron - bearing minerals suggests that *conditions for authorization the use of strong acids should be avoided in are included in the current breakdown treatments, spacers, etc. Water from order the seawater treatment plant has been successfully used for injection within the Kuparuk of the Pt. McIntyre Oil Pool. Geochemical modeling indicates that a combination of GC -2 produced water and connate water is likely to form calcium carbonate and barium sulfate scale in the production wells and downstream production equipment. Scale precipitation will be controlled using scale inhibition methods similar to those used at Kuparuk River Unit and Milne Point Unit. Miscible gas is a hydrocarbon with similar composition to reservoir fluids in the BOP therefore no compatibility issues are anticipated with the formation or confining zones. The composition of injection water from the Prince Creek aquifer is expected to fall within the range of Well W-400 and MPF -02 produced water • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 6 compositions, less than 10,000 -ppm total dissolved solids. Milne Point Unit F -Pad Prince Creek source water has been injected since 1996 into the Milne Point Kuparuk Reservoir, lithologically similar to the BOP, with no apparent formation damage. A single well chemical tracer test in BOP well L -122 conducted using 640 barrels of Prince Creek Source water did not detect any formation damage. 25A 3 Polaris produced water, tracer AIO 25A, Finding 11: The enriched gas proposed survey fluid, enriched for injection is a hydrocarbon with similar hydrocarbon gas, treated composition to reservoir fluids in the Polaris Oil seawater, non - hazardous Pool and therefore no compatibility issues are filtered water from pads and anticipated. cellars, enriched AIO 25, Finding 12: BPXA provided laboratory hydrocarbon gas; analysis of the injection and produced waters. No AIO 25A.001 filtered and significant compatibility problems are evident chemically treated lake from these analyses. Disposal of PBU produced water used for hydrotesting water within the Ugnu sands has successfully replacement pipeline occurred in other parts of the field. segments 26B 3 Orion enriched gas, produced AIO 26A, Finding 11: The enriched gas proposed water, tracer survey fluid, for injection is a hydrocarbon with similar treated seawater, Prince composition to reservoir fluids in the Orion Oil Creek source water, non- Pool and therefore no compatibility issues are hazardous filtered water anticipated. from pads and cellars, non- AIO 26, Finding 11: The composition of produced hazardous filtered lake water will be a mixture of connate water and water employed for injection water, and will change over time hydrotesting pipeline depending on the rate and composition of segments injection water. Based on analyses of Polaris water samples, no significant compatibility problems are expected between connate water and injection water. 31 3 Raven produced water, tracer AIO 31, Finding 14: Water compatibility problems survey fluid, stimulation are not expected because of the successful fluids, source water from history of both sea water and produced water STP, and non - hazardous injection into the Prudhoe Bay Reservoir. No clay water collected from well swelling problems have been seen in the Ivishak house cellars and standing Formation in the Ivishak Participating Area of the ponds. PBU (IPA) with either source water injection or produced water injection. When present, scaling in the Ivishak Formation in the IPA has been limited to calcium carbonate deposition, which has been eliminated with acid treatments and controlled with the use of inhibitors. Minimal problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 7 Attachment B Proposed Standardized List of Fluids Authorized for Injection in Prudhoe Bay Field Pools Fluids authorized for injection include: • Produced water and gas; • Enriched hydrocarbon gas • Non - Hazardous Water and water based fluids — (includes seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 140 degrees F) • Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas and water separation in the facility. Includes but not limited to: • Freeze protection fluids; • Fluids in mixtures of oil sent for hydrocarbon recycle • Corrosion /Scale inhibitor fluids • Anti - foams /emulsion breakers • Glycols • Non - hazardous glycols and glycol mixtures • Fluids that are used for their intended purpose within the oil production process. Includes: • Scavengers; • Biocides • Fluids to monitor or enhance reservoir performance. Includes: • Tracer survey fluids; • Well stimulation fluids • Reservoir profile modification fluids f • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 8 Attachment C Historical Fluids Injected for FOR and Pressure Maintenance: these fluids were authorized and injected under the general descriptions of authorized fluids: AIO 4, 4A, and 4B: Class II fluids; AIO 4C: authorized fluids; AIO 3: non - hazardous fluids Treated Seawater supplied from PBU STP. Contains small amounts of chemicals: coagulant, anti -foam, scale inhibitor, biocide, oxygen scavenger and other process chemicals. Produced water from PB field producing formations. Contains small amounts of entrained produced oil and gas, and chemicals: scale inhibitor, corrosion inhibitor, emulsion breaker, and other production process chemicals. Natural Gas (including natural gas liquids) from PB field producing formations. Miscible Injectant from PBU Central Gas Facility. Reserve Pit water from pit dewatering operations. Consists of precipitation and small amounts of drilling wastes and chemicals (oxygen scavenger and biocide). ( Y9 . 9 ) Source water from shallow formations. Contains small amount of production chemicals (scale inhibitor). 017 • • BP closes site over loss in Slope rent dispute N *c,.�vA..Fkc\�c C HEALD POINT: Oengas fight oil giant over rent for use of their land. C6- N By ELIZABETH BLUEMINK ‘V----1 ° c `� ebluemink @adn.com \L-- cos f a QS - 0 ( p" N �\ — 3 Published: January 4th, 2011 . 10:09 P M \L— �'\3 � O\ Last Modified: January 4th, 2011 10:09 PM N \L— \ C N a O \ -a' BP shut down a small portion of the Prudhoe Bay oil field last week after a judge ruled that federal regulators failed for years to get approval from the Inupiat Eskimo family that owns the land. (.0 s'c tmuon a .+t ttolw.n` 0 .. _„ s kh — ton ,--• ` "r w....- ,Nr$dwa '.hp -. Y. o-ie'u 1 °i r "+ .,, .... A _ . • y ., Photo courtesy of BP Exploration (Alaska) Inc. Heald Point drill pad at Prudhoe Bay has been used to access oil from several oil pools, including Raven. The BIA told BP to suspend Raven production in late December due to a court ruling. Read more: http: / /www.adn.com/ 2011 /01 /04/v- gallery /1631936/bp- closes- site - over - loss- in- rent.html #ixzzl AB7r0Ir1 • . The shutdown affects less than 1 percent of production from the nation's largest oil field, but so far it's the most visible consequence of a significant legal victory for the Native family, which has battled lawyers for the federal Bureau of Indian Affairs and BP in federal court over the oil production from its land. Federal claims court judge Nancy Firestone ruled this fall that the Oenga family is owed millions in unpaid rent because the BIA improperly allowed BP to tap three offshore oil deposits from the family's allotment on the northern edge of the vast Prudhoe oil field. The BIA approved BP's expanded use of the allotment without the family's consent, in violation of the family's contract with BP, Firestone said in her 168 - page ruling on Nov. 22. A week ago, the BIA told BP to shut down production from Prudhoe's Raven unit, the only one of the three disputed offshore deposits that BP was still accessing from the allotment. BP shut down Raven, which produced about 25,000 barrels of oil in November, on Friday. BP is still legally tapping the Niakuk field from the allotment. The battle over unpaid rent and unauthorized land use involves a nondescript finger of land called Heald Point that extends into the Beaufort Sea. The Oenga family acquired its 40 -acre allotment at Heald Point decades ago for subsistence hunting. But in 1989, the family patriarch, Andrew Oenga, signed a contract with BP allowing the oil giant to use Heald Point as a right of way. Years later, believing that BP was giving the family annual rent payments much lower than the land's true value, eight of Oenga's heirs -- including two children, his grandchildren and great - grandchildren -- sued the BIA in 2005. The family said it had to go to court because it was unable to persuade the agency, which is in charge of collecting the family's rent from BP, to take action on its behalf. In an eight -day Lower 48 trial last July, the agency and the oil giant defended themselves against the Oengas' claims. BP argued in court filings that no additional money was owed to the family. The BIA argued that the family's claims for unpaid rent were exorbitant. • • The judge ruled for the family, saying the BIA owes it roughly $5 million for the unauthorized use of the land, but she also said that BP is paying too little for the land it is authorized to use. The judge is still taking briefings on the exact amount owed but it will be far below the $200 million the Oengas originally sought. BP Alaska spokesman Steve Rinehart said Tuesday the company is evaluating its best path forward on a potential appeal. He emphasized that Raven represented a fraction of Prudhoe's output. BIA's acting director in Alaska did not return a call for comment on Tuesday. In a written statement late week, Oenga family member Tony Delia said the family is willing to end the matter. "Earlier this month we made BP a fair offer -- pay what is owed and we will renegotiate the lease so they can use our land to produce from Raven and wherever else they want to drill. They haven't responded," he said. According to a written statement from the family's attorney, Ray Givens, the total amount owed the family is $15 million. That figure includes the Oenga family's calculation of how much additional money it is owed in unpaid rent for BP's authorized use of the land, which was not part of the this lawsuit. In her ruling, Firestone said evidence from the trial showed that BP withheld critical information about Heald Point's strategic value for oil development when it negotiated a contract with the family to use the land. "Clearly, (BP) did not wish to share much with the plaintiffs," she wrote. Find Elizabeth Bluemink online at adn.com /contact /ebluemink or call 257 -4317. Read more: http: / /www.adn.com/ 2011 /01 /04/1631936/bp- closes- site - over - loss -in- rent.html #ixzz1AB73YsM3 PIWFO WL� AIO 4E and AIO 14A - Question Wrding authorized fluids 0 Page 1 of 2 Maunder, Thomas E (DOA) From: Cooke, Alison D [Alison.Cooke@bp.com] Sent: Wednesday, September 22, 2010 4:17 PM To: Maunder, Thomas E (DOA) Cc: Burgh, Colleen D; Bill, Michael L (Natchiq); Brock, Mike; AK, HSSEE Env Adv Central; AK, HSSEE Env TL (North Slope) Subject: RE: AIO 4E and A1014A - Question regarding authorized fluids Tom, Thanks for the very timely response. As we discussed, we should have referenced AIO 4D in our request instead of 4C (corrected). As we also mentioned, we look forward to working with you and the Commission on reviewing some of the older Orders to make them more inclusive of fluids that have been authorized in newer Orders and making them more clear and consistent. Thanks again for you help. Alison From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Wednesday, September 22, 2010 4:01 PM To: Cooke, Alison D Cc: Burgh, Colleen D; Bill, Michael L (Natchiq); Brock, Mike; AK, HSSEE Env Adv Central; AK, HSSEE Env TL (North Slope) Subject: RE: AIO 4E and AIO 14A - Question regarding authorized fluids Alison, et al, Sorry for the delay in getting back. I've been looking over the references you included and I've been looking at AIO 4C corrected instead of 4C. I do not see an issue with the small volume of fluid being considered here. The pump seals are in contact with the approved injection fluid and the "leakage" across the seals is as designed to flush and keep the seal clean as well as reduce wear. Picking up the small amount of lube oil is part of the normal process. I do appreciate your inquiry regarding this matter. It is better ask, there is no dumb question. Call or message with any questions. Tom Maunder, PE AOGCC From: Cooke, Alison D [mailto:Alison.Cooke@bp.com] Sent: Wednesday, September 22, 2010 11:29 AM To: Maunder, Thomas E (DOA) Cc: Burgh, Colleen D; Bill, Michael L (Natchiq); Brock, Mike; AK, HSSEE Env Adv Central; AK, HSSEE Env TL (North Slope) Subject: AIO 4E and AIO 14A - Question regarding authorized fluids Tom, This email is a follow-up from our phone conversation this morning. We are seeking clarification concerning authorized injection fluids cited in Area Injection Order (AIO) 4E (Prudhoe Oil Pool in the PBU Eastern Operating Area and Pt. McIntyre Oil Pool) and AIO 14A (Niakuk Oil Pool). Background The Prudhoe Bay Seawater Injection Plant (SIP) is nearing the end of a turnaround. Normally sump fluids consisting of fluids from seawater injection pump seawater seal flush and small amounts of lube oil are routed to a dirty water tank and then to Flow Station 1. Due to inspection and potential repair of the dirty water tank, the SIP 9/23/2010 AIO 4E and A10 14A - Question V ding authorized fluids 0 Page 2 of 2 has proposed to routing these sump fluids to the SIP seawater inlet tank, mixing with the seawater injection stream. The estimated maximum volume of lube oil is one gallon per day which would be mixed with 600,000 barrels of seawater per day. AIO 4E, Rule 1 states: "Within the affected area, authorized fluids may be injected for purposes of pressure maintenance and enhanced oil recovery .... AIO 4C (corrected), Finding 11 Type of Fluid / Source: "Fluids requested for injection for the purposes of pressure maintenance and enhanced recovery are: a) produced water from Prudhoe Bay Unit production facilities; b) source water from the Seawater Treatment Plant; c) fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); d) tracer survey fluid to monitor reservoir performance, consistent with other North Slope field practices; and e) miscible injectant." AIO 14A, Rule 1 states: "Enhanced recovery operations as described in the operator's applications are approved for the NOP within the Prudhoe Bay Field subject to these rules. ... 2) Authorized Injection Fluids: Fluids authorized for injection for the NOP: a. Produced water from LPC operations; b. Beaufort seawater; c. Trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process; and d. fluids injected for the purposes of stimulation per 20 AAC 25.280(2)." Specific Question Is the injection of small amounts of SIP process related fluids (specifically in this case seawater injection pump seawater seal flush and small amounts of lube oil) with the seawater stream authorized under AIOs 4E and 14A? We would appreciate a response at your earliest convenience If you have any questions please call me at the number below or Mike Bill at 564-4692. Thanks, Alison Alison D. Cooke 907-564-4838 tel. 907-440-8167 cell 907-564-5020 fax. cookead@bp.com 9/23/2010 X15 0 • by BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 0 October 27, 2009 R ECEIVED NOV 0 3 2009 Mr. Daniel Seamount, Chairman Alaska Oil and Gas Conservation Commission 1�85�(a Di! Gas Cons. Commission 333 West 7 Avenue Anchorage Anchorage, Alaska 99501 Subject: Prudhoe Bay Unit well NK -16 (PTD #1940220) Application for Cancellation of Amended Administrative Approval 14A.002 Dear Mr. Seamount, BP Exploration (Alaska) Inc. requests cancellation of amended Administrative Approval number 14A.002 dated February 11, 2008. The administrative approval was for continued water injection into well NK -16 with slow inner annulus repressurization. This well has instantaneous breakthrough to a nearby producer. The well is shut in and there are no plans to return this well to injection. Therefore it is requested to cancel the Administrative Approval for continued operations. A plot of wellhead pressures has been included for reference. If you require any additional information, please contact me at 564 -5637 or Anna Dube / Torin Roschinger at 659 -5102. Sincerely, 7 r � R. Steven Rossberg BPXA, Wells Manager Attachments: TIO Plot Cc: Bixby /Olsen Dube /Roschinger North Area Manager Bob Gerik Harry Engel Bruce Williams NK -16 (PTD #1940220) TIO Plot + n. tM xmo a WA I I I 1OW i I I I � ! iim" worm oirmvs minim mrarm crams W26" 06mm mmM Oman mmrm X14 ...> ~., ~r.,.,....,~ x.~~ ~< emu. ~.. ~ ~~ Regg, James B (DOA) From: NSU, ADW Weii Integrity Engineer jNSUADWWeIIlntegrityEngineer@BP.com] Sent: Friday, February 08, 2008 1:34 PM To: Regg, James B (DOA) ~.~~~~ ~~ it ~ ~ ~ Cc: Maunder, Thomas E (DOA); NSU, ADW Well Integrity Engineer Subject: RE: NK-16 specified MAASP in AA Attachments: NK-16 30-day TIO.BMP 1 U`b'\. 1 Vl J Jim, The IAP on well NK-16 has stabilized at 2190 psi. I have attached a TIO plot for your reference to assist with your decision on increasing the MAASP. Please let me know ifyou need additional information or have any questions. Thank you, Andrea Hughes From: NSU, ADW Well Integrity Engineer Sent: Friday, January 25, 2008 3:54 PM To: Regg, James B (DOA) Cc: Maunder, Thomas E (DOA); NSU, ADW Well Integrity Engineer Subject: RE: NK-16 specified MAASP in AA Hi Jim. I`ve discussed this with the operator and we'li begin allowing the IA pressure to build and stabilize. I've left a note in our database and in my change out notes far Andrea to get back with you sometime late next week with pressure information. Thank you, /'A'nna ~u6e, ~'. E. Well Integrity Coordinator OPB Wells Group Phone: {907) 669-5°102 Pager: (907) 659-5°It30 x'1154 From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, January 25, 2008 1:23 PM To: NSU, ADW Well Integrity Engineer Cc: Maunder, Thomas E (DOA) Subject: RE: NK-16 specified MAASP in AA Thank you for the quick reply. Please suspend bleeds on NK-16 and allow the pressure to build so we can determine where it will stabilize. Managing pressure by frequent bleeds is probably not a good idea for several reasons. Checked design burst rating fior the pipe and that should be anon-issue. Jim Regg 2/11/2008 1V1V.-1V Jr/GG1111.U 1~lAA~Jl 111 AA ~ ~ 1 Q~'G G Vl .J AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: NSU, ADW Well Integrity Engineer [mailto:NSUADWWeIIIntegrityEngineer@BP.com] Sent: Friday, January 25, 2008 12:54 PM To: Regg, James B (DOA) Cc: NSU, ADW Well Integrity Engineer Subject: RE: NK-16 specified MAASP in AA Hi Jim. 9 suspect the lA pressure would climb and equ~a(ize with the in;ection pressure. if you would like, i can classify the well as Under Evaluation and allow the IA pressure to increase and determine if this is actually the case. Please let us know how you would like to progress this issue. Thank you, Anna 1~u6e, P Weil integrity Coordinat®r GPB 1Neiis Group Phane: (9t}7) 659-5'1(32 Palterer: t9Q7) 659-51030 x1154 - - -- From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, January 25, 2008 12:04 PM To: NSU, ADW Well Integrity Engineer Subject: RE: NK-16 specified MAASP in AA Any idea/evidence what the lA pressure will build to without bleeding down {and aN other things remaining stable so there is no thermal impact)? Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: NSU, ADW Well Integrity Engineer [mailto:NSUADWWeIIIntegrityEngineer@BP.com] Sent: Wednesday, January 09, 2008 12:13 PM To: Regg, James B (DOA) Cc: Engel, Harry R; NSU, ADW Well Integrity Engineer Subject: RE: NK-16 specified MAASP in AA Jim, I have attached a TlO plot that demonstrates Operations need to bleed NK-16 every 7-10 days to maintain the iAP below the specified 2000 psi MAASP. Please let me know if yon, need additiCJnal information to enable yo!~~r decision. Thank yogi, 2/11/2008 1V11"1 V J~JGlJ111GU 1V 1t1!'1Vl 111 C1C1 ~ t [l.b'G J V1 J i Andrea Hughes • From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Wednesday, January 09, 2008 10:40 AM To: NSU, ADW Weli Integrity Engineer Subject: RE: NK-16 specified MAASP in AA As discussed this morning, send me a current TIO plot and I will evaluate. 2000psi was set based on info I reviewed in application, specifically the TIO plot. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone:907-793-1236 fax: 907-276-7542 From: NSU, ADW Well Integrity Engineer [mailto:NSUADWWeIIIntegrityEngineer@BP.com] Sent: Tuesday, January 08, 2008 12:39 PM To: Regg, James B (DOA) Cc: NSU, ADW Well Integrity Engineer Subject: NK-16 specified MAASP in AA Jim, We were granted approval for continued water injection in well NK-16 (PTD 1940220) with TxIA communication with AIO 14.A.002 on 11/29/07. Condition number 4 states that the IA pressure limit is 2,000 psi. However, the IA pressure limit for all other wells in GPMA is 2,500 psi. Is there any reason that we should not resubmit an AA request to have the IA pressure limit increased to 2,500 psi. Thanks, Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 2/ 11 /2008 ~~ I~,~-~ v ~ ~-- a,ooa ~;ooo ~ ,ooa 0 ~~,~ # Tbg IA -~- ~a oo~ i x#13 • BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator Post Office Box 196612 Anchorage, Alaska 99519-6612 October 31, 2007 Alaska Oil ~ Gas Cans. Commission Anchorage Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Niakuk Oil Pool well NK-16 (PTD #1940220) Request for Administrative Approval: Continue Water Injection Operations Dear Mr. Norman, BP Exploration (Alaska) Inc. requests approval for continued water injection operations into Niakuk well NK-16. Well NK-16 exhibits manageable inner annulus repressurization of less than 100 psi/day. However, a pressure test of the inner annulus passed to 3000 psi, indicating the tubing and production casing are competent. Based upon sound engineering practice, two barriers have been established and the well can be safely operated. Consequently, no repairs are planned at this time. In summary, BPXA believes Niakuk well NK-16 is safe to operate as stated above and requests administrative approval for continued water injection operations. If you require any additional information, please contact me at 564-5637 or Anna Dube / Andrea Hughes at 659-5102. Sincerely, teve Rossberg Wells Program Manager • • Attachments: Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Bixby/Olsen Dube/Hughes GMPA Manager Gavin Ramsay Harry Engel John Kurz Niakuk Oil Pool well NK-16 Technical Justification for Administrative Approval Request October 31, 2007 Well History and Status Niakuk well NK-16 (PTD #1940220) exhibits manageable inner annulus repressurization indicated by wellhead pressure trends on a TIO plot. AMIT-IA to 3000 psi passed on 10/28/07 indicating competent tubing and production casing. Recent Well Events: > 10/08/07: PPPOT-T Passed to 5000 psi, PPPOT-IC Passed to 3500 psi > 10/14/07: IA re-pressurization 90 psi /day > 10/16/07: MITIA passed to 3000 psi, pre-AOGCC > 10/28/07: AOGCC MITIA Passed to 3000 psi Barrier Evaluation The primary and secondary barrier systems consist of tubing and production casing and associated hardware. A pressure test of the inner annulus passed to 3000 psi, demonstrating competent primary and secondary barrier systems. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT-IA to 1.2 times maximum anticipated injection pressure. 4. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. a,ooo i NK-16 TI4 Plot • + Tbg 3,000 IA 2,000 1,000 -r OA OOA OOOA 0 10730f2006 12I29f1006 2f28f2007 4/302D07 6130f2007 8t30f2007 10f30f2007 • M N pO (O N 8 a N O O ~ N N O m O Q N LL p !„) O '„~N O "~ v N O O V o a N C? .- c7 0 NK-16 Daily Allocated Injection Plot _~ °o fn 0 0 a 0 N 10l30f2006 - ~MiIP p O O M S~ D '.^.. ~ ~ PVN+~~ N .~ N v - h9Gl GAS p I 9f30f2007 TREE= 4-1/16"SMCM/ WELLHEAD = 13-5/8" 5M FMC UNN ERSA L ACTUATOR = T KB. ElEI/ = 59.T BF. ELEV = 24.4' KOP = 3000' Max Angle = 65 @ 6800' Datum MD = 12685' Datum TV D = 9200' SS ~ 10-314" CSG, 45.5#, NT-80, ID = 9.953" ~~ 4340' GAS LIFT MANDRELS ST MD TVD DEV 1'Y PE VLV LATCH PORT DATE 2 1 4759 12401 4464 8899 50 19 MERLA-TMPDX MERLA-TMPDX BK BK Minimum ID = 2.75" @ 12912' 3-112" HES X NIPPLE TOP OF 5-1/2" LNR ~ 12605' 4-1/2" TBG, 12.6#, L-80, 12609 0.0152 bpf, ID = 3.958" 7-5/8" CSG, 29.7#, NT-95 HS, 12781' .0459 bpf, ID = 6.875" TOP OF 3-1/2" TBG ~ 12902' 3-112" TBG, 9.3#, L-80, .0087 bpf, ID = 2.992" 12915 PERFORATION SUMMARY REF LOG: ATLAS SBL on 05/10/95 ANGLE AT TOP PERF: 23 @ 12088' Note: Refer to Production DB for historical perf data ~ SIZE SPF INTERVAL Opn/Sqz DATE ~' 3-318" 6 12800-12840 O 05!28/95 3-318" 6 12850-12893 O 08/10/95 3-3/8" 6 12912-12917 O 05112(95 3-318" 6 12806-12811 O 05/27/95 PBTD 13079' 5-112" LNR, 17#, NT-80, 0.0232 bpf, ID = 4.892" 13160' NK-16 ~AFETY NOTES: 2140' ~~ 4-1/2" HES X NIP, ID = 3.8.13" 12551' 4-1 /2" HES X NIP, ID = 3.813" 12562' 7-518" X 4-1/2" BAKER SABL PKR W/ANCHOR LATCH, ~ = 4.750" 12586' 4-1 /2" HES X NIP, ID = 3.813" 12597' 4-112" HES XN NIP, ID = 3.725" 12609' -~ 4-112" TUBING TAIL WLEG 12617' ELMD TUBING TAB 12902 -~ 5-1/2" X 3-1/2" FB-1 PKR, ID= 3.937" 12912' 3-112" HES X NIP, ID = 2.75" 12915' 5-112" MULE SHOE 12913' ELMD MULE SHOE (05126/95) DATE REV BY COMMENTS DATE REV BY COMMENTS 05/16/95 ORIGINAL COMPLETION 09108/06 CS/PJC TV D/ MD DATUM CORRECTIO NIAKUK UNIT WELL: NK-16 PERMff No: 94-022 API No: 50-029-22447-00 Sec. 36, T12N, R15E, 851.75 FEL 4293.93 FNL BP Exploration (Alaska) #12 Raven AlO - þarlier Withdrawal ofNK-65A injection order , e e Subject: Raven AIO - Earlier Withdrawal ofNK-65A injection order From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Mon, 19 Jun 2006 18:54:09 -0800 To: CC: il <jódy_co Sherri, Here's the letter from Gus withdrawing the original 2005 application for NK-65A. (You stated you have a copy of the affidavit for this application and we likely also have this affidavit in our files). Later, we decided we could handle the NK-65A request through Administrative amendment to AI014 for Niakuk (AA 14A.001). I'm attaching that amendment - it might be of some historical use to you. I've also attached the Raven application BP sent that is currently being considered for Pool Rules and AIO. As I stated, the affidavit was not included in the application that we have. I'm attaching a scan of the application we have on file. I've filled in Cammy Taylor, our attorney from the AG office. (She's at the same disadvantage that you as she wasn't here at the time of these applications). You can contact Cammy at 269-5269 for further discussion on the way to proceed if you can't find the affidavit. You can also call me at 793-1226- however, I will be out of the office from tomorrow afternoon through the remainder of the week. I think Jody Colombie could let you look at the files for AA 14A.001 and the file for the current application to help you fill in your own files. You can contact her at 793-1221. Jane -------- Original Message -------- Subject: Withdrawal ofNK-65A injection order Date:Mon, 11 Jul 2005 14:40:02 -0800 From:Gustafson, Gary G (Alaska) <GustafGG~BP.com> To: i ane williarnson~adrnin.state.ak. us CC:lnce, Don <Don.Ince~conocophillips.com>, Goltz, Jon K <Jon.Goltz~conocophillips.com>, Steve S. Luna (Exxon) (steve.s.luna~exxonrnobi1.com) <charles.s.luna~exxonrnobi1.com>, Buckendorf, Randal (Randa1.Buckendorf~BP.com) <Randa1.Buckendorf~BP.com>, Mark C Weggeland (Weggeland, Mark C) <weggelrnc~BP.com>, Strait, David R <StraitDR~BP.com>, Leslie B Senden (Senden, Leslie B) <SendenLB~BP.com>, Threadgill, Greg (ExxonMobil) <greg.b.threadgill~exxonrnobil.com>, ieff.e.farr~exxonrnobi1.com, Frazer, Lamont C <Larnont.C.Frazer~conocophillips.com> Jane, Pursuant to our conversation earlier today, BPXA, as PBU operator, gives formal notice of the withdrawal of our May 18, 2005 request to allow for the injection of water for enhanced recovery into the NK-65A well. As a result, it is our understanding that the AOGCC will now cancel the public hearing on the request scheduled for 9:00 AM on July 13, 2005. On July 14 we scheduled a meeting with DO&G Director Mark Myers to discuss several pending Niakuk issues, including the proposed NK-65A tract operations and a new Raven PA. I will keep you posted on the results of this discussion as they could have a bearing upon the 10f2 6/20/20068:50 AM Raven AlO - Earlier Withdrawal ofNK-65A injection order I e , future actions we advance to the Commission. e As you know, the Commission's April 13, 2005 waiver of the gas-oil ratio limitations for the NK-38A well expires July 31,2005 (DNR tract operations will expire on July 29). BPXA hereby provides early notice that we may request an extension of this waiver - which if a NK-38A tract operations extension is also requested and approved by DNR - will allow continued production from the well while we prepare the Raven CO & AIO applications. Thanks again for your advice and assistance. Please confirm that the Commission's July 13 public hearing on the NK-65A injection order has been cancelled. Gus Jane Williamson, PE <iane williamson~admin.state.ak.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission Content- Type: application/pdf aio14a-1.pdf Content-Encoding: base64 . ...... . ..... ... ... ....... . ......... . ·rC~~t~~t-Ty~~:- application/pdf 48 BPXA.pdf! i Content-Encoding: base64 20f2 6/20/2006 8:50 AM #11 ~ bp e e o September 8, 2005 BP Exploration (Alaska) Inc. 900 East Benson Boulevard po. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 HAND-DELIVERED Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Re: Request for Pilot Injection in NK-65A, and Extension of GOR Waiver for NK-38A Dear Chairman Norman: In support of the Governor's initiative to increase production from North Slope fields in the wake of Hurricane Katrina, BP Exploration (Alaska), Inc. (BPXA), as Operator of the Prudhoe Bay Unit, hereby requests administrative approval under AIO 14B to commence pilot injection into well NK-65A. Injection into this well will allow us to bring the nearby producer NK-38A on production, adding an incremental 3-5 MBO to our current level of production. Since this is an interim solution, we are requesting pilot injection for a period of 6 months while we prepare the Pool Rules and Area Injection Order application for the Raven Pool. In order to produce NK-38A, we also need to request an extension of the GOR waiver for an additional 6 months. As we discussed during our technical review at the AOGCC's offices on August 25, 2005, we do not expect any negative impacts on ultimate recovery in the Raven accumulation by producing this well concurrent with the commencement of injection in NK- 65A. As we discussed, we have attached the original AIO application for the Raven Pool along with the additional data requested by the Commission in support of our request for pilot injection. We appreciate the Commission staff's proactive and cooperative approach in getting this additional production online quickly. If you have any questions about the application, please contact Leslie Senden at 564-5488. Respectfull y, ~e~W~~ Greater Pt. McIntyre Area Subsurface Manager, BPXA cc: Mr. Dan Kruse, ConocoPhillips Alaska, Inc. Mr. Sonny Rix, ExxonMobil Mr. Leonard Gurule, Forest Oil Corporation Mr. Gary Forsthoff, Chevron USA Mr. Art Copoulos, Division of Oil and Gas Ms. Jane Williamson, AOGCC " .. bp . . o BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 September 8,2005 Commissioners Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 RE: Application for Injection for NK-65A Well Prudhoe Bay Unit Dear Commissioners: BP Exploration (Alaska) Inc, (BPXA), Operator of the Prudhoe Bay Unit (PBU), on behalf of itself and the other Prudhoe Bay Unit (PBU) Working Interest Owners (ConocoPhillips Alaska, Inc., ExxonMobil Alaska Production Inc., Chevron U.S.A. and the Forest Oil Corporation) hereby makes application pursuant to 20 AAC 25.402 and 25.412 for an administrative order authorizing injection for the NK-65A Well. This order is needed to inject water in the Ivishak Formation (Raven Accumulation) for the purpose of enhanced recovery operations from the NK-38A Well. BPXA hereby requests interim approval to inject water into the Ivishak Formation for enhanced recovery benefits through February 28, 2006 or until approval of an Area Injection Order for the Raven Pool. We have addressed the applicable regulatory requirements below and in the attachments. Please maintain the exhibits and other information marked "Confidential" as confidential in accord with AS 31.05.035 and 11 AAC 25.537. 1. 20 AAC 25.402 (c)(1) - a plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, and other well within one-quarter mile of each proposed injection well; Exhibit A-1 and A-2 are plats showing the location of all wells in the area, including all Kuparuk Formation wells, the Ivishak injection well NK-65A and the Ivishak production well NK-38A. 2. 20 AAC 25.402 (c)(2) - a list of all operators and surface owners within a one-quarter mile radius of each proposed injection well; " ~ e e BPXA and the State of Alaska are the only operators, and the State of Alaska and the heirs of Native allottee Andrew Oenga are the only surface owners, within a one-quarter mile radius of the proposed injection well. 3. 20 AAC 25.402 (c)(3) - an affidavit showing that the operators and surface owners within a one-quarter mile radius have been provided a copy of the application for injection; An affidavit is attached as Exhibit B. 4. 20 AAC 25.402 (c)(4) - a full description of the particular operation for which approval is requested; NK-38A is a horizontal production well that reached a total depth of 16,765' (- 9,874 TVDSS) at an approximate location of X=721700 and Y=5988600, ASP Zone 4. The well was perforated with an initial BHP pressure of 4973 psi @ - 9850' TVDss and began flowing on March 31,2005. The NK-65A injection well is required for pressure maintenance and enhanced recovery of the reservoir. NK- 65A reached total depth of 14,208' (-9,938' TVDss) at an approximate location of X = 724300 and Y = 5988000, ASP Zone 4 on May 12, 2005. NK-65A injection is expected to provide exceptional sweep and pressure support for the NK-38A producer. Estimated total oil recovery will increase from about 11 % OOIP (primary production only) to approximately 30-35% OOIP with water injection from the NK- 65A well. Recovery from the waterflood was calculated using a reservoir simulation model. The model was used to determine optimum injector placement and timing. The NK-65A water injection will be conducted from the PBU DS NK Pad, which was built for Niakuk Field development. Injection into NK-65A is intended to replace produced fluids from NK-38A. This injector/producer pair will be operated to maintain a Voidage Replacement Ratio (VRR) of 1.0 within normal operating ranges. The anticipated production profile from NK-38A is shown on Exhibit I. Production surveillance activities for the Ivishak Raven Accumulation will be the same as other GPMA fields, and include: 1) Static Bottom-hole pressure surveys 2) Production Logging (NK-38A) 3) Injection Logging 4) Production Well Testing (NK-38A) The DS NK-Pad plot plan showing the well layouts is shown as Exhibit F. Produced and/or seawater will be routed to the OS NK Pad manifold and then routed to the injection well. A flow meter on well NK-65A measures total fluid injected into the well. 2 e e 5. 20 AAC 25.402 (c)(5) - the names, descriptions, and depths of the pools to be affected; A pool has not been established for the Ivishak Formation in the proposed area of injection. Information regarding the Ivishak formation is set forth under item 6, below. An application to establish a new Raven Pool and associated Pool Rules is planned for submittal to the commission by September 30,2005. 6. 20 AAC 25.402 (c)(6) - the name, description, depth, and thickness of the formation into which fluids are to be injected, and appropriate geological data on the injection zone and confining zone, including lithologic descriptions and geologic names; The injection zone is a 71' interval in the lower Ivishak formation, below the 2A2 Shale and above the Kavik Shale. This interval includes Zone 1 (32' thick) and Zone 2A 1 (39' thick) sands of the Ivishak. Zone 1 is expected to have a permeability of - 70 md and the Zone 2A 1 Sands are expected to be -250md. Geologic structure on top Ivishak is shown in the proposed injection area on Exhibit C. Two cross sections (Exhibits D & E) are provided to show the structure, stratigraphy and fluid contacts. Exhibit D shows a cross section along the wellbore of the recently drilled NK-38A production well. NK-38A drilled horizontally in the Ivishak Formation from the "South Fault Block" of the accumulation, into the "North Fault Block" after crossing fault "B." The well was perforated between Fault B and Fault D (North Fault Block) in the lower Ivishak, below the Zone 2A2 Shale. NK-38A began flowing on March 31,2005. The well last tested (July 28,2005) with an ftp of 2,239 psig, 1,882 BOPD, 4% watercut, and a GOR of 4,182 SCF/STB on a 60 bean choke. NK-38A was shut-in on July 29,2005 and is currently shut-in awaiting injection support from NK-65A. Exhibit E shows a cross section between the NK-38A producer (going into the plane of section) and the injector, NK-65A. Fluid contacts show most of the oil resides in the lower Ivishak, between the Kavik and the 2A2 Shales. This presents an ideal situation where the injected water is contained between two shales to provide exceptional sweep and pressure support for the producer. The Kavik Shale is 188' thick in the nearby NK-04 well and forms the lower confining zone, below the lower Ivishak. The Kingak Shale overlies the Sag River formation and is 320' thick in NK-65A. The Kingak forms the upper confining zone. The Zone 2A2 Shale is 27' thick and will act as a secondary upper confining zone. This shale will mainly keep the water within the lower Ivishak and help provide excellent sweep in the oil leg. However, the relatively thin 2A2 Shale may be offset by small faults and juxtapose upper and lower Ivishak in some areas. Some water will possibly enter the Upper Ivishak (above the 2A2 Shale) in areas where the faults exceed 27'. The Kingak Shale will ultimately provide the upper confining zone for all water injected in the Ivishak. 3 ~ e e All three shales (Kavik, 2A2, and Kingak) are ubiquitous in the area and exist in all nearby wells that drill deep enough to encounter these stratigraphic intervals. The confining shales and the reservoir intervals are not truncated by unconformities in the field area and the hydrocarbon accumulation is controlled entirely by structure. 7. 20 AAC 25.402 (c)(7) - logs of the injection wells if not already on file with the commission; There are no other injection wells in the accumulation. Logs for all wells are sent to the state as they are drilled. 8. 20 AAC 25.402 (c)(B) - a description of the proposed method for demonstrating mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that no fluids will move behind casing beyond the approved injection zone, and a description of (A) the casing of the injection wells if the wells are existing; or (B) the proposed casing program, if the injection wells are new; The casing program is included with the "Application to Drill" for NK-65A and is documented with the AOGCC in the completion record. The completion employs a 6,000' long 4 %" liner from the sidetrack depth in the Ugnu through the Ivishak target depth. The production packer is positioned roughly vertical 3,000' above the reservoir top. Special considerations for the liner are employed to ensure the wellbore integrity in the absence of an annulus extending to the top of the reservoir: . A premium liner connection ensures liner mechanical integrity against leaks. . The liner annulus is fully cemented with a light-weight, high compressive strength lead cement, followed by 1,000 annular feet of 15.8 ppg class G slurry. An XN-nipple profile is positioned in the liner just above the perforations to allow for future pressure-testing plugs. 9. 20 AAC 25.402 (c)(9) - a statement of the type of fluid to be injected, the fluid's composition, the fluid's source, the estimated maximum amounts to be injected daily, and the fluid's compatibility with the injection zone; Type of Fluid/Source Fluids requested for injection are: a. Sea water from the STP; 4 e - b. Produced water from the LPC (possible in the future); and c. Fluids injected for purposes of stimulation (possible in the future) The maximum injection rate of 15,000 bwpd will also be the initial target rate. This is done in order to make up voidage from production prior to the initiation of water injection. The injection rate is expected to decline to - 6,000 bwpd. Water compatibility problems are not expected because of the successful history of sea water injection into the Prudhoe Bay reservoir. Source water will be obtained from the Beaufort Sea and is the same water that is currently being injected into the Ivishak Formation in the IPA, and into the Niakuk Participating Area. It is possible that produced water could be injected at some time in the future. Produced water is water that is produced with Lisburne, Pt. Mcintyre, West Beach, North Prudhoe Bay State and Niakuk oil, and is separated from the oil and gas at the LPC.· Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. Compatibility with Formation and Confininq Zone The produced water returning to the Ivishak formation could be a mix of Pt. Mcintyre, West Beach, North Prudhoe Bay State, Lisburne, Niakuk or IPA produced water separated through the LPC or FS-1. Minimal problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. No clay swelling problems have been seen in the Ivishak in the IPA with either source water injection or produced water injection. When present, scaling in the Ivishak in the IPA has been limited to calcium carbonate deposition, which has been eliminated with acid treatments and controlled with the use of inhibitors. 10. 20 AAC 25.402 (c)(10) - the estimated average and maximum injection pressure; During the injection period, the maximum injection pressure will be 2,500 psi. Well NK-65A wellhead injection pressure will be determined by the Niakuk Oil Pool requirements, but the average wellhead injection pressure is expected to be about 1,500 psi. Average expected surface injection pressures of 1500 psi would yield less than the average expected Ivishak parting pressure of .66 psi/ft based on a large number of IPA fraced wells. 11. 20 AAC 25.402 (c)(11) - evidence to support a commission finding that each proposed injection well will not initiate or propagate fractures through the confining zones that might enable the injection fluid or formation fluid to enter freshwater strata; 5 e e There are no freshwater strata in the area of issue. Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Injection in the Ivishak above fracture parting pressure may be necessary to allow for additional recovery of oil. In no instance would such injection pressures breach the integrity of the confining zone. The Ivishak Formation is overlain by over 200' of Kingak shale. The Kingak is a thick shale sequence which would tend to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. The Ivishak Formation at the Niakuk Oil Pool is overlain by the Kingak shale, which is over 200 feet thick. The Kingak shale sequence tends to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones of the Ivishak Formation. Data from offset fields in the Kingak shale formation demonstrated leakoff at a gradient of approximately 0.85 psi/ft, while Ivishak sandstone has been seen to fracture with an average gradient of .66 psi/ft based on a large number of IPA fraced wells. Therefore, any fracturing would be contained within confining strata. 12. 20 AAC 25.402 (c)(12) - a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which fluid injection is proposed; Seawater from the STP will be injected initially. Exhibit H shows an analysis of the Beaufort Sea source water, as well as produced water from the Lisburne, Pt. Mcintyre and Niakuk fields. 13. 20 AAC 25.402 (c)(13) - a reference to any applicable freshwater exemption issued under 20 AA,C 25.440; The lack of fresh water and underground sources of drinking water in the Niakuk Injection Area eliminates the need for an aquifer exemption. 14. 20 AAC 25.402 (c)(14) - the expected incremental increase in ultimate hydrocarbon recovery; Reservoir modeling indicates an incremental recovery from water-flooding to be approximately 10 - 20% of the original oil in place, relative to primary depletion. 15. 20 AAC 25.402 (c)(15) - a report on the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of a proposed injection well. There are no wells that penetrate the Ivishak injection zone within a one-quarter mile radius of well NK-65A. The NK-65 parent well is within one-quarter mile, but within the Kuparuk Formation. The bottom portion of the NK-65A well was 6 e e plugged according to regulations prior to the drilling the NK-65A side-track well and will not be of concern. If you have any questions or need additional information, please don't hesitate to contact Gary Gustafson at 564-5304. Thank you for your timely consideration. Sincerely Yours, ·~lù Mark Weggeland GPMA Resource Manager Attachments Exhibit A-1 -Well Locations: Niakuk Exhibit A-2 -Well Locations: NK-65A Area Exhibit B - Affidavit Exhibit C - Top Ivishak Depth Exhibit D - Cross Section along NK-38A Wellbore - Confidential Exhibit E - Cross Section between NK-38A and NK-65A - Confidential Exhibit F - DS NK-Pad plot plan Exhibit G - NK-38A Production Profile Exhibit H - Water Analysis Exhibit I - NK-65A Type Log Exhibit J - Ivishak Net Pay and Volumetric Summary Exhibit K - Ivishak Fluid Properties Cc w/attachments: Sonny Rix, EM Dan Kruse, CPAI Gary Forsthoff, Chevron Leonard Gurule, Forest Gary Gustafson, BPXA David Strait, BPXA Leslie Senden, BPXA Art Copoulos, DNR Jane Williamson, AOGCC Bob Loeffler, Director, DML&W, DNR Mark Myers, Director, DO&G, DNR Heirs of Andrew Onega, Native allottee 7 , e Exhibit B Affidavit e STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Mark Weggeland, declare and affirm as follows: 1. I am the GPMA Manager for BP Exploration (Alaska) Inc., the designated operator of the Niakuk Participating Area and NK-65 Tract Operations, and as such have responsibility for all Niakuk-related operations. 2. On S~~ßJ ~ ~ç , I caused copies of the September 8, 2005 ApplicéÍtion for Injection for NK-65A Well to be provided to the below referenced surface owners and operators of all land within a one-quart~r mile radius of the proposed injection area. Operators: Maureen Johnson Prudhoe Bay Unit Operator BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Mark Myers, Director Director, Division of Oil & Gas Department of Natural Resources 550 West ih Avenue, Suite 800 Anchorage, AK 99501 Surface Owners: State of Alaska Division of Mining, Land & Water Department of Natural Resources 550 West ih Avenue, Suite 800 Anchorage, AK 99501-3510 Heirs of Andrew Oenga c/o Inupiat Community of the Arctic Slope P.O. Box 934 Barrow, AK 99723 ~Lù X~ Mark Weggeland . ~ Declared and affirmed before me this ~ ~/~/os- Date day of ~A<-.~Q..~~¡-, 2005. ~~~~~~ Notary Public In for Alaska My commission expires: ~ \ t5\~Oß //))"1',/· . f. ,f. J~> I ..'/ I \\ t\J.J(j~' \\ .(.t, 't«:.I. '. . ï . -"":-"~'" , . \ ~:~ ..'/" 'ifllli. {,~<:~\:~. .fhrfl1!; u ~'H)~~~~'" i,,·\ > . (, ; f '».: , 6000 5000 4000 t ~ 3000 ,¡:¡¡ ,¡:¡¡ 2000 000 0 0 3000 2500 2000 500 (If 1000 500 e e Exhibit H - Water Analysis Usbume Produced Water Analysis Beaufort Sea Source Water Analysis Determination Value Urnts Determination Summer Winter Units pH 8.5 MgIl SpecifIC Gravity 1.013 1.024 MgIl Calcium 105.0 MgIl pH 7.5 7.8 MgIl Magnesium SO.O MgIl Calcium 196.0 365.0 MgIl Sodium (calc) 10555.0 MgIl Magnesium 631.0 1190.0 MgIl Sodium (M) 13875.0 MgIl Sodium & Potassium 5680.0 10400.0 MgIl Strontium 3.8 MgIl Strontium 0.0 0.0 MgIl Barium 1.1 MgIl Barium 0.0 0.0 MgIl Iron 1.1 MgIl Iron 0.0 0.0 MgIl Hydroxyl 0.0 Mg/l Bicarbonate 85.0 142.0 MgIl Carbonate 228.0 Mg/l Cart>on Dioxide Calc. 0.0 0.0 MgIl Bicartx>nate 2618.0 MgIl Total DissolVed Solid 17852.0 32787.0 MgIl Chloride 14261.0 MgIl Chloride 9880.0 18200.0 MgIl Sutfate 750.0 MgIl Sutfale 1380.0 2490.0 MgIl T olal Dissolved Sof'od 28753.0 MCIL Resistivity 0 70'F 0.422 0.255 Ohms Susoended Solids 6.0 1.0 MQi!. PI. Mcintyre Produced Water Analysis Hiakuk Produced Water Analysis Determination Value Units pH 72 MgIl Calcium 24.0 Mg/l Magnesium 9.0 MgIl $od'l\Jm 8540.0 Mg/l Potassium 179.0 MgIl Strontium 7.0 Mg/l Barium 11.0 MgIl Iron 1.4 MgIl Hydroxyl 0.0 MgIl Carbonate 0.0 MgIl Bicartx>nate 3262.0 MgIl IrSiStivity @ 68'F 0.4 Ohms Chloride 10597.0 MgIl. Silicon 24.0 MCIL Determinalion Value Units pH 6.8 MgIl Calcium 84.0 Mg/l Magnesium 25.0 MgIl Sodium 8560.0 MgIl Potassium 128.0 MgIl Strontium 3.0 Mg/l Barium 1.1 MgIl. Iron 0.6 MgIl Bicarbonate 2800.0 MgIl Chloride 15499.6 MgIl Sutfate 484.6 MgIl. Total Dissolved SorKl 27585.9 MÕil MW ExhiM J-3 ~ . , DescriPtion: e psia (air--1 ) I ~š~1 Reservoir- BPP Estimated Gas Gr-avity optiona optional OF psia SCF/STB deg API cp (alr--1) Reservoir- T emper-atur-e _.:!!!. Initial Reservoir pr-essure51001 Initial GOR 1614.0 Tank Oil Gravity . 37, Tank Oil Viscosity at 60F Separator Gas Gravity Co 1/psi 18.5E.6 Gas Viscosity cp GasZ Factor- Gas Gr-avity (alr--1) Gas FVF bbllMSCF e 0.0356 0.0342 0.0323 0.0302 0.0279 0.0258 0.0230 0.0205 0.0182 0.01.60 0.0141 0.0122 0.0081 0.0075 0.960 0.928 0.881 0,848 0.815 0.783 0.167 0.753 0.746 0.155 0.772 0.767 0.919 0.975 0.819 0.819 0.819 ö:ã1'9 õ:ii9 0.829 0.829 0.846 0.881 imõ 1Ji25 :r.m 2.469 2.677 0.62 0.64 0.68 0.72 0.78 0.85 0.97 1.14 1.40 1.81 2Ji2 5.30 59.81 215.69 Oil Viscosity CP 0.30 0.30 0.31 0.34 0.31 0.41 0.45 0.51 0.51 0.65 õ:76 õ:9õ i:õ9 1.53 1.69 Oil FVF Oil Density bbl/bbl glcc 1.957 0.576 1.960 0.575 1.882 0.581 1.183 0.604 1.681 õ:ffi 1.596 õ:i4õ 1.518 0.658 1.434 0.618 1.366 0.696 1.306 0.115 1.241 0,133 1.194 õ:7š1 1.150 0.769 1.082 0.791 1.011 0.192 Solution GOR SCF/STB 1614 1614 1491 1332 i1"76 1õ23 884 738 609 490 ill 260 159 31 o Reservoir Pressure psia 5100 5000 4619 4258 3838 3411 2996 2515 2154 1133 1313 ~ 471 50 14.1 #10 ') ) "~":::;? i~' ~-;:J .'I'-~ 't'iQJ.,· ; 1 :1.',: !/fi~\, '..: :,1 ,.,r 'iû'" ~ . JU· ~ \ ·UII ·::Jr . \.1. .1·, .. ,I f1J' l' ·1 '-"I ',\ 'i ,1 ,¡ '\,': 'I, lJw ., ,'!..c.'::;:! (~W'U'ï ./["1::::1 'j . , . , '¡r: ':\ '\~; :' U ilo~\ ~¡., ,<'11-' ?,-'\ ¡ ·~'I Ii I l' I ·"'LJ i r \¡i II \ \ ""', I, \ ,I .1 :, 1" \ ". ) .-;;::, \1:1 :::; \ ,1'"'1 \ 'ì :Ll ti i~ U '\J (\,!.;:!) tj;\ ! J ':\ .\ lU \ ,LG,j FRANK H. MURKOWSKI, GOVERNOR A".6A~1iA OIL AlQ) GAS CONSERVATION COltDlISSION 333 W. pH AVENUE. SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)27&7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly iDcons istent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity . The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" Area Injection Orders AIO 1 - Duck Island Unit 6 7 9 AIO 2B - Kuparuk River Unit; Kuparuk River, 6 7 9 Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; 6 7 9 Western Operating Area -- AID 4C - Prudhoe Bay Unit; 6 7 9 Eastern Operating Area AID 5 - Trading Bay Unit; 6 6 9 McArthur River Field AIO 6 - Granite Point Field; 6 7 9 Northern Portion AIO 7 - Middle Ground 6 7 9 Shoal; Northern Portion AIO 8 - Middle Ground 6 7 9 Shoal; Southern Portion AIO 9 - Middle Ground 6 7 9 Shoal; Central Portion AIO lOB - Milne Point Unit; Schrader Bluff, Sag River, . 4 5 8 Kuparuk River Pools AIO 11 - Granite Point 5 6 8 Field; Southern Portion AIO 12 - Trading Bay Field; 5 6 8 Southern Portion AIO 13A - Swanson River 6 7 9 Unit AIO 14A - Prudhoe Bay 4 5 8 Unit; Niakuk Oil Pool AIO 15 - West McArthur 5 6 9 ) Affected Rules "Demonstration of "Well Integrity "Administrative Injection Order Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River 6 7 10 Unit; Tam Oil Pool 6 8 Ala I 7 Badami Unit 5 AID 18A - Colville River 6 7 11 Unit; Alpine Oil Pool AID 19 - Duck Island Unit; 5 6 9 Eider Oil Pool AIO 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AID 21 - Kuparuk River 4 No rule 6 Unit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 U nit; Aurora Oil Pool 6 9 AIO 23 Northstar Unit 5 AIO 24 - Prudhoe Bay Unit; 5 No rule 9 Borealis Oil Pool AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Disposal In.iection Orders 010 1 - Kenai Unit; KU No rule No rule No rule WD-l 0102 - Kenai Unit; KU 14- No rule No rule No rule 4 010 3 - Beluga River Gas No rule No rule No rule Field; BR WD-l DID 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DID 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DID 6 - Lewis River Gas No rule No rule 3 Field; WD-l DID 7 - West McArthur 2 3 5 River Unit; WMRU D-l DID 8 - Beaver Creek Unit; 2 3 5 BC-3 DID 9 - Kenai Unit; KU 11- 2 3 4 17 DID 10- Granite Point 2 3 5 Field; GP 44-11 Affected Rules "Demonstration of "Well Integrity " Administrative Injection Order Mechanical Failure and Action" Integrity" Confinement" DIO 11 -Kenai Unit; KU 2 3 4 24-7 DIO 12 - Badami Unit; WD- 2 3 5 1, WD-2 DIO 13 - North Trading Bay 2 3 6 Unit; S-4 -- DIO 14 - Houston Gas 2 3 5 Field; Well #3 DIO 15 - North Trading Bay 2 3 Rule not numbered Unit; S 5 DIO 16 - West McArthur 2 3 5 River Unit; WMRU 4D DIO 1 7 - North Cook Inlet 2 3 6 Unit; NCIU A 12 010 19 - Granite Point 4 6 Field; W. Granite Point State 3 17587 #3 01020 - Pioneer Unit; Well 3 4 6 1702-15DA WDW DIO 21 - Flaxman Island; 3 4 7 Alaska State A - 2 010 22 - Redoubt Unit; RU 3 No rule 6 Dl DIO 23 - Ivan River Unit; No rule No rule 6 IRU 14-31 DIO 24 - Nicolai Creek Order expired D nit; NCD #5 DIO 25 - Sterling Unit; StJ 3 4 7 43-9 010 26 - Kustatan Field; 3 4 7 KFl Storage Injection Orders SIO 1 - Prudhoe Bay Unit, No rule No rule No rule Point McIntyre Field #6 SIO 2A- Swanson River 2 No rule 6 Unit; KGSF #1 SIO 3 - Swanson River Unit; 2 No rule 7 KGSF #2 Enhanced Recovery In.iection Orders EIO 1 - Prudhoe Bay Unit; No rule 8 Prudhoe Bay Field, Schrader No rule Bluff Fonnation Well V-I 05 ') ) Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" EIO 2 - Redoubt Unit; RU-6 5 8 9 I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA ADVERTISING ORDER ~f;.f;gq1''TOMif"O~'INY9Ic.E~jQ~îE~ NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC 333 West ih Avenue, Suite 100 Aù1chorage,AJe 99501 907-793-1221 AGENCY CONTACT Joòv r()~, 11 IIh;t PHOÑE (907) 7Q1 - 1 ')') 1 ÒA TES ADVERTISEMENT REQUIRED: DATE OF A.O. R o M C1 1 :"'\f"n I ~I II It PC'" )7 2004 T o Journal of Commerce 301 Arctic Slope Ave #350 Anchorage,AK 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE UNES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of S5 INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of . 2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, Notary public for state of My commission expires 9/29/2004 1: 10 PM 10f2 Subject: Public Notices From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Wed, 29 Sep2004 13:01 :04 -0800 To: undisclosed-recipients:; Bec: Cynthia B Mciver.<bren_mciver@adrttin.state.ak.us>, AngelilWebb. <aJlgie _webb@admin.state,.ak.us>,.RobeìtE Mintz. <robert ~ min~@la", .:state~ak.us> ~ Christine" Hansen <c.han.sen@iogcc.stat~.ok.~s>, Terrie Hubl?l~ <~ubbl-etl@bp.com>,Sohdi'a Stewman <SíewmaSD@BP .com>, Scott & can1my TaylQr <staylor@alaSka~net:>',· stanekj <stanckj@tmocal.com> ,ecolaw <ecolaw@ti:ustees.org>, rôseragsdále <rosera.gsdale@gcLnet>, trmjr 1 <tI1Iljrl@aoLcom>, j.briddle<jbriddle@maratho~o~l.com>, rockhill ,<róckhiH@aoga.org>, sharieg <sh.ai1eg@ev¢rgre~ngas~com>, jçlarlington ·<jdadington@f(lt~e~t()~,.com> ,nelson <knelson@petroleurrinews.com):-, cbodqy <cboddy@usîbèIH.co$>,~ark ÓaltQn. <mark.dalton@hdtinc.com>,Sh. 'annonDonnelly :<shannon.do~e.· liy@.cþnocophillip, s.~orn>~- ",.Mark·P. . ' .. ~ WOrcester" <mark.p..worcester@conocophillips.com>, "JerryC.DethJefs·" . . . . ~ .' <jerry.c.dethlefs@conocophillips~com.>,. . Bob <bob@inletkeeper.org> ~ wdv <wdv@~~state.àk. us>, tjr :<tjr@dnr.state.ak.us>, bbritch <þbritch@alaska.net>,Ii1jnelson <ni.jnelson@pu:rvingeriz.com>, CharlesO'DonneU <charles~o'dönnell@veco.com>, "Randy L. Skiilern", <SkilleRL@BP .co~>, "Deborah J. Jones" <JonesD6@BP.com>, "Paul G. .Hyatt" <hyattpg@BP.com>,. nStevenR. Rossberg" <R;ossbeRS@BP.com.>, Lois <lois@inle~eeper~org>, D~ Brpss<kitacrtews@kuac~org> ,Gordon Pospisil <PospisG@BP.c.om<, "Francis 8. Sonirl1er" <SommerF$@BP~com,>, Mik~l S9hultz <Mike1.Schultz@BP·.cortl>, "NickW.· Glover" <GloverNW@BP.com>,. "Dát'yl J. Kleppin" <K1eppiDE@BP.com>, It.Janet D. Platt~' <PlattJD@BP.com>, "Rþsåime M. Jåcobsen" <JàcobsRM@BP . com> , ddonkel <ddonk~l@cfl.rr.com>,CollinsMòunt <collins ~ mount@revenue.state.ak.'us>, mckay <m.ckay@gci.net> ,'BarbaraF Funrru~r <barbara.ffulbner@conocophillips.com>, bocastwf <bocastwf@bp.conï>, 'C}):atles Bark~r : <barker@usgs.gov>, doug_schultze <doug_schultle@Xtoenergy.com>,Hank Aiford .. <hank.a1fotd@exxonmobil.com>, Mark Kovac <yesnol@gci.l:u~t>,gspÎoff .' . <gspfoff@au.rorapower.com>, Gregg N ady <gregg.nady@shell.com>, .Fred Steece <fted.steec·e@state.sd.us>, rcrotty <rcrotty@ch2m.coni>, jéjones <jèjones·@aurorapower.com>, dapa <dapa@alask~.net>,jr~derick <jr<?derick@)gci.ne~>, ey~cy <eYat:l~y@~eal~títe~net>, ~'James M. Ruud" <james~m.ruud@~onócophillips.com>, Brit Lively <mapalask~@ák~n..e~,ja)1 <jah@dnr.state~ak.us>,·Kurt E Olson <kurt_oIson@legis.state.ak..us>, buonoje <buonoje@bp.com>, Mark Hanley <mark _ hanley@anadarko.com>, loren _lernan <loren_leinap.@gov.stcite.ak.us>, Julie Houle <julie_houle@dnr.statè.ak~us>, John W Katz<jwka~@sso.org>, SuzånJ Hilt· <suzan~hiIl@dec.state.ak.us>, tablerk <tablerk@unocaLcom>, Brady·<brady@~oga..org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borQugh.keD;~Lak.lis:>, Jìni\V:hitè <jimwhite@satx.rr.com>, "John S.Haworth" <jòhn.s~¥wprth@cxxonm~bil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.c~m>,. nnclean <nÌ1clean@pobox.alaska.net>, mkm720q: <mkm7200@aotcö~>,. B9aJ:i. GilleSpie <itbmg@uaa.alaska.èdu>, David L ~oe.lens <dboele~@à1:lrÓrapower.co1i1>, TOdd put-kee <TDURKEE@KMG.,com>~ Gary Schultz <gary _schultz@dnr.state.aJ.c:.us>,: Wày.ne:~~cier <RA.~f~~~~~~~~~~a~cél~,.Bill, ~ill~r)~iIl~ ~il.ler@~t~aSk:a.çot? ~ ·~~don·.Gagnon <b~~g~@þr~~~aw.q9iH?,p(ttt,r-W-j~~løw..:~P~~~ºw@t~(~stpil·~cOm>, darry·Cmon <CâtrOtfg¡-@Þp~C9m~;:'$À~åiÌl,¢~,~ºp~l~(.t<cqpelasv@bp~.cOni~, S'uz~e'AHèxan ') ) Pùblic Notices Public Notices <scott.cranswick@mms.gpv>,Brad McKim <mckimbs@BP.com> ~~ê~S~f&I1d th~a.ttélchTª Noti cean.q ....l\tta.cl1.ment for~ltj J?r.9J?o~~d a.mendment Òf 'Q.Ildet'grou.nd injection orders and the.Pub:l:i;.cNotic~Happy V'é).I.I£;:)f #10. JdCiy Cölotnbie ". . ... , ........ "-"..' "',.-".... ",. . .",.,._-;.~...:, ....>~,;~:',....., ,...;.:~- ,;,.;._,.., .....-, " . u. ..."....~" _......... . ,,' .._~, '"'' '.._. ._A_ .~_"..~".._,...__.___""".;.__.~"...~..,_. . -,,,.." -~_._,-- ,,-'''''''''''''''''''''':'''' ",.."..::"...".:""..""".."......,,,.. , .. . .... .. .. .. ....... ...... .¡Contel1t-iyp~; applicatio11/msword iMechallIcallntegrIty proposal.d()c !.'. . ..' ... ·..:t.·...:..........:.. ..... .:. ..... ..... ..................:..... ........ '.. . b·· ....... ... ··6.·. It.·.. ...... i . . .... . . . . . ... :Coutent-Encodmg:. ·ase '-t ,,-_·"··'·r-·...'-·,',_..··~ ... .."("" ...... . .ri.. ... . ... ....... ................ . ........... ..:Contént"J':Yp~: åpPlicatioW;mswÓrd MeckanicallntegrityofWells Notice.doc: ..... ..... ... ·······.············.···<a·:····· ·k.···...·····6·4··. ! Content..;Enc() lUg: uase I Content-Type: applicationlmsword HappyVaßeyl0 _ HearingNotice.doc ' Content-Enc()dit1g:øase64 . . _,""'" ,., "^~~.~.. . ,ow ...._~" ..,..,..~,..._....v,~,~..~..~~-:.......:~_'. ~.._, "'''.''._.._ '."_~"".._," ~"~...,,,,...._~,...,. . " . ~._. _...,~. .,,;;.." ." ._,~... ...._ .,..,........, _,'..~_,' _..u:. ',w , ..~ '" ~~""'_-:-_....,~...:-,..,~._.~~...____...~w.~,_"..._....;;..~..__..~,__ "_._,"'" ..,. .".~.._~",._......,.'.~_ . ...:..~, _*,¥ 20f2 9/29/2004 1: 10 PM Pwblic No~ice ) \ J Subject: Public Notice From: Jody Colombie <jody _ colombie@admin.state;ak.us> Date: Wed, 29 Sep 2004 12:55:26 -0800 To: legal@alaskajournal.com Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie ...........,,, . ,.".".........."...,..."......,...." ............ 'h''''" ",,,...,,,, """" : ¡ Content-Type: application/msword : Mechanical Integrity of Wells Notice.doc : b 64 ¡Content-Encoding: ase . "...."",..." , ,........,.........,.....,............... Content-Type: application/msword :Ad Order form.doc Content-Encoding: base64 1 of 1 9/29/2004 1: 10 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 /1 a I!¿;d /(J 11(,: David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Com pany 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland. OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 1 90083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks. AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 . [Fwd: Re: ·Consistent Wording for Injection Jers - Well Integrity... ) SUbject:.·[Fwd: Re: ·G()~sistentWorqi~~.··.~()t Ir1j~eti()~...Ord~.rs-W~ll~t¢grit~.<R~vis~Q)l F.'.......r..........o.... m.'. :. ..J.....o. hn N.o.rID. ..' :....an...........<.J.·.....O........00............. ~.·.......11.....0.......rm......... an." .@.......... .·.a...4min~state~ak. ~US. >- p~te: ,Fr,i"01 pçt ~~q~11:g9:~6~q800 .......... .... ..... .... 1'9,#:~q~~,~ß~J()~~mQi:~~g4yf9þ~~~bl~@~~~~.~~~¢~~~ys~· more -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert mintz~law.state.ak.us> To:jim regg(â¿admin.state.ak.us CC:dan seamount(â¿admin.state.ak.us, john norman(â¿admin.state.ak.us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commission." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <¡im regg@admin.state.ak.us> 8/25/2004 3:15:06 PM »> Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...] to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions abQut the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <¡im regg(â?admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection ~ ~rs - Well Integrity ... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EaR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions - adopts "Administrative Actions" title (earlier rules used "Administrative Relief"); - consistent language regardless of type of injection (disposal, EaR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg Norman(Q?admin.state. us> 20f2 10/2/20044:07 PM .[Fwd: Rê: èonsistent Wording for Injection ,)rs - Well Integrity... ,) .~~bject: [Fwd: Re:ConsistentW ordingfor Irijèctip110rders· - .Wêl11ptègrìty{~evised)] ~~~ln:" John Nonnan <johrï_n()rman~admiI1.state.ak.µs> Date: Fri, 01 Oct 2004 11:08:55 -0800 ~9,;·lèªýj:Qg·~~mÞ~~~;~~~iš~j;p~Þ~~@·ª~~~~s#~t~):~.µ~~. please print all and put in file for me to review just prior to hearing on these amendments. thanx -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz(ã}law.state.ak.us> To:dan seamount(ã}admin.state.ak.us, Jim regg(ã}admin.state.ak.us, ~hn nonnan(ã}admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as red lines on the second document attached. »> James Regg <¡¡m regg(á)admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for sluny injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIG 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several Dros Administrative Actions lof2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection ( [s - Well Integrity... - adopts" Administrative Actions" title (earlier rules used" Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu ofteITIls like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg : John K.Nonnan <John Norman@admin.state.us> · Commissioner Alaska Oil & Gas Conservation Commission . Content-Type: application/msword Injection Order language - questions.doc Content-Encoding: base64 Content-Type: applicationlmsword Injection Orders language edits.doc Content-Encoding: base64 20f2 10/2/2004 4:07 PM ), ) Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integritv Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Form 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once everv two years in the case of a slurry iniection \vcll), and before returning a vi/cll to service foLh.1\ving a.fte.F a workover affecting mechanical integrity, and at lðíl~;t on~e e\'ery '1 year~; white actively injecting. For slurry ~lls, the tubing/casing annulus tnust be t~stûd for mechanical integrity every 2 years. Unless an alternate tneans is approved bv the COlTI.nlission. Inechanical integritY" ITIUst be demonstrated bv a tubing pressure test using a +fie MI+-surface pressure of must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that ffH±St-show?i stabilizing pressure that doesand Inay not change more than 10%- percent during a 30 minute period. -Afl.y altenla.te illeans of delnon~trating l11cchanical integrity rnu~t be a.pproved by the COlnn1is::;ion. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as otherwise provided in this rule, +lhe tubing, casing and packer of an injection well must Ek~~lnaintain integrity during operation.\Vhenever any pressure conlffiunication, leakage or lack of inÌection zone isolation is indicated bv iniection rate. operating pressure observation, test, survey, log, or other evidence, t+he operator :lt1:H:&f-shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approvat 'shene'i-er any pres~ure C01TIl11Unication, leakage or lack (7f...ffij-ection zons-tsübtion is indi~ated by injection fatc, oper:J.tÍng pressure obserT;ation, te~~t, survey, or log. The operator shall shut in the well if so directed bv the COl1unission. The operator shall shut in the well \vithout a\vaiting a response tì-om the Comlnission if continued operation v\I'ould be unsafe or would threaten contamination of fresh water-If there is no threat to freslnvJ.ter, injection 111:1)' contir:.ue until the Conll11i,~sion require~ the '.\'811 to be shut in or secured. Until corrective action is successfully conlp1ctcd. Aª monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. .[F.~d: R~:-[Fwd; AOGCC Proposed WI Lant. }e for Injectors]] ) ~~bJect: [Fwd: Re:, [Fwd: AOGCCProposed WI Language for Irijectors]] ~r~m: ,.Winton',Aubert<winto~aubert@admin.state.alcus> D, .>~t~: Tþ:µ,28Qct 200409:4~:5, 3 -Q8.o0, ' 1~;~·:~Þ·~Y:~·§9~J9¡ìrþi:~$j,9~y~~qt~:n&ij~~@~~~~;$t~t~..:~:ttŠ~"',·.::,'·"'·'·"" , This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngeIHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven¡ Engel, Harry R¡ Cismoski, Doug A¡ NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.¡ Reeves, Donald F¡ Dube, Anna T¡ NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few , comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** 1 of 3 10/28/2004 11 :09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI Lan§, : for Injectors]] returning a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately"! due to weekends! holidays! etc. We like to confer with the APE and get a plan finalized! this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate! operating pressure observation! test! survey! log! or other evidence, the operator shall * immediately*_** notify the Commission" This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation." Report content requirements are clear! but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC! are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures! daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action! but to pursue an AA! does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin! Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend! Monte Ai Digert, Scott A¡ Denis, John R (ANC) ¡ Millerr Mike E¡ McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of Wells Notice.doc» 2 of3 10/28/2004 11 :09 AM #9 [Fwd: Ni~:uk AIO] ) ) A J:'C) /<{ Subject: [Fwd: Niakuk AIO] Date: Thu, 02 Aug 2001 17:10:17 -0800 From: Julie Heusser <julie _ heusser@admin.state.ak.us> To: Jody J Colombie <jody _ colombie@admin.state.ak.us> Hi Jody, Would you please include a copy of this e-mail in the record for Niakuk AIO expansion. Thanks Julie 1....,."................................ .. .... ····,···w·w·,·w.w_,·,','.·,·,'.·,',','.,,'······ ..,,,,.... .. , ..... ""... ....".,..".... ,..""...... ....-..........--..---------"""""""'... ·w,',',','."" .". ,.... .... .." . ." "" "~",',', .. w..,·..."'··", "W ·...'.·,·,""',.,....·",..'.',·,·,·.','.·,w..,..w,·..',.,. ,.. '·,',',',',',w,'"",,,,w,,,",',w.',w.',",',,,,",'.'.'''''''',',',',,."",. Subject: RE: Niakuk AIO Date: Thu, 2 Aug 2001 20:39:37 -0500 From: "Shaw, Anne L (BP Alaska)" <ShawAL@BP.com> To: "'Jane Williamson'" <Jane_ Williamson@admin.state.ak.us>, Jack Hartz <jack_hartz@admin.state.ak.us>, "Camille O. Taylor" <Cammy_Taylor@admin.state.ak.us>, Dan Seamount <dan _seamount@admin.state.ak.us>, Julie Heusser <julie _ heusser@admin.state.ak.us>, Bob Crandall <bob_crandall@admin.state.ak.us>, Steve Davies <steve _ davies@admin.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Wendy D Mahan <wendy_mahan@admin.state.ak.us> CC: "Warner, Dwight" <WarnerDW@BP.com>, "Mark Evans (E-mail)..<mpevans@upstream.xomcorp.com>. "Jim Johnson (E-mail)..<jpjohns@ppco.com>. "Limb, H Gary (Phillips)" <HLIMB@ppco.com>, "Johnson, Michael R (Exxon-Mobil)" <Johnson6@BP.com>, "Cole, Mike D" <colemd@BP.com>, "Schafer, Daniel B" <SchafeDB@BP.com>, "Taylor, Paul J" <TaylorP J@BP .com> Jane and Jack, We have received your message of August 1, 2001, and the list of additional information you have requested regarding our application for a revision to Area Injection Order 14. The data you have requested is significantly more than the information necessary for expansion of the Niakuk injection area as discussed at our meeting on June 11th, and also is substantially more information than was provided at the time of the original Niakuk Area Injection Order. While we will try to provide the additional information as soon as practical, responding will require quite a bit of staff time and will impact other ongoing activities, including plans to commence injection in NK-28. Given the additional work that will be necessary to review and respond to your letter, we request that the record be kept open for an additional (30) days. We will be able to provide the additional discussion items you have requested and certain of the data and maps. A session in the HIVE at the BP office to review the model and history match may be possible as well. However, our preliminary review indicates there likely will be some information that we will not be able to provide. Based on our conversation with you this afternoon we will follow your lof2 8/3/01 6:49 AM [F.:wd: N."iak,)Jk AIO] J ) suggestions to use your requested list as a guideline for providing additional information. Additionally, as we mentioned, if there is any way we can begin injection at NK-28 prior to the finalization of this document it would be certainly appreciated. Anne L. Shaw GPMA Team Leader BP Exploration (907)564-5844 -----Original Message----- From: Jane Williamson [mailto:Jane Willi~mson@admin.state.ak.us] Sent: Wednesday, August 01, 2001 12:20 PM To: Anne Shaw; Camille O. Taylor; Dan Seamount; Julie Heusser; Jack Hartz; Bob Crandall; Steve Davies; Thomas E Maunder; Wendy D Mahan; WarnerDW@BP.com Subject: Re: Niakuk AIO I had a slight typo in the original attachment to this letter. Please discard and use this attachment Jane Williamson Jane Williamson wrote: > Dear Anne, > > > > > > > > > > > > > > > > > > > > > > > > Please call me (793-1226) or Jack Hartz (793-1232) if you wish to > discuss further. > > Sincerely, > > Jane Willamson > AOGCC Petroleum Engineer > > > requirments BP Niakuk AI014.doc > AOGCC list of requirments BP Niakuk AI014.doc (application/msword) > Attached is a review by the AOGCC technical Staff of the Application for Revision of Niakuk Area Injection Order #14 which you submitted to us on July 24, 2001. (2 initial copies were provided received on July 23, 2001. We are using the July 24, 2001 for the copy of record.) The revision is requested for the purposes of beginning waterflood in the Western Niakuk region, not currently covered by AIO 14. The application is not complete. The Commission needs an updated record of the project plans, current and future, and must provide sufficient reservoir, completion and geologic information for evaluation of the proposed expansion. The quantity of oil in place 310 MMBO, with the expantion area containing 190 MMBO, emphasizes the need for the Commission to fully evaluate the project. Our current records are vastly out of date as to reservoir/geologic description and are insufficient for the task at hand. Please review this list and let us know how long you will need to keep the record open on this matter, in order to gather, document, and review the submittal. At your request we will keep the record open longer in order for you to gather the information. Please advise us as to the date you wish for extension of the record on this matter. ------------------------------------------------------------------------ Name: AOGCC list of Type: WINWORD File Encoding: base64 2of2 8/3/01 6:49 AM Niakuk Field Maps, ie, Niakuk Area Injection Order 20 AAC 25.460 20 AAC 25.402 Full size copies of : Exhibit 0-7: Exhibit 0-8: Exhibit 0-9: Exhibit 0-10: Exhibit 0-11: Exhibit 0-12: Exhibit 0-13: Exhibit 0-14: West Niakuk Net Sand Map East Niakuk Net Sand Map West Niakuk Net Porosity Map East Niakuk Net Porosity Map West Niakuk Net Water Saturation Map East Niakuk Net Water Saturation Map West Niakuk Net Hydrocarbon Pore Foot Map East Niakuk Net Hydrocarbon Pore Foot Map Montage of 8 maps of: West Niakuk Net Sand Map East Niakuk Net Sand Map West Niakuk Net Porosity Map East Niakuk Net Porosity Map West Niakuk Net Water Saturation Map East Niakuk Net Water Saturation Map West Niakuk Net Hydrocarbon Pore Foot Map East Niakuk Net Hydrocarbon Pore Foot Map Delivered to Mr. Bob Crandall, by: i) J~L Received By: r - ~~ Exhibit 0-7: Exhibit 0-8: Exhibit 0-9: Exhibit 0-10: Exhibit 0-11: Exhibit 0-12: Exhibit 0-13: Exhibit 0-14: Date ') l I Date I ò ,- 3" '-ell RECEIVED OCT J U / Alaska Oil & Gas Cons. Commission Anchorage #8 . . . bp BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 October 19,2001 REC ~\.'ED Alaska Oil & Gas Conservation Commission 333 W. th Avenue, Suite 100 Anchorage, Alaska 99501 (¡ AlaSka Oil & Gas Gons. CommlSSÍOn Anchorage Attn: Cammy Taylor, Commissioner Jane Williamson, Engineer Jack Hartz, Engineer Bob Crandall, Geologist Re: Application for Revised Niakuk Area Injection Order Enclosed is the revised application by BP Exploration (Alaska), Inc. (BP) for the expanded Niakuk Area Injection Order. This application requests that an injection order be granted to cover injection operations in which BP will act as the Operator, over both the Niakuk Participating Area and the Western Niakuk Participating Area. All information required is included in the application as discussed with staff members at the AOGCC. Please contact Anne Shaw, GPMA Resource Manager, at (907) 564-5844 if you need any additional information or if you have any questions. Sincerely, Russell Smith. GPB Satellites Asset Manager GPMA WIO Alternate Representative . . cc: M. Evans (w/o attachments) - Exxon Mobil J. Johnson (w/o attachments) - Phillips Alaska, Inc. M. Johnson (with attachments) - Exxon Mobil G. Limb (with attachments) - Phillips Alaska, Inc. GPMA File (with attachments) . . Application for Revision of Niakuk Area Injection Order 20 AAC 25.460 20 AAC 25.402 . . SECTION A: APPLICATION FOR REVISED AREA INJECTION ORDER ................... 3 SECTION B: PLA T .................................................................................................................... 4 SECTION c: OPERATORS/SURFACE OWNERS ...............................................................5 SECTION D: AFFIDAVIT ........................................................................................................ 6 SECTION E: DESCRIPTION OF OPERATION ................................................................... 7 SECTION F: POQ L INFO RMA TI ON ..................................................................................... 9 SECTION G: GEOLOGIC INFO RMA TI ON ....................................................................... 10 SECTION H: WELL LOGS .................................................................................................... 12 SECTION I: CASING INFORMA TION ................................................................................ 13 SECTI ON J: INJECTION FLUID .......................................................................................... 14 SECTION K: INJECTION PRESSURE ................................................................................ 16 SECTION L: FRACTURE INFORMA TION ........................................................................ 17 SECTION M: FORMA TI 0 N FL UID ..................................................................................... 18 SECTION N: AQUIFER EXEMPTION ................................................................................. 19 SECTION 0: HYDROCARBON RECOVERY ....................................................................20 SECTION P: MECHANICAL INTEG RITY ......................................................................... 22 SECTION Q: MECHANICAL CONDITION OF WELLS.................................................. 23 LIS T OF EXHIB ITS. ..... ..... ... ..... ....... ....................... ................... ........ ....................... ...... ... ..... 24 2 . . SECTION A: Application for Revised Area Injection Order 20 AAC 25.460 20 AAC 25.402 BP Exploration (Alaska) Inc. (BP), in its capacity as a Working Interest Owner (WIO) and the Operator of the Niakuk Participating Area and Western Niakuk Participating Area within the Prudhoe Bay Unit, hereby applies for revisions to Area Injection Order No.14 to cover operations in the Niakuk and Western Niakuk Participating Areas (Exhibit A-la). Water injection for waterflood purposes in the interval defined as the Kuparuk interval in the Pool Rules for the Niakuk Oil Pool, (Conservation Order 329) is the subsurface injection operation planned within the Niakuk Injection Area. Initially, water injected into the Niakuk Oil Pool was source water from the Prudhoe Bay Seawater Treatment Plant. Currently, produced water processed at the LPC is used for injection. Future needs may require water from either source. This application follows the same general format and exhibit numbering as in the original application for proposed injection operations in the Niakuk Injection Area. This submittal includes information contained in the original application, supplemented and updated as appropriate. Exhibit A-la details the area included in the updated Niakuk Injection Area. The legal description of the area included in the Niakuk Area Injection Order is listed in Exhibit A-2. 3 . . SECTION B: Plat 20 AAC 25.402(c)(1) Exhibit A-I b is a plat showing the location of all wells that penetrate the injection zone within the Niakuk Injection Area as of July 1,2001. Within this area, all the specific wells that will become injectors have not been selected. Current Injectors: NK-lO, NK-15, NK-16, NK-18, NK-23, NK-38, NK-65 [Note: NK-17 and NK-ll are shown as shut-in on Exhibit A-lb and Sections E and 0 state there are 7 current injectors.] Proposed Injectors: NK-28 4 · e SECTION C: Operators/Surface Owners 20 AAC 25.402(c)(2) Working interest ownership for both PAs is as follows: ExxonMobil Alaska Production Inc. (36.82263%) Phillips Alaska, Inc. (36.49270%) BP Exploration (26.66467%) Forest Oil (0.02000%) The surface owners and operators within a one-quarter mile radius of the Niakuk Injection Area areas shown on Exhibit C-l : Surface Owners/Operators State of Alaska Department of Natural Resources Attn: M. D. Kotowski P.O. Box 107034 Anchorage, AK 99510 BP Attn: Anne L. Shaw P.O. Box 196612 Anchorage, AK 99519-6612 Native Allotment Parcel B Owners Mr. Leroy Oenga P.O. box 201 Barrow, AK 99723 Mr. Michael M Delia 1228 28th Avenue Fairbanks AK 99701 Ms. Georgene Shugluk P.O. Box 1621 Atqasuk, AK 99791 Mr. Wallace Oenga P.O. Box 1128 Barrow, AK 99723 BIA / Heirs of Jenny Oenga c/o Inupiat Community of the Arctic Slope 4495 Northstar Street Barrow, AK 99723 5 · e SECTION D: Affidavit 20 AAC 25.402(c)(3) Exhibit D-I is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of any proposed injection well in the Niakuk Injection Area have been notified and provided a copy of the application. 6 - e SECTION E: Description of Operation 20 AAC 25.402(c)(4) Well Spacing Well spacing is nominally 80-120 acres with tighter locations that target localized accumulations separated by faults. Future development is expected to be consistent with this spacing although 40 acre spacing may be required in some areas of the field (see Exhibit A-la and A-lb). Well Counts As of May 2001, 31 wells have been drilled from two drillsites in East and Western Niakuk. 14 producers and 7 water injectors are currently active. Final count will be dependent upon production and reservoir performance data. Impacted Wells Wells currently used as water injectors include NK-lO, NK-15, NK-16, NK-18, NK-23, NK-38, NK-65. Expanding the area of injection to include Sections 15,22, and 27 allows NK-28 to be converted to injection. This well is located on the western edge of Segment 3/5 (see Exhibit A- Ib). Other candidates for conversion will be evaluated as field needs dictate. Facilities Water injection rates will be determined by reservoir management needs. This entails monitoring reservoir pressures and recovery performance and adjusting injection rates and locations accordingly. The goal is to maximize sweep and maintain reservoir pressures while working within economic constraints. Niakuk water injection currently comes from the LPC produced water system through an 8" pipeline. Niakuk injection water was switched to produced water from seawater during 2000. Future injection requirements may require the use of one or more booster pumps at the drillsite. Water usage at Prudhoe Bay may lead to Niakuk returning to seawater injection at a future date. Surveillance The Niakuk accumulation is separated into Eastern and Western areas due to a complete loss of Kuparuk sand across the mid-field high (see Exhibit G-3). In the Western accumulation, separate OWCs and production history indicate that Segment 1 is separated from Segment 3/5 (see Exhibit G-4). Niakuk is managed as three main pools - Segment 1, Segment 3/5, and Segment 2. Segment 1: Production in Segment 1 began in April 1994. Injection began approximately one year later with the conversion of NK -10. Production has been sustained via pressure maintenance from this single injector. Aquifer support to the west may also be present, but has not been verified. Segment 1 performance, in terms of reservoir injection, voidage, pressures, and GaRs, is provided in Exhibit E-l. Oil, gas, and water production for Segment 1 is provided in Exhibit E-2. The recent increase in oil production is attributed to redrilled well NK-07 A. Although injection is currently adequate in this area, future conversions may be considered. 7 Segment 3/5: Production in s'ment 3/5 began in January 1995. Inje.n began approximately two years later at NK-15. Production has been sustained via pressure maintenance from this one injector, although injection has also been attempted at NK-17 with limited success due to poor rock quality. Aquifer support to the west may also be present, but has not been verified. Segment 3/5 performance, in terms of reservoir injection, voidage, pressures, and GaRs, is provided in Exhibit E-3. Oil, gas, and water production for Segment 3/5 is provided in Exhibit E-4. Injection in Segment 3/5 is currently not balanced with voidage, in part due to production from recently redrilled well NK-08A. Another reason is reduced injectivity at NK-15 since being converted to produced water injection roughly one year ago. Converting NK-28 to injection should alleviate this situation and optimize recovery from NK-08A. Segment 2: Production in Segment 2 began in April 1994. Injection began approximately one year later when NK-16, NK-23, and NK-38 were put into injection service. NK-65 was later put on injection in mid-1998. Production has been maintained to varying degrees via pressure maintenance from these injectors. NK -19 is an exception to this because it is completed in a relatively small isolated block that receives no pressure support. This well produced less than half a million barrels of oil before gassing out and dying due to low pressure. NK-18 has had similar performance, but is not completely isolated. NK-18 was recently converted to injection in anticipation of production from the redrill of NK -19 A. These anomalies, along with others, can be seen in Exhibit E-5, which illustrates how Segment 2 is more complex relative to Segments 1 and 3/5. Because of this, well configuration and recovery performance in East Niakuk may differ substantially from what is seen in the west. Oil, gas, and water production for Segment 2 is provided in Exhibit E-6. Pressure Maps Pressure maps by year are provided for the Niakuk field in Exhibits E-7 through E-14. These maps were created by time-weighted averages of all pressure data taken within 365 days of the reported year. Initial reservoir pressure is estimated at 4500 psi. Production prior to 1996 dropped reservoir pressures in some areas. After injection started in 1995, pressures stabilized at roughly 4000 psi in Segments 1 and 3/5. Segment 2 has shown mixed results from water injection due to structural and stratigraphic compartmentalization that is not as evident in the west. Future injection will be determined from reservoir performance. The goal will be to provide adequate pressure support and improve vertical and areal sweep where economically feasible. Development Development at Niakuk is an ongoing process to access oil that otherwise would not be produced. Seismic imaging is incorporated with reservoir simulation models to develop targets aimed at bypassed or undeveloped oil (SECTION 0 contains information on the models). Potential targets are pursued if economically viable. Examples include tapping into suspected compartments or attic oil along faults via low cost sidetracks. Older wells are reviewed for the potential for conversion or service elsewhere. Given constraints on current well locations, improvements in areal sweep will also be considered to improve recovery. An example of this is establishing more of a peripheral flood pattern in Segment 3/5 versus simply maintaining pressure. Converting NK-28 is part of this process. 8 e . SECTION F: Pool Information 20 AAC 25.402(c)(5) The Niakuk Injection Area includes the Niakuk Oil Pool in the Kuparuk Formation. The Kuparuk is defined in the pool rules as the stratum that is common to and correlates with the accumulation found in the Niakuk 6 well between the depths of9,351' and 9,842' subsea (SS) [12,318' and 12,942' measured depth (MD)]. 9 - . SECTION G: Geologic Information 20 AA C 25.402( c)( 6) A. Injection Interval Stratigraphy The geologic framework of the Niakuk Field is set up by deposition of the Kuparuk River formation SS which was deposited downthrown to the Niakuk Field fault. The NK-29 well log (Exhibit G-l) shows the typical Kuparuk sandstone with all stratigraphic zones (1-4) represented. The major stratigraphic features characterizing the Kuparuk are thick aggredational sands commonly divided by a mid Kuparuk Sequence boundary (Zones 213) then capped by an erosional - reworked lower quality zone 4 facies. B. Structure/Cross sections The structure surface on top of the Kuparuk sandstone is shown in Exhibit G-2. The field is a large 3-way NE dipping structure with a crest of -8800 feet in the SW and a low of -9800 feet in the NE. The surface hole locations (SHLs) for all the wells are Heald Point and the Lisburne L-5 pad. A red dashed line highlights the proposed Niakuk Injection Area boundary. Black stars identify current injectors while red stars show proposed injectors. Two S -7 N and one W -7 E structural cross section lines are highlighted on the map and displayed in Exhibits G3, G4, and G5. Exhibit G-3 is a W -7 E structural cross section through the field showing the maximum thickness of 800 feet in the west, the eroded central region near the paleo high, and the accommodation space to the east. Two separate and distinct OWCs are present in the field, - 9240 in the West, and -9535 in the East. Exhibit G-4 is a S -7 N cross section through the Western Niakuk field area. Different OWCs exist (-9240 ft. & -9285 ft.) here as a result of complex stratigraphy rather than a major structural factor. Exhibit G-5 is as -7 N cross section through the East Niakuk field area. A common OWC of -9535 is observed in the eastern field area. C. Confining Interval The producing Kuparuk River Sandstone is bounded below by the Jurassic age Kingak Formation over virtually the entire Niakuk Injection Area. The contact is defined by a change in lithology and electric log character. The Kingak Formation is a highly impermeable, low resistivity (2 - 3 ohm-meters) shale with a thickness varying from 400 to 800 ft. The overlying Kuparuk Formation (producing interval) is characterized by siltstones and sandstones of much higher quality and higher resistivity (6 -70 ohm-meters). In the extreme SE comer of the Injection Area, the Kingak Formation has been interpreted as absent on seismic. In this small area, located in the SE 11<1 of section 28 TI2N, RI6E, confinement of injected fluids will be provided by Lower Kuparuk siltstones and shales as encountered in the NK-23 well. The Kuparuk Formation is overlain by the Lower Cretaceous age Highly Radioactive Zone (HRZ) interval over the entire Injection Area. It is comprised of a 200 ft. thick, black, organic rich shale exhibiting high radioactivity as measured by the gamma ray logs, typically greater than 150 API units. 10 e e D. Flow Properties Water injection patterns in Niakuk are reviewed as production and surveillance data is gathered. Wide perforation intervals spanning most of the stratigraphic zones suggest water injection is being accomplished over a large interval of the reservoir. Production rates and static pressures from producing wells similarly suggest that effective injection sweep is being realized over all communicative zones. Exhibit G-6 is a representative structural cross section in West Niakuk showing the stratigraphic zones from a structural prospective. These stratigraphic zones may be influencing water movement in the reservoir. E. Reservoir Maps Isopach maps of Net Sand, Net Porosity Feet (thickness), Net Water Saturation, and Net Hydrocarbon Pore Foot for West and East Niakuk are presented in Exhibits G-7 through G-14. Wells outside of the field proper were used for additional control in the gridding and mapping process. The oil water contacts define the functional reservoir volume within the Niakuk and Western Niakuk participating areas. The Western Niakuk and Niakuk Participating Areas are best identified by the Hydrocarbon Pore Foot maps, Exhibits G-13 and G-14. 11 · e SECTION H: Well Logs 20 AAC 25.402(c)(7) All openhole logs from Niakuk wells are sent to the Commission as the wells are completed. Exhibit G-1 [NK-29] is the type log for the Niakuk Injection Area with stratigraphic and marker horizons annotated. 12 e e SECTION I: Casing Information 20 AAC 25A02(c)(8) Tubing sizes in the Niakuk field vary from 3 1/2 to 5 1/2 inches. In general, the production casing will be sized to the tubing in the Niakuk wells. Typical development wells will utilize either a "conventional," or "slimhole," design similar to Kuparuk and Prudhoe Bay. The "conventional" design wells will utilize 13 3/8-inch surface casing, 9 5/8-inch production, or intennediate casing with a 7-inch liner for the high stepout wells. The "slimhole" design wells requiring 4 1 /2-inch tubing will utilize 10 314-inch surface casing, 7 5/8-inch production, or intennediate casing with a 5 1/2-inch liner for high stepout wells. Niakuk wells initially designated as water injection wells will be completed with L-80 grade steel. The injection wells planned for pre-production may utilize corrosion-resistant material where applicable. NK-18, which was completed with chrome, has recently been converted into an injector. Most Niakuk water injection completions are currently envisioned as single zone, single string with a single packer. Where potentially advantageous, isolation packers may be run between intervals. Exhibits 1-1 and 1-2 show typical wellbore schematics for the two basic completion designs. Exhibit 1-3 shows the most recent sidetrack (NK-12B) schematic completion. As shown in the schematics, gas lift mandrels with dummy valves have been run to provide flexibility in artificial lift, which will enhance production in the injection wells planned for pre- production. Sufficient mandrels will be run to provide flexibility for well production and gas lift supply pressure. The casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling pennit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. All drilling and production operations will follow approved operating practices in reference to the presence of H2S in accordance with 20 AAC 25.065 (a), (b), and (c). 13 e e SECTION J: Injection Fluid 20 AAC 25.402(c)(9) Two types of injection fluid will be utilized in the Niakuk fujection Area: Source water and Produced water. Source water is obtained from the Beaufort Sea and is the same water currently being injected into the Ivishak Formation in the IP As and into the Pt. Mcfutyre Participating Area. Produced water is water that is produced with Lisburne, Pt. Mcfutyre, West Beach, North Prudhoe Bay and Niakuk oil and separated from the oil and gas at the LPC. Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. A. Source Water 1) Analvsis of Composition of Typical Fluid - Exhibit J-l is a listing of the composition of Beaufort Sea source water. 2) Estimated Maximum Amount to be fuiected Daily - The current well configuration calls for roughly 60,000 BWPD. Future activity could raise this requirement to roughly 70,000 BWPD. 3) Compatibility with Formation and Confining Zone - SEM, XRD and ERD analyses conducted on Niakuk core indicate very low clay content in reservoir intervals (see Exhibit 1-2). As a result no significant problems with formation plugging or clay swelling due to fluid incompatibilities is expected. B. Produced Water 1) Analysis of Composition of Typical Fluid - See Exhibits 1-3, 1-4, and 1-5, respectively, for the compositions of Niakuk, Lisburne, and Pt. Mcfutyre formation water. 2) Estimated Maximum Amount to be fuiected Daily - The current well configuration calls for roughly 60,000 BWPD. Future activity could raise this requirement to roughly 70,000 BWPD. 3) Compatibility with Formation and Confining Zone - The produced water injected into the Niakuk formation will be a mix of Pt. Mcfutyre, West Beach, North Prudhoe Bay, Lisburne and Niakuk produced water separated through the LPC. Current development for these fields indicates the majority of the produced water will come from Pt. Mcfutyre (current maximum estimated at 250 MBWPD) with minimal amounts coming from West Beach (current maximum estimated at 10 MBWPD), Lisburne (current maximum estimated at 20 MBWPD), and Niakuk (current maximum estimated at 50 MBWPD). Because the origin of a vast percentage of the produced water will be the Kuparuk 14 formation, minimal p!ems with formation plugging or clay .lling due to fluid incompatibilities are anticipated. 15 e . SECTION K: Injection Pressure 20 AAC 25.402(c)(10) The estimated maximum and average injection pressures anticipated for Niakuk wells are listed in the following table: Estimated Maximum Injection Pressure (Psi g) Estimated Average Injection Pressure (Psi g) Niakuk Water Injection 2,850 2,450 Pressure represents - Well Head Injection Pressure (WHIP) 16 e e SECTION L: Fracture information 20 AAC 25.402(c)(1l) The estimated maximum injection pressures for enhanced recovery wells will not initiate or propagate fractures through the confining strata, which might enable the injection or formation fluid to enter freshwater strata. There are no freshwater strata in the area of issue (see Section N). Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Injection in the Kuparuk above fracture parting pressure may be necessary to allow for additional recovery of oil. In no instance would such injection pressures breach the integrity of the confining zone. The Kuparuk Formation is overlain by the HRZ shale. The HRZ is a thick shale sequence, which would tend to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. Fracture data from the Kuparuk intervals of the Pt. Mclntyre and West Beach Pools indicate a fracture gradient of between 0.60 and 0.63 psi/ft in current virgin reservoir conditions. Fracture data from Pt. Mclntyre No.9 gave a fracture gradient of 0.624 psi/ft, while data from West Beach No.4 indicated a fracture gradient of 0.602 psi/ft. While no fracture gradient has been obtained in the Kuparuk interval at Niakuk, it is expected that the fracture gradient will be similar since it is Kuparuk rock with similar character. Prudhoe field data also indicates that sandstone fracture gradients may be reduced during waterflooding operations due to reduced in-situ stress associated with the injection of colder water. Declining reservoir pressure can also reduce formation stresses, thereby reducing the fracture gradient. Additional information on the fracture gradient was provided by letter of December 12, 1994, from BP to the AOGCC. This included a HRZ leakoff test on NK-5 and a HRZ integrity test on NK-6. 17 e e SECTION M: Formation Fluid 20 AAC 25.402(c)(12) An analysis of formation water samples obtained from Kuparuk sandstone indicates that Total Dissolved Solids are 25,700 ppm. Wireline log TDS calculations indicate a lack of fresh water (NaCl equivalents of greater than 10,000 ppm). The method used in these calculations is described in Exhibit M-l. 18 e e SECTION N: Aquifer Exemption 20 AAC 25.402(c)(13) The lack of fresh water and underground sources of drinking water in the Niakuk Injection Area obviates the need for an aquifer exemption. The presence of hydrocarbons, either live or residual, causes the Kuparuk Formation of the Niakuk Injection Area to be unsuitable as a source of drinking water. Kuparuk Formation water analysis indicates 25,000 ppm total dissolved solids (TDS). Calculation of TDS from wireline logs indicates NaCI equivalents of greater than 10,000 ppm in the formations above the Kuparuk Formation (see Section M and Exhibit M-l). Therefore, no aquifer exemption is requested nor needed. 19 e e SECTION 0: Hydrocarbon Recovery 20 AAC 25.402(c) 14 Reservoir Background Kuparuk development from the Niakuk Participating Area began in April 1994 upon completion of surface facilities at Heald Point. Production was initiated in 1995 from the Western Niakuk accumulation from ADL034626 and ADL034629. Seawater injection also was initiated at that time. Niakuk was converted to produced water injection in August 2000. The OOIP in Niakuk is estimated at 310 MMBO. Cumulative production to date is 59 MMBO. Initial reservoir pressure was roughly 4500 psi (8900' datum) and the initial temperature ranged from 171 to 182 degrees F. Niakuk oil is generally close to 25 degrees API, but has been observed to vary between 20-30 degrees API. The bubble point pressure is around 4200 psi with solution gas in the 600-700 CF/bbl range (Bo is typically 1.3 RB/STB). Permeability ranges from lOs to 1000s of millidarcies, with pay averaging in the 100-300 millidarcy range. Net to gross also varies from less than 20% to greater than 90% depending on location. Separate oil accumulations have been identified at Niakuk as follows. East and Western Niakuk are separated due to a complete loss of Kuparuk sand across the mid-field high (see Exhibit G-3). Other isolated accumulations exist in East Niakuk as evidenced by data from wells NK -18 and NK-19. Despite reasonable pressure support in the surrounding area, NK-18 had to be shut in due to low pressure and high GORs. This well has been converted to injection in anticipation of the NK -19 A sidetrack. NK -19 is located in a completely separate fault block as evidenced by its unique GOC, OWC, and production history. East Niakuk OOIP is estimated at roughly 120 MMBO. Nominally, Segment 2 covers around 2500 acres. Relative to East Niakuk, Western Niakuk is more homogeneous. A different OWC was observed between Segment 1 and Segment 3/5 and pressure communication across this fault is suspected to be very limited, except where it dies out to the west. Western Niakuk OOIP is estimated at roughly 190 MMBO with about 85 MMBO in Segment 1 and around 105 MMBO in Segment 3/5. Segments 1 and 3/5 cover approximately 3600 acres. Expansion of the Area Injection Order is proposed so NK-28 can be converted to water injection. This well will support the newly drilled well NK-08A, a well that produces roughly 4,000 bopd . Segment 3/5 needs at least one additional injector to balance voidage. This conversion also should help improve areal sweep by establishing more of a peripheral flood. Reservoir Model Description Two reservoir models are used to simulate the Niakuk field. Exhibit 0-1 shows a map view of how the model grids are situated in relation to the wells (250' foot grids). Exhibits 0-2 and 0-3 shows oblique views of the three dimensional framework used in the models. Both models were built using a deterministic methodology. Kuparuk tops and bottoms were defined by seismic data, along with internal stratification where it could be seen. Well control was honored in defining the structure. Geologic descriptions from core, coupled with log data, 20 was used to interpret internal !tigraPhY. These interpretations forme.e basis for an internal zonation scheme, which was then mapped and rolled up into the final simulation grid. Net sand, porosity, water saturation, and hydrocarbon pore feet maps for East and West Niakuk are shown in Exhibits G-7 through -G-14. Exhibit 0-4 shows the zonation key for each model. 32 discrete zones were created for East Niakuk. In the west, 13 zones were created, and further subdivided to create a total of 35 layers. Simulation grids that averaged less than 15% porosity or 10 md permeability were zeroed out. Porosity in both models has been derived from core where available and an interpreted log model elsewhere. The log model incorporates density, sonic, and neutron measurements along with adjustments for shale volumes, heavy minerals, and cementation, which are zone-specific in some cases. For reference, a porosity-permeability cross plot for several Niakuk cores is provided in Exhibit 0-5. Also shown in this exhibit are transforms for the general case (e.g., non zone-specific case) in each field. Initial water saturations are assigned by functions developed from core that incorporate porosity, height above the water column, saturation exponents (Archie model), and Waxman-Smits parameters. Examples of these functions are provided in Exhibit 0-6. Relative permeability experiments have not been conducted with Niakuk rock samples. Accordingly, scalable relative permeability curves developed from Prudhoe Bay samples have been employed and are assigned based on initial water saturation. Examples of these curves are depicted in Exhibit 0-7. Niakuk fluid properties are based on samples taken from NK-I0 in August of 1994 and are summarized in Exhibit 0-8. History matches have been obtained in the West and East Niakuk models and are summarized on the field level in Exhibits 0-9 through 0-18. In order to achieve these matches, some adjustments to the description were required, particularly with respect to fault locations and characteristics. Recovery Simulation studies in the early 1990s indicated benefit from waterflooding at Niakuk. The primary recovery factor was estimated at 4%, whereas waterflooding was expected to achieve roughly 40% recovery. The model used to create these initial estimates was smaller and not as refined as the models summarized above. More recent review of these mechanisms supports the same conclusion, although in varying degrees. For Western Niakuk, given the current well configuration, simulation suggests a primary recovery factor of around 13%, with waterflooding upwards of 37%. In East Niakuk, the benefits due to waterflooding are less pronounced due to higher degrees of complexity, reservoir heterogeneity, and uncertainty in development plans. The Niakuk models also are used to evaluate infill drilling and conversion candidates. Reservoir management is improved from the visualization of fluid migration and identification of unrecovered oil. Infill targeting requires evaluating variables such as location, injector utilization, and completion strategy. The goal is to maintain confidence in the existing reservoir description and create fairly well defined assessments of the benefits of future development work. 21 e e SECTION P: Mechanical Integrity 20 AAC 25.402(e) In drilling Niakuk injection wells, the casing is pressure tested in accordance with 20 AAC 25.030(g). When a producing well is converted to injection, the casing pressure test will be repeated in accordance with 20 AAC 25.412(c). Injection well tubing/casing annulus pressures will be monitored and recorded on a regular basis. BP as the operator of the Niakuk oil pool, will be responsible for mechanical integrity of injection wells and for ensuring compliance with monitoring and reporting requirements. The tubing/casing annulus pressure of each injection well is checked weekly to ensure there is no leakage and that it does not exceed a pressure that would subject the casing to a hoop stress greater than 70 percent of the casings minimum yield strength. If an injection well is deemed to have anomalous annulus pressure, it will be investigated for tubing/annulus communication using a variety of diagnostic techniques and a mechanical integrity test. If subsequent investigation indicates hydraulic communication between the tubing/casing exists, a plan for remedial action will be formulated. A variance will be obtained from the AOGCC to continue safe operations, if technically feasible, until the remedial solution is implemented. BP will maintain annular pressure data in the Injection Well Database and will provide copies with monthly Injection Reports (Form 10-406) to provide annular pressures, diagnostic comments, and scheduled remedial action. Tubing/casing pressure variations between consecutive observations need not be reported to the Commission. A schedule developed and coordinated with the Commission ensures that the casing/annulus for each injection well is pressure tested prior to initiating injection, and at least once every four years thereafter. The casing must be tested at a test surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% over the casing's minimum yield strength. The test pressure must be held for 30 minutes with no more than a 10 percent decline. The Commission is to be notified at least 24 hours in advance to enable a representative to witness the pressure test. With Commission approval, alternate EPS approved methods may be used, including timed-run radioactive tracer surveys (RTS), oxygen activation logs (OAL), temperature logs (TL), and noise logs (NL). An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. 22 e . SECTION Q: Mechanical Condition of Wells 20 AAC 25.402(c)(15) To the best of BP's knowledge, the wells within the Niakuk and Western Niakuk Participating Areas were constructed, and where applicable, have been abandoned to prevent the movement of fluids into freshwater sources. NK-28 is the only well currently planned to be converted to an injector. A Segmented Bond Tool was run in the well in-July 1995. The tool shows good bond above and below the perforations. The gas lift valves are being dummied off and a mechanical integrity test is to be performed. Any well converted to an injector in the future will undergo the same requirements. 23 Exhibit A-la: Exhibit A-lb: Exhibit A-2: Exhibit C-l: Exhibit D-l : Exhibit E-l: Exhibit E-2: Exhibit E-3: Exhibit E-4: Exhibit E-5: Exhibit E-6: Exhibit E-7: Exhibit E-8: Exhibit E-9: Exhibit E-l 0: Exhibit E-ll : Exhibit E-12: Exhibit E-13: Exhibit E-14: Exhibit G-l: Exhibit G-2: Exhibit G-3: Exhibit G-4: Exhibit G-5: Exhibit G-6: Exhibit G-7: Exhibit G-8: Exhibit G-9: Exhibit G-l 0: Exhibit G-ll : Exhibit G-12: Exhibit G-13: Exhibit G-14: Exhibit 1-1: Exhibit 1-2: Exhibit 1-3: . . List of Exhibits Niakuk Injection Area Well Locator Map Legal Description of Niakuk Injection Area Niakuk Injection Area Lease Ownership Affidavit Niakuk Injection Management, Segment 1 Niakuk Production History, Segment 1 Niakuk Injection Management, Segment 3/5 Niakuk Production History, Segment 3/5 Niakuk Injection Management, Segment 2 Niakuk Production History, Segment 2 Niakuk Pressure Map for 1994 Niakuk Pressure Map for 1995 Niakuk Pressure Map for 1996 Niakuk Pressure Map for 1997 Niakuk Pressure Map for 1998 Niakuk Pressure Map for 1999 Niakuk Pressure Map for 2000 Niakuk Pressure Map for 2001 Niakuk 29 Type Log Kuparuk Structure Map West to East Structural Cross Section South to North Structural Cross Section South to North Structural Cross Section West Niakuk - Representative Structural Cross Section West Niakuk Net Sand Map East Niakuk Net Sand Map West Niakuk Net Porosity Map East Niakuk Net Porosity Map West Niakuk Net Water Saturation Map East Niakuk Net Water Saturation Map West Niakuk Net Hydrocarbon Pore Foot Map East Niakuk Net Hydrocarbon Pore Foot Map Typical Niakuk Well Schematic Slimhole 4.5-inch Tubing Typical Niakuk Well Schematic 4.5/5.5-inch Tubing Typical Niakuk Well Schematic for Sidetrack with 4.5-inch liner and tubing 24 Exhibit J-l: Exhibit J-2: Exhibit J-3: Exhibit J-4: Exhibit J-5: Exhibit M-l: Exhibit 0-1: Exhibit 0-2: Exhibit 0-3: Exhibit 0-4: Exhibit 0-5: Exhibit 0-6: Exhibit 0-7: Exhibit 0-8: Exhibit 0-9: Exhibit 0-10: Exhibit 0-11: Exhibit 0-12: Exhibit 0-13: Exhibit 0-14: Exhibit 0-15: Exhibit 0-16: Exhibit 0-17: Exhibit 0-18: . List of Exhibits (cont.) . Beaufort Seawater Composition Niakuk Clay Content Niakuk Produced Water Composition Lisburne Produced Water Composition Pt. McIntyre Produced Water Composition Documentation of Water Salinity Calculations From Well Logs Niakuk Reservior Model Grids West Niakuk Model (oblique view) East Niakuk Model (oblique view) Zonation Key for the Niakuk Full Field Models Niakuk Porosity-Permeability Cross Plot Example Water Saturation Functions Relative Permeability Summary Niakuk Field Reservoir Model PVT Properties West Niakuk History Match Summary: Oil West Niakuk History Match Summary: Gas West Niakuk History Match Summary: Produced Water West Niakuk History Match Summary: Injected Water West Niakuk History Match Summary: Pressure East Niakuk History Match Summary: Oil East Niakuk History Match Summary: Gas East Niakuk History Match Summary: Produced Water East Niakuk History Match Summary: Injected Water East Niakuk History Match Summary: Pressure 25 Niakuk Well Locator Map Exhibit A..1 b PROPOSED NIAKUK INJECTION AREA EXPANSION Exhibit A-1a 10 w Scale 1 :48,000 2000 1000 0 4000 I I I I Feet 18 Projection: ASP4 NAD 1927 Proposed Injection Area 15 Working Interest in Niakuk leases: E)()(onMobii Alaska Pro 36.82263% Phillips Alaska Ino 36.49270% SP 26.66467% Forest 0.02000"Ao 22 so-os o 28 GULL ISlAND 33 34 NIAKUK ISLANDS L5¿33 35 1.5·21 . . Exhibit A-2 Legal Description of Niakuk Injection Area T12N, R15E UM Sections: 13, 14, 15, 16,22,23,24,25,26, and 27 Sections: 21: N/2 SE/4, 36 NE/4 T12N, R16E UM Section: 28 W /2, NE/4, W /2, SE/4, S/2, E/2, SE/4 Sections: 29, 30 Sections: 31 N/2, 32 N/2 26 C-1 Exhibit NIAKUK INJECTION AREA LEASE OWNERSHIP . . Exhibit D-l AFFIDA VIT REGARDING NOTICE TO SURFACE OWNERS IN THE VICINITY OF THE PROPOSED INJECTION WELLS Anne L. Shaw, on oath, deposes and says: 1. I am the Resource Manager at BP Exploration (Alaska), Inc., the Operator of the Niakuk Participating Area and Western Niakuk Participating Area within the revised Niakuk Injection Area, Prudhoe Bay Unit; 2. On October 25,2001, I caused copies of the application for the updated Area Injection Order to be provided to the Surface Owners of all land within a quarter mile of all proposed injection wells within the Niakuk Injection Area as listed below: State of Alaska Department of Natural Resources Attn: M. D. Kotowski P.O. Box 107034 Anchorage, AK 99510 BP Anne L. Shaw P.O. Box 196612 Anchorage, AK 99519-6612 Native Allotment Parcel B Owners Mr. Leroy Oenga P.O. Box 201 Barrow, Ak 99723 Mr. Michael M. Delia 1228 28th Avenue Fairbanks, AK 99701 Ms. Georgene Shugluk P.O. Box 1621 Atqasuk, AK 99791 Mr. Wallace Oenga P.O. Box 1128 Barrow, AK 99723 BW Heirs of Jenny Oenga c/o Inupiat Community of the Arctic Slope Realty Department 4495 Northstar Street Barrow, AK 99723 A* y il¡iJ:- STATE OF ALASKA ) ) ) ss. THIRD JUDICIAL DISTRICT SUBSCRIBED AND SWORN to before me this 25 day of October 2001. . 'th !J1ldiv . ~ ? NOTARY PUBLIC IN AND FOR ALASKA My Commission Expires: ~ '~ J-003 27 Notay Public MONITAJ. OLM: State of AIasIca My Commission Expires f.kJy 7.2003 C\~" 25000 5000 0::: 0 c.::¡ (!) 5 </) ø 20000 4000 !!: a.. á5 $9 (f) 15000 3000 Exhibit E..1 40000 Niakuk Injection Management, Segment 1 -Injection (R8D) Flux (R8D) 35000 Pressures GOR (scfpbo) 30000 10000 5000 o Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-OO Jan-01 8000 7000 6000 2000 1000 o 20000 18000 16000 14000 12000 10000 8000 6000 4000 2000 Exhibit E...2 Niakuk Production History, Segment 1 o Jal1-93 Jan-94 -Oil BOPO -Water BWPO I\ICFPO 30000 6000 ¡.::: ¡.::: ,.- ,.- , ~ ~ Z z 25000 5000 gj CJ () 5 '" t/J 20000 4000 ~ a.. <.:> ~ èi5 15000 3000 Exhibit E...3 40000 Niakuk Injection Management, Segment 3/5 -Injection (RBD) - Flux (RBD) Pressures 35000 o~GOR(scfpbo) 10000 5000 o Jan-94 8000 7000 2000 1000 o 20000 18000 16000 14000 12000 10000 8000 6000 4000 2000 o Jan-93 Exhibit E...4 Niakuk Production History, Segment 3/5 -Oil BOPO -Water BWPO IVCFPO Exhibit E...5 40000 Niakuk Injection Management, Segment 2 -Injection (RBD) Flux (RBD) Pressures GOR(scfpbo) 35000 30000 8000 7000 6000 25000 5000 gj <:) 2: :::¡ II> (J) 20000 4000 £ <.:I ~ W 3000 15000 10000 5000 2000 1000 o 20000 18000 16000 14000 12000 8000 6000 4000 2000 o Jan-93 Exhibit E..6 Niakuk Production History, Segment 2 Jan-94 -Oil BOPO -Water BWPO - Gas !\I!CFPO Jan-95 Jan-OO Jan-01 Exhibit E-7 Exhibit E-9 Exhibit E...10 E...11 Exhibit Exhibit E-12 Exhibit E...13 Exhibit E-14 -- st Exhibit G...l Exhibit G...2 Nia -T P upar k tructure ap ..9800 29 32 5 3 ...- -.- BPE:xplot"&Uon . A.!a.Øka - Exhibit G-3 Niakuk- Top 7 Base uparuk Structural Cross Section W-E Structural Well Cross-Section through Niakuk and Western Niakuk Reservoirs West East I I I I I I I I I I I I I I - 9500 I Seg owe I I I I I I I DAiHua ..) Exhibit G...4 iakuk- Top -7 ase Kuparuk Structural Cross Section S- N Structural Well Cross-Section through Western Niakuk Reservoir --- - North --- -- --- -- --- 8900 9000 9100 9200 9300 9400 Seg 1,3/5 owe -0185 9500 9600 2.2 ¡ ma'rAt'lC!tOO~:N: 0' . 2223' .- 4513' ,'u, "" 11742' H742 Exhibit G...5 Niakuk- op -7 Base uparuk Structural Cross Section SW-NE Structural Well Cross-Section through Niakuk Reservoir Southwest 1---- I 1 9100 1 I 9200 I I 1 9300 I I 9400 I 1 I 9500 I I 9600 I 1 1 9700 I I 9800 I I I I 0' 1198' , '''' --- --- -- --- --- --- Northeast NK-38 8 c West Niakuk ...... Representative Structural Cross Section West Stratigraphic Zonation -- Highlights Possible Flow Pathways East --- 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 - -- --- --- ~'" Exhibit E-B e e EX HI 1-1 TYPICAL SLlMHOLE WELL SCHEMlc TREE: 4-1116", SM, CIW WELLHEAD: 13-5IS", 5M, FMC ACTUATOR: BAKER :1:i·lI·i:il· KB. ELEV = BF. ELEV = 4-1/2" OTIS CP-2 TRSSV (3.S1" 10) 10-3/4". 45.5#1ft, NT-BO, BTC. ..:.:.:.:.:.:.:.:.:.:-:.:.". :¡!iiiiiiil!¡!ii¡!!!¡:¡. GASlIFT MANDRELS 4-112" TUBING "X" NIPPLE - PACKER "X" NIPPLE "X" NIPPLE WLEG PBm 7-5IS", 29.7#1ft, NT-80, NSCC. REV. BY , " " " " '\. " ,/ " " / , , , " " " " " " " DATE COMMENTS NIAKUK WELL: API NO: SEC : TN : RGE BP Exploration (Alaska) €XHI- 9/-2 TYPICAL C TREE: (4 1/2" ONV€NìION. WEl.l.HE:.4D. ? 1/16" C'f OR 51/2" ì,(JA( W€(t srA 4CTU4TOR: 135/8" FMc SIII/G) ~AìIC . Baker 9-518' L ' 4?t/lft -80, NScC ' 13-3/8' 72 I.-eo S'T: #Ift, , As ----- Ka. EV... BF. 8..EV.. (eu :; MOdel 10 ( 4.562 . JD) ìRsV} --- GASI.1FìûA.. """VDRELS '8%. NIPPLE rOp OF' '1" I.IN12R --- PA.CkER -- 'XN" NIPPI.E . TaG TAIL RE(EIVED NOV 1 6 1994 I\\aska Oil & Gas Cons. Commissio Anchor<.ß 5 ~ (xll/IJIT 1-3 / y¡JIC AL I·IJ.£T~A¿I( iJELL c..1I[AI¡4/I¿ TREE = 4-1116"5MCIW NK-12B I SAFAES I WELLHEAD= 13-5/8" 5M FMC ACTUA TOR- BAKER C KB. ELEV = 51.88' BF. ELEV = 1-14-112" HES CP-2 TRSSSV NIP, ID = 3.938" I KOP= 1300' I 2023' Max Angle = 79 @ 13722' . Datum MD = 13800' GAS LIFT MANDRELS Datum lVDss= 8800' ST MD lVD DEV TYÆ VLV LATCH SIZE DATE 110-3/4" CSG, 45.5#, NT-80S BTC, ID = 9.950" ~ ~ 3 3239 3037 40 KBG-2LS DOME INTG 1.0" 03125101 2 7098 5471 59 KBG-2LS DOME INTG 1.0" 03/25/01 1 10711 7249 59 KBG-2LS SO INTG 1.0" 03/25/01 Minimum 10 = 3.725" @ 10843' U 4-1/2" HES XN NIPPLE I t 10778' 1--14-1/2" HES X NIP, 10= 3.813" I . :8: ~ I 10799' H 7-5/8" X 4-1/2" BAKER S-3 A<R, ID = 3.850" I I I I 10822' H4-112" HES X NIP, ID = 3.813" I I I 10843' 4-112" HES XN NIP, 10 = 3.725" I I 14-112" TBG, 12.6#, L-80 IBT-M, ID = 3.958" I 10855' I I 10855' H4-1/2" WLEG I ~ ~ .::: ~ 10849' 1-17-5/8" x 4-1/2" BAKER ZXP A<R, ID = 4.938" I k1R[ r--'t ì 10869' I-fBAKER 7" X 5" HMC LNR HANGER. ID = 4.938" I ÆRFORA IDN SUMMARY RB= LOG: TCP ÆRF ANGLEATTOPPERF: 62 Note: Refer to Production DB for historical perf data I ELMD - TT NOT LOGGED I SIZE SPF INTERV AL Opn/Sqz DATE 2-7/8" 6 16175 - 16195 0 05112/01 .J 11092' -fTOP OF BAKER WHIPSTOCK I ~~ ....... I 2-112" 6 16330 - 16390 0 03/15/01 11106' H EZSV BRIDGEFUJG I ~ ~ 16300' HClBPSET06/26101 I ~ I 7-5/8" MILLOUT WINDOW 11092' - 11104'/ I PBTD H 16453' I 113590' HTop P&A Cement I 17-5/8" CSG, 29.7#, NT 95 HS, NSCC, ID = 6.875" I 15024' 14-1/2" LNR, 12.6#, L-80 HYD 521, .0152 bpf, ID - 3.958" I 16550' I DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BA Y UNff ORIGINAL COMPLETION WELL: NK-12B 03/19/01 CHlKAK RIG SIDETRACK PERMff No: 201-015 05/08101 pcr UPOA TED API No: 50-029-23414-02 05/12/01 ATDltlh ADD PERFS SEe 36; T12N; R15E 1327' FSL 996' FEL 06/26101 JLG/tlh SET ClBP BP Exploration (Alaska) e e Exhibit J-l Beaufort Sea Source Water Analysis Determination Summer Winter Units Specific Gravity 1.013 1.024 Mg/L pH 7.5 7.8 Mg/L Calcium 196.0 365.0 Mg/L Magnesium 631.0 1190.0 Mg/L Sodium & Potassium 5680.0 10400.0 Mg/L Strontium 0.0 0.0 Mg/L Barium 0.0 0.0 Mg/L Iron 0.0 0.0 Mg/L Bicarbonate 85.0 142.0 Mg/L Carbon Dioxide Calc. 0.0 0.0 Mg/L Total Dissolved Solids 17852.0 32787.0 Mg/L Chloride 9880.0 18200.0 Mg/L Sulfate 1380.0 2490.0 Mg/L Resistivity @ 700P 0.422 0.255 Ohms Suspended Solids 6.0 1.0 Mg/L e e Exhibit J-2 Clay Content in Niakuk Reservoir Zones Zone! Well Sam led Zone 3 (NK #1A) Zone 0 (NK #5) Zone E (NK #6) Zone F NK #6 Cia Content· 0-1% kaolinite, 1-2% illite trace to 1 % illite, trace kaolinite &.!or chlorite trace only of illite trace onl of kaolinite, trace onl of illite . Based on Scanning Electron Microscopy, X-ray diffraction, and Energy Dispursive X-ray Spectroscopy e Exhibit J-3 . Niakuk Produced Water Analysis Determination Value Units pH 7.0 Mg/L Calcium 95.0 Mg/L Magnesium 22.0 Mg/L Sodium 9925.0 Mg/L Potassium 147.0 Mg/L Strontium 16.0 Mg/L Barium 1.7 Mg/L Iron 5.2 Mg/L Bicarbonate 3870.0 Mg/L Chloride 11440.0 Mg/L Sulfate 190.0 Mg/L Total Dissolved Solids 25711.9 Mg/L "It-\) ~~t-\~ ~ \~~Ót , "\ ~ ''if¡'\o~ t..\ () 'I ~ow.w.~ \' ~o~s. _\ ~ (;,'3.S ~e \,~ 0\\ ~"o~....·; ~'ò.s~ Þ-~ at e Exhibit J-4 Lisburne Produced Water Analysis Determination Value Units pH 8.5 Mg/L Calcium 105.0 Mg/L Magnesium 50.0 Mg/L Sodium (calc) 10555.0 Mg/L Sodium (AA) 13875.0 Mg/L Strontium 3.8 Mg/L Barium 1.1 Mg/L Iron 1.1 Mg/L Hydroxyl 0.0 Mg/L Carbonate 228.0 Mg/L Bicarbonate 2618.0 Mg/L Chloride 14261.0 Mg/L Sulfate 750.0 Mg/L Total Dissolved Solids 28753.0 Mg/L ~ . Exhibit J-5 e Pt. Mcintyre Produced Water Analysis Determination Value Units pH 7.2 Mg/L Calcium 24.0 Mg/L Magnesium 9.0 Mg/L Sodium 8540.0 Mg/L Potassium 179.0 Mg/L Strontium 7.0 Mg/L Barium 11.0 Mg/L Iron 1.4 Mg/L Hydroxyl 0.0 Mg/L Carbonate 0.0 Mg/L Bicarbonate 3262.0 Mg/L Resistivity @ 68°F 0.4 Ohms I~hloride 10597.0 Mg/L Silicon 24.0 Mg/L e Exhibit M-1 . Documentation of Water Salinity Calculations from Well Logs The four wells, NK-1, NK-3, NK-6 and SD-8, were selected for the calculation because they are spatially representative of the Niakuk Injection Area and have wireline logs up-section and through the Kuparuk Formation. The steps in the calculation were: 1) Formation Temperature: Tfm = 0.0222 (Depth fm - Depth base of permafrost) + 32 deg. F 2) Porosity from Sonic Log: 0.625 * (dt-55) Phi = --------------------------- dt 3) Apparent Formation Water Resistivity (m and a from Humble equation): Phi**m * Rt Rvva = ------------------------- a 4) Water Resistivity @ 75 deg. (Schlumberger): Rwa * Tfm + 6.77 RW@75 = ---------------------------- 81.77 5) Total Dissolved Solids in NaCI Equivalents (Dresser Atlas): (3.562 - 10910 (Rw@75 - 0.0123)) TDS = 10** ----------------------------------------------------- 0.955 Exhibit 0...1 74 x51 x 193 MMBOIP Segm ent Niakuk Reservoir Model Grids Segment 1 Segment 2 Alaska Plane Exhibit 0...2 Niakuk Field -- est Niakuk odel Niakuk Field - East Niakuk odel Exhibit 0...3 Zonation Key for the Niakuk Full Field Models West Niakuk Laver Zone Laver Zone 1 4 19 2C2 2 20 3 21 4 382 22 2C1 5 23 6 24 7 25 28 8 381 26 9 27 2A 10 3A2 28 11 29 12 30 1C 13 3A1 31 14 32 18 15 33 16 2C3 34 1A 17 35 18 Exhibit 0-4 East Niakuk Laver Zone Laver Zone 1 1a 21 7c 2 2a 22 7d 3 2b 23 7e 4 2c 24 8a 5 2d 25 8b 6 2e 26 9a 7 3a 27 9b 8 3b 28 9c 9 3c 29 9d 10 3d 30 ge 11 3e 31 10a 12 4a 32 10b 13 4b 14 4c 15 4d 16 5a 17 6a 18 6b 19 7a 20 7b e - 10000 Niakuk Porosity - Permeability Cross Plot 1000 . . . . 100 . . . . . . . . . 10 III .... . . . . . 0.1 0.01 5 10 15 20 Porosity (%) Exhibit 0...5 ". . . . . . " NK-01A NK-05 NK-06 NK-15 NK-29 - West Niakuk Transform East Niakuk Transform 25 30 200 150 t) (\j ë o ü Q; 100 ~ Õ Q) > o ..a « 50 Porosity o o Niakuk Example Water Saturation Functions 15% Porosity 20% 25% 10 Water Saturation % Exhibit 0...6 ----- West Niakuk Zones 1-4 East Niakuk Zones 1Z and 4-10 80 90 100 10000 0 24 25 26 27 28 29 30 31 1.0 0.9 0.8 0.7 0.6 ¡: 0.5 0<: 2 0<: 0.4 0.3 0.2 0.1 0.0 0 80000 70000 60000 50000 40000 30000 20000 Histogram of Relperm Curve Types in West Niakuk 32 33 Exhibit 0..7 70000 Histogram of Relperm Curve Types in East Niakuk 60000 50000 40000 30000 20000 10000 2' 0<: o 31 32 33 1.0 ~ 2 0<: 0.4 0.5 0,6 Sg Exhibit 0-8 Niakuk Field Reservoir odelP Prope .. les 1600 2.0 1400 1.8 1.6 1200 1.4 1000 1.2 Water Density:::: 1.02 gms/cc 15 co Bwi :::: 1.02 RB/STB 800 it 1.0 iñ ~ I- Vw :::: 0.40 cp '" 0.8 f.!) 600 0:: ã5 0.6 Ë. 400 S 0.4 200 0.2 Pressure (psìa) Pressure (psìa) 0 0.0 0 2000 4000 6000 8000 0 2000 4000 6000 8000 :3 6 0.05 Gas GravŒY = 0.76 5 0.04 2 4 0.03 i:L () :3 êi :2' ã5 ~ Ë. !j; 0.02 fi! 2 0.01 Pressure (psìa) Pressure (psia) 0 0 0.00 0 2000 6000 8000 0 2000 4000 6000 8000 Exhibit 0-9 West Niakuk History Match Summary - 2000 Model - 2001 Model + Actual ~ Exhibit 0-10 West Niakuk History Match Summary -- 2000 Model -- 2001 Model + Actual ~ Exhibit 0-11 West Niakuk History Match Summary - 2000 Mode! - 2001 Mode! + Actual ~, Exhibit 0...12 West Niakuk History Match Summary - 2000 Mode! - 2001 Mode! + Actual - Exhibit 0..13 West Niakuk History Match Summary - 2000 Model - 2001 Model + Actual Exhibit 0-14 East Niakuk History Match Summary - 2000 Model - 2001 Model + Actual ~ Exhibit 0-15 East Niakuk History Match Summary - 2000 Model - 2001 Model + Actual Exhibit 0-16 East Niakuk History Match Summary - 2000 Model - 2001 Model + Actual Exhibit 0-17 East Niakuk History Match Summary -. 2000 Model -. 2001 Model + Actual ~ Exhibit 0-18 East Niakuk History Match Summary - 2000 Model - 2001 Model + Actual + + + #7 . to 'bp . . BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 August 13,2001 Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501 Attn: Cammy Taylor, Commissioner Jane Williamson, Engineer Jack Hartz, Engineer Bob Crandall, Geologist Re: Request for NK-28 Injection and Response to 8/1/01 AOGCC Request for Additional Data to Support the Revised Niakuk Area Injection Order 14 BP would like to request interim permission for 60 days to convert well NK-28 to water injection while we collate the data you require for the Revised Area Injection Order (AIO). As per our telephone conversation on August 7, we are supplying the information below to provide a better understanding of why a timely conversion is desired. The Niakuk accumulation is separated into Eastern and Western areas due to a complete loss ofKuparuk sand across the mid-field high (see Figure 3, Revised AIO first draft). In the Western accumulation, separate OWCs and production history indicates that Segment 1 is separated from Segment 3/5 (see Figure 4, Revised AIO first draft). This results in three main Niakuk pools: Segment 1, Segment 3/5, and Segment 2 (East Niakuk). Attachment 1 in this note depicts a net oil pore foot map for Western Niakuk, the sealing fault that separates Segment 1 from Segment 3/5, and the area of expansion for the Revised Area Injection Order. Production at Niakuk has been sustained by pressure maintenance. In Segment 3/5 this support has come from water injection in NK-15. Simulation work has demonstrated an opportunity to improve the depletion strategy for Segment 3/5 and advance the waterflood into more of a peripheral pattern. The first step in this involves converting NK-28 to injection. Although this well produced close to 2.0 MMBO, it cut water from its initial production and is currently watered out. Other conversions will be considered in the future to optimize recovery. RECEIVED AUG 1 3 Z001 Alaska Oil & Gas Cons. Commission Anchorage . . Page 2 It is evident from material balance (see Attachment 2) that Segment 3/5 is in need of additional injection. The recently redrilled NK-08A has increased off-take by over 4,000 BOPD from the heart of Segment 3/5 (see Attachment 3). In addition, injectivity at NK- 15 has declined since being converted to produced water injection approximately one year ago. Included for your reference is a diagram showing the relative volumes of production and injection that are desired once NK-28 is converted to injection (see Attachment 4). Without injection support from NK-28, reserves will likely be left behind. Any additional water we can inject at the Niakuk field directly increases our water handling capacity at the LPC, thus boosting our overall GPMA oil rate. Having NK-28 on injection during our planned rework of our cretaceous injector LPC-02 will greatly alleviate the associated production impact. This work is scheduled for early September. Within the agreed 60-day period, we will provide you with the additional infonnation for the revised Area Injection Order per our conversation on August 7. This includes the four geologic reservoir maps for net sand, porosity, hydrocarbon pore foot, and water saturation, as well as a more complete write up of the requested sections in your letter of August 1. Please let us know at your earliest convenience when we may commence injection into NK-28. Sincerely, ~y~ Anne L. Shaw GPMA Team Leader cc: M. Cole - BP M. Evans - ExxonMobil J. Johnson - Phillips Alaska, Inc. M. Johnson - ExxonMobil G. Limb - Phillips Alaska, Inc. 8000 7000 6000 5000 ~ ø - G) 5 (ð (ð 4000 ;. (.) 'i 00 3000 2000 1000 0 ~Iniection (REID) ~Flux (REID) -- Pressures (scfpbo) - - ¡:;;; .... , ::c: z 40000 r Nlakuk Reservoir Material Balance, Segment 315 35000 30000 ¡:;;; .... 'd:: z Jan-oo Jan-99 ~ Jan-98 'd:: z 25000 20000 5000 10000 5000 20000 -Oil SOPD Niakuk Production History, Segment 315 18000 16000 Jan-94 0000 8000 6000 4000 ~ ('II #6 [Fwd: Niakuk AlO] . . Subject: [Fwd: Niakuk AIO] Date: Thu, 02 Aug 2001 17: 10: 17 -0800 From: Julie Heusser <julie_heusser@admin.state.ak.us> To: Jody J Colombie <jody_colombie@admin.state.ak.us> Hi Jody, Would you please include a copy of this e-mail in the record for Niakuk AIO expansion. Thanks Julie ",,'"_''''_r_m'~'~''' ""WW___w_'_'_n_mnm,.>m.m~,,,,,,,,,,,,,,wc,ü_~_~_w_,_,_ _m_'___nnmmmnmm,'.">."m,~,,=WM ""wmwmm_~".~"__.~_____^_ W,-n---"=,,,ww.,'N^' Subject: RE: Niakuk AIO Date: Thu, 2 Aug 2001 20:39:37 -0500 From: "Shaw, Anne L (BP Alaska)" <ShawAL@BP.com> To: "'Jane Williamson'" <Jane_ Williamson@admin.state.ak.us>, Jack Hartz <jack_hartz@admin.state.ak.us>, "Camille O. Taylor" <Cammy _ Taylor@admin.state.ak.us>, Dan Seamount <dan_seamount@admin.state.ak.us>, Julie Heusser <julie _ heusser@admin.state.ak.us>, Bob Crandall <bob_crandall@admin.state.ak.us>, Steve Davies <steve_davies@admin.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Wendy D Mahan <wendy _ mahan@admin.state.ak.us> CC: "Warner, Dwight" <WarnerDW@BP.com>, "Mark Evans (E-mail)..<mpevans@upstream.xomcorp.com> , "Jim Johnson (E-mail)..<jpjohns@ppco.com>. "Limb, H Gary (Phillips)" <HLIMB@ppco.com>, "Johnson, Michael R (Exxon-Mobil)" <Johnson6@BP.com>, "Cole, Mike D" <colemd@BP.com>, "Schafer, Daniel B" <SchafeDB@BP.com>, "Taylor, Paul J" <TaylorPJ@BP.com> Jane and Jack, We have received your message of August 1, 2001, and the list of additional information you have requested regarding our application for a revision to Area Injection Order 14. The data you have requested is significantly more than the information necessary for expansion of the Niakuk injection area as discussed at our meeting on June 11th, and also is substantially more information than was provided at the time of the original Niakuk Area Injection Order. While we will try to provide the additional information as soon as practical, responding will require quite a bit of staff time and will impact other ongoing activities, including plans to commence injection in NK-28. Given the additional work that will be necessary to review and respond to your letter, we request that the record be kept open for an additional (30) days. We will be able to provide the additional discussion items you have requested and certain of the data and maps. A session in the HIVE at the BP office to review the model and history match may be possible as well. However, our preliminary review indicates there likely will be some information that we will not be able to provide. Based on our conversation with you this afternoon we will follow your lof2 8/16/018:46 AM [Fwd: Niakuk AIO] . . suggestions to use your requested list as a guideline for providing additional information. Additionally, as we mentioned, if there is any way we can begin injection at NK-28 prior to the finalization of this document it would be certainly appreciated. Anne L. Shaw GPMA Team Leader BP Exploration (907)564-5844 -----Original Message----- From: Jane Williamson [mailto:Jane Williamson@admin.state.ak.us] Sent: Wednesday, August 01, 2001 12:20 PM To: Anne Shaw; Camille o. Taylor; Dan Seamount; Julie Heusser; Jack Hartz; Bob Crandall; Steve Davies; Thomas E Maunder; Wendy D Mahan; WarnerDW@BP.com Subject: Re: Niakuk AIO I had a slight typo in the original attachment to this letter. Please discard and use this attachment Jane Williamson Jane Williamson wrote: > Dear Anne, > > > > > > > > > > > > > > > > > > > > > > > > Please call me (793-1226) or Jack Hartz (793-1232) if you wish to > discuss further. > > Sincerely, > > Jane Willamson > AOGCC Petroleum Engineer > > > requirments BP Niakuk AI014.doc > AOGCC list of requirments BP Niakuk AI014.doc (applicationjmsword) > Attached is a review by the AOGCC technical Staff of the Application for Revision of Niakuk Area Injection Order #14 which you submitted to us on July 24, 2001. (2 initial copies were provided received on July 23, 2001. We are using the July 24, 2001 for the copy of record.) The revision is requested for the purposes of beginning waterflood in the Western Niakuk region, not currently covered by AIO 14. The application is not complete. The Commission needs an updated record of the project plans, current and future, and must provide sufficient reservoir, completion and geologic information for evaluation of the proposed expansion. The quantity of oil in place 310 MMBO, with the expantion area containing 190 MMBO, emphasizes the need for the Commission to fully evaluate the project. Our current records are vastly out of date as to reservoir/geologic description and are insufficient for the task at hand. Please review this list and let us know how long you will need to keep the record open on this matter, in order to gather, document, and review the submittal. At your request we will keep the record open longer in order for you to gather the information. Please advise us as to the date you wish for extension of the record on this matter. -------------------------------------------- ---------------------------- Name: AOGCC list of Type: WINWORD File Encoding: base64 20£2 8/16/01 8:46 AM Re: Niakuk AlO . . Subject: Re: Niakuk AIO Date: Wed, 01 Aug 2001 12:20:23 -0800 From: Jane Williamson <Jane_ Williamson@admin.state.ak.us> Organization: Alaska Oil & Gas Conservation Commission To: Anne Shaw <ShawAL@BP.com>, "Camille O. Taylor" <Cammy_Taylor@admin.state.ak.us>, Dan Seamount <dan_seamount@admin.state.ak.us>, Julie Heusser <julie_heusser@admin.state.ak.us>, Jack Hartz <jack_hartz@admin.state.ak.us>, Bob Crandall <bob _ crandall@admin.state.ak.us>, Steve Davies <steve _ davies@admin.state.ak.us>, Thomas E Maunder <tom _ maunder@admin.state.ak.us>, Wendy D Mahan <wendy_mahan@admin.state.ak.us>, WamerDW@BP.com I had a slight typo in the original attachment to this letter. Please discard and u Jane Williamson Jane williamson wrote: > Dear Anne, > > Attached is a review by the AOGCC technical Staff of the Application for > Revision of Niakuk Area Injection Order #14 which you submitted to us on > July 24, 2001. (2 initial copies were provided received on July 23, > 2001. We are using the July 24, 2001 for the copy of record.) The > revision is requested for the purposes of beginning waterflood in the > Western Niakuk region, not currently covered by AIO 14. > > The application is not complete. The Commission needs an updated record > of the project plans, current and future, and must provide sufficient > reservoir, completion and geologic information for evaluation of the > proposed expansion. The quantity of oil in place 310 MMBO, with the > expantion area containing 190 MMBO, emphasizes the need for the > Commission to fully evaluate the project. Our current records are > vastly out of date as to reservoir/geologic description and are > insufficient for the task at hand. > > Please review this list and let us know how long you will need to keep > the record open on this matter, in order to gather, document, and review > the submittal. At your request we will keep the record open longer in > order for you to gather the information. Please advise us as to the > date you wish for extension of the record on this matter. > > Please call me (793-1226) or Jack Hartz (793-1232) if you wish to > discuss further. > > Sincerely, > > Jane Willamson > AOGCC Petroleum Engineer > > ------------------------------------------------------------------------ > > > Name: AOGCC list of requirment AOGCC list of requirments BP Niakuk AI014.doc Type: WINWORD File (applicatio Encoding: base64 lof2 8/1/01 12:21 p~ Re: Niakuk AID . . Name: AOGCC list ofrequirments BP Niakuk AI014.doc [JAOGCC Jist ofrcquinnents BP Niakuk AI014.doe Type: WINWORD File ( application/msword) ~ ,. base64 0 2of2 8/1/01 12:21 PM . . Date: 8/1/01 Subject: Application for Revision of Niakuk Area Injection Order - Proposed Revision to Area Injection Order 14 - AOGCC Review of Completeness of the Application Following is a review for completeness by AOGCC technical Staff of the Application for Revision of Niakuk Area Injection Order #14 which you submitted to us on July 24,2001. (2 initial copies were provided received on July 23,2001. We are using the July 24,2001 for the copy of record.) The Commission needs an updated record of the reservoir, completion and geologic infonnation for Niakuk. This is required in order to evaluate the request as well as to ensure that the infonnation for the Niakuk Pool is current. This is a significant expansion of the injection area (190 MMSTB). The following are specifics that AOGCC is requesting to allow for complete technical review of the water injection expansion. We would like the application and the supporting exhibits and infonnation available in electronic fonn, as well as hard copy. General Please provide page numbers, and an overall table of contents Section A Plat and Exhibits A-la and A-2 Please review the Al014 expansion request as compared to the approved area for Conservation Order. Per the administrative approval for Conservation Order 329 (AA 329.05) from AOGCC dated January 12, 1996 (corrected March 24, 1998) the pool rule area differs from the your application in your AlO application. Please explain in your application the difference in boundaries. Why would we not want to expand the WIO to include all tracts within the C0329? Should the CO 329 be amended to add the V4 section noted above? Missing from the WIO 14 application as compared to C0329 are the following areas Tl2N RISE, Sec 16 all and Sec 21 - N/2, SE/4. Included in WIO 14, but not in the Conservation order is Tl2, RISE Sec.25 NW V4. Section E - Description of Operation AOGCC Regulation 20 AAC 25.402 (c) (4) requires a full description of the particular operation for which approval is requested. While some of the infonnation is available in the 2001 Annual Reservoir Report, Niakuk Oil Pool, the infonnation must be incorporated into the record. The description needs to provide well, facility, surveillance plans for the expansion area, and must tie in to the full reservoir plans. . Overview of Project · Discussion of wells and injectors impacted · Discuss the wells planned for injection or conversion to injection · Refer to maps with well location noted · Facilities requirements · Water Injection rates required · Additional facilities envisioned · Surveillance overview for area · Provide infonnation to relate the expansion area to the hydraulic blocks segments. · Refer to void age production and injection - maps by hydraulic units or segments · Explain the evidence for the segmenting · Reservoir pressure map · May wish to include as an exhibit the 2001 Annual Reservoir Report, Niakuk Oil Pool submitted by BP on 4/12/01 · Planned timing of injection project . . · Development plan - Longer tenn vision for development of area Reservoir evaluation of injection Section G Geoloe:ic information The following maps are required for the full Niakuk Oil Pool boundaries, provide total reservoir and by zones: 1) Net sand isopach 2) Net Porosity foot 4) Net hydrocarbon pore foot map 5) Net penneability foot map 6) Net water saturation map Note typo 2nd to last sentence in C confining interval (injection area not "Induction" Area Sections K and L Iniection Pressure and Fracture Pressure Maximum injection pressure requested is 2850 psi. Add or refer to infonnation received by the Commission (Letter dated December 12, 1994, ttom Robert Janes BP to David Johnston AOGCC, leakoff tests in NK-5 HRZ and NK-6 HRZ the fonnation ttacture pressure was estimated at .8-.9 psi/ft. Commission approved this and the application is consistent with March 22, 1995 AOGCC AlO 14. Section M - Fonnation Fluid (reword to injection water) Please look at the 2nd sentence and rephrase. Section 0 - Hydrocarbon Recovery - This section needs to provide reservoir justification for expansion of the waterflood. Hydrocarbon recovery needs to be supported with full technical backup. Our infonnation is dated (4/26/96) and does not include this expansion area. In order to evaluate the injection proposal, add Reservoir Management V oidage management to date V oidage management expectations Model Description used for the justification Input parameters (grid, rock properties, fluid properties) Need Maps of pore foot, penn, kv/kh, Sw, Net Hydrocabon Pore volume here or in other sections of the report. Case summary Water injection / production Timing/amount of injection History match of model Results of model runs Profiles production (oil, water, gas), injection volumes over time with analysis of over/under injection Cases investigated Discussion with backup Any problems with the injection such as thief zones Injection profile, concerns. Section P. Mechanical Integrity - The requirements of the following AOGCC Regulations apply: 20 AAC 25.402 (e), (t), (g), (h), (i), 20AAC25.412 And 20 AAC 25.030(d)(7) Section Q Report on Mechanical Condition of Wells Provide analysis on the mechanical condition of injectors and wells within Y4 mi radius the injectors in the expansion area, per 20 AAC 25.402 (15) #5 . . Application for Revision of Niakuk Area Injection Order 20 AAC 25.460 20 AAC 25.402 ~<8> /i' \. r'Y <\~~ .~t::- .t¡V ~ v ~q> <¿-'v cµ (;r§ ~'v (;C)~~~ dt' &~ v ~ Ò<".'b- ~ ~'1> ~rt' 'f . . SECTION A Application for Revised Area Injection Order 20 AAC 25.460 20 AAC 25.402 BP Exploration (Alaska) Inc. (BP) in its capacity as a Working Interest Owner (WIO) and the Operator of the Niakuk Participating Area within the Prudhoe Bay Unit, hereby applies for revisions to Area Injection Order No.14 to cover operations in the Niakuk and Western Niakuk Participating Areas (Exhibit A-1a). Water injection for waterflood purposes in the interval defined as the Kuparuk interval in the Niakuk Oil Pool rules, (Conservation Order 329) is the only subsurface injection operation planned within the Niakuk Injection Area. Initially, water injected into the Niakuk Oil Pool was source water from the Prudhoe Bay Seawater Treatment Plant. Currently, produced water processed at the LPC is used for injection at Niakuk. Future needs may require water from either source. This application follows the same general format and exhibit numbering as in the application for proposed injection operations in the Niakuk Injection Area. Exhibit A-1a details the area included in the updated Niakuk Injection Area. The legal description of the area included in the Niakuk Area Injection Order is listed in Exhibit A-2. Development Historv/Reservoir Back2round Niakuk targets were first drilled in the 1975 to 1985 timeframe. Development plans were formulated after NK-05 drilled in the winter of 1985 found 79' of Kuparuk sand and tested at 4800 bopd. Kuparuk development from the Niakuk Participating Area began in April 1994 upon completion of surface facilities at Heald Point. One year later, production was initiated from the Western Niakuk accumulation from ADL034626 and ADL034629. At this time, seawater injection was initiated. Niakuk was converted to produced water injection in August 2000 to increase water handling at the Lisburne Production Center. As of May 200 I, 31 wells have been drilled from two drillsites in East and Western Niakuk. 14 producers and 6 water injectors are currently active. Well spacing is nominally 80-120 acres with tighter locations that target localized accumulations separated by faults. Future development is expected to be consistent with this spacing. Niakuk wells are generally characterized by long reaches. The average departure is more than 11,000'. At one time, NK-11 was a North American record holder with a departure of 19,284', which equates to 23,885' total measured depth. The OOIP in Niakuk is estimated at 310 MMBO. Cumulative production to date is 59 MMBO. Initial reservoir pressure was roughly 4450 psi (8900' datum) and the initial temperature ranged from 171 to 182 degrees F. Niakuk oil is generally close to 25 degrees API, but has been observed to vary between 20-30 degrees API. The bubble point pressure is around 3835 psia with solution gas in the 600-7.Flbbl range (Eo is typically 1.3 RBIS! Permeability ranges from 10s to 1000s of millidarcies, with pay averaging in the 100-300 millidarcy range. Net to gross also varies from less than 20% to greater than 90% depending on location. Separate oil accumulations have been identified at Niakuk as follows. East and Western Niakuk are separated due to a complete loss of Kuparuk sand across the mid- field high. Other isolated accumulations exist in East Niakuk as evidenced by data from wells NK-18 and NK-19. Despite reasonable pressure support in the surrounding area, NK-18 has been shut in due to low pressure and high GORs. Injection of water was resumed in this area in mid July 2001. NK-19 is located in a completely separate fault block as evidenced by its unique GOe, woe, and production history. East Niakuk OOIP is estimated at roughly 120 MMBO with the majority of this oil located in Segment 2. Nominally, Segment 2 covers around 2500 acres. Relative to East Niakuk, Western Niakuk is more homogeneous. A different woe was observed between Segment 1 and Segment 3/5 and pressure communication across this fault is suspected to be very limited, except where it dies out to the far west. West Niakuk OOIP is estimated at roughly 190 MMBO with about 85 MMBO in Segment 1 and around 105 MMBO in Segment 3/5. Segments 1 and 3/5 cover approximately 3600 acres. Produced gas is currently injected into the Lisburne reservoir. . . SECTION B Plat 20 AAC 25.402(c)(1) Exhibit A-la is a plat showing the location of all wells that penetrate the injection zone within the Niakuk Injection Area as of July 1,2001. Within this area, all the specific wells that will become injectors have not been selected. Current Injectors: NK-lO, NK-15, NK17, NK-18, NK-16, NK-23, NK-38, NK-65 Proposed Injectors: NK-28 . SECTION C . Operators/Surface Owners 20 AAC 25.402(c)(2) Niakuk working interest ownership for both PAs is as follows: ExxonMobil (35.82283%) Phillips Alaska, Inc. (36.49270%) BP Exploration (26.66467%) Mobil Alaska E&P (0.99980%) Forest Oil (0.02000%) The surface owners and operators within a one-quarter mile radius of the Niakuk Injection Area are: As shown on Exhibit C-1: Surface Owners/Operators State of Alaska Department of Natural Resources Attn: M. D. Kotowski P.O. Box 107034 Anchorage, AK 99510 BP Attn: Anne L. Shaw P.O. Box 196612 Anchorage, AK 99519-6612 Native Allotment Parcel B Owners Mr. Leroy Oenga P.O. box 201 Barrow, AK 99723 Mr. Michael M Delia 1228 28th Avenue Fairbanks AK 99701 Ms. Georgene Shugluk P.O. Box 1621 Atqasuk, AK 99791 Mr. Wallace Oenga P.O. Box 1128 Barrow, AK 99723 BIA / Heirs of Jenny Oenga c/o Inupiat Community of the Arctic Slope 4495 Northstar Street Barrow, AK 99723 . SECTION D . Affidavit 20 AAC 25.402(c)(3) Exhibit D-l is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of any proposed injection well in the Niakuk Injection Area have been notified and provided a copy of the application. . SECTION E . Description of Operation 20 AAC 25.402(c)(4) This application encompasses the injection of Class II fluids in connection with an Enhanced Oil Recovery (EOR) operation. Subsection I Enhanced Recovery Water injection is the only enhanced recovery injection planned within the Niakuk Injection Area. Water injection began in 1995 utilizing water from the Prudhoe Bay Seawater Treatment Plant. Niakuk injection was switched to produced water in August 2000. A miscible gas WAG process may be evaluated for the future. Well Spacin2 Well spacing is nominally 80-120 acres with tighter locations that target localized accumulations separated by faults. Future development is expected to be consistent with this spacing although40 acre spacing may be required in some areas of the field. Well Counts As of May 2001, 31 wells have been drilled from two drill sites in East and Western Niakuk. 14 producers and 6 water injectors are currently active. Final count will be dependent upon production and reservoir performance data. . SECTION F . Pool information 20 AAC 2S.402(c)(S) The Niakuk Injection Area includes the Niakuk Oil Pool in the Kuparuk Formation. The Kuparuk is defined in the pool rules as the stratum that is common to and correlates with the accumulation found in the Niakuk 6 well between the depths of 9,351' and 9,842' subsea (SS) [12,318' and 12,942' measured depth (MD)]. . SECTION G . Geologic Information 20 AAC 25.402(c)(6) A. Injection Interval Stratigraphy The geologic framework of the Niakuk Field is set up by deposition of the Kuparuk River formation SS which was deposited downthrown to the Niakuk Field fault in a large accommodation space north of the ancestral Brooks Range. The NK-29 well log (Figure 1) shows the typical Kuparuk sandstone with all stratigraphic zones (1-4) represented. The major stratigraphic features characterizing the Kuparuk are thick aggredational sands commonly divided by a mid Kuparuk Sequence boundary (Zones 2/3) then capped by an erosional - reworked lower quality zone 4 facies. B. Structure/Cross sections The structure surface on top of the Kuparuk sandstone is shown in Figure 2. The field is a large 3-way NE dipping structure with a crest of -8800 feet in the SW and a low of -9800 feet in the NE. The surface hole locations (SHL's) for all the wells are Heald Point and the Lisburne L-5 pad. A red dashed line highlights the proposed Niakuk Area Injection boundary. Black stars identify current injectors while red stars show proposed injectors. Two S -7 N and one W -7 E structural cross section lines are highlighted on the map and displayed in Figures 3, 4, and 5. Figure 3 is a W -7 E structural cross section through the field showing the maximum thickness of 800 feet in the west, the eroded central region near the paleo high, and the accommodation space to the east. Two separate and distinct OWC's are present in the field, -9240 in the West, and -9535 in the East. Figure 4 is as -7 N cross section through the Western Niakuk field area. Different OWC's exist (-9240 ft. & -9285 ft.) here as a result of complex stratigraphy rather than a major structural factor. Figure 5 is a S -7 N cross section through the Eastern Niakuk field area. A common OWC of -9535 is observed in the eastern field area. C. Confining Interval The producing Kuparuk River Sandstone is bounded below by the Jurassic age Kingak Formation over virtually the entire Niakuk Injection Area. The contact is defined by a change in lithology and electric log character. The Kingak Formation is a highly impermeable, low resistivity (2 - 3 ohm-meters) shale with a thickness varying from 400 to 800 ft. TVD. The overlying Kuparuk Formation (producing interval) is characterized by siltstones and sandstones of much higher quality and higher resistivity (6 - 70 ohm-meters). In the extreme SE comer of the Injection Area, the Kingak Formation has been interpreted as absent on seismic in a 350 ft. (EW) x 2100 ft. (NS) area. In this small area, located in the extreme SE 14 of section 28 Tl2N, RI6E, confinement of injected fluids will be provided by Lower Kuparuk siltstones and shales as encountered in the NK-23 well. The Kuparuk Formation is overlain by the Lower Cretaceous age Highly Radioactive Zone (HRZ) interval over the entire Induction Area. It is comprised of a 200 ft. thick, black, organic rich shale exhibiting high radioactivity as measured by the gamma ray logs, typically greater than 150 API units. D. Flow Properties . . Water injection patterns in Niakuk are reviewed as production and surveillance data is gathered. Wide perforation intervals spanning most of the stratigraphic zones suggest water injection is being accomplished over a large interval of the reservoir. Production rates and static pressures from producing wells similarly suggest that effective injection sweep is being realized over all communicative zones. Figure 6 is a representative structural cross section in West Niakuk showing the stratigraphic zones from a structural prospective. These stratigraphic zones may be influencing water movement in the reservoir. . . SECTION H Well Logs 20 AAC 25.402(c)(7) All openhole logs from Niakuk wells are sent to the Commission as the wells are completed. Figure 1 [NK-29] is the type log for the Niakuk Injection Area with stratigraphic and marker horizons annotated. . . SECTION I Casing Information 20 AAC 25A02(c)(8) 20 AAC 25.252(c)(6) Currently, 8-10 water injectors are planned for Niakuk. Tubing sizes in the Niakuk field will vary from 3 1/2 to 5 1/2 inches. In general, the production casing will be sized to the tubing in the Niakuk wells. Typical development wells will utilize either a "conventional," or "slimhole," design similar to Kuparuk and Prudhoe Bay. The "conventional" design wells will utilize 13 3/8-inch surface casing, 9 5/8-inch production, or intermediate casing with a 7-inch liner for the high stepout wells. The "slimhole" design wells requiring 4 ll2-inch tubing will utilize 10 3/4-inch surface casing, 7 5/8-inch production, or intermediate casing with a 5 ll2-inch liner for high stepout wells. The Niakuk wells initially designated as water injection wells will be completed with L-80 grade steel. The injection wells planned for pre-production may utilize corrosion-resistant material where applicable. NK-18, which was completed with chrome, has recently been converted into an injector. Most Niakuk water injection completions are currently envisioned as single zone, single string with a single packer. Where potentially advantageous, isolation packers may be run between intervals. Exhibits I-I and 1-2 show typical wellbore schematics for the two basic completion designs. Exhibit 1-3 shows the most recent sidetrack (NK-12B) schematic completion. As shown in the schematics, gas lift mandrels with dummy valves have been run to provide flexibility in artificial lift, which will enhance production in the injection wells planned for pre- production. Sufficient mandrels will be run to provide flexibility for well production and gas lift supply pressure. The actual casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. Further, all drilling and production operations will follow approved operating practices in reference to the presence ofH2S in accordance with 20 AAC 25.065 (a), (b), and (c). . SECTION J . Injection Fluid 20 AAC 25.402(c)(9) 20 AAC 25.252(c)(7) Two types of injection fluid will be utilized in the Niakuk Injection area: Source water and Produced water. Source water will be obtained from the Beaufort Sea and is the same water that is currently being injected into the Ivishak Formation in the IP A, and into the Pt. McIntyre Participating Area. Produced water is water that is produced with Lisburne, Pt. McIntyre, West Beach, North Prudhoe Bay State and Niakuk oil and separated from the oil and gas at the LPC. Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. A. Source Water . I) Analysis of Composition of Typical Fluid - Exhibit 1-1 is a listing of the composition of the Beaufort Sea source water. 2) Estimated Maximum Amount to be Iniected Daily - Niakuk - The current well configuration calls for roughly 60,000 BWPD. Future development could raise this requirement to roughly 70,000 BWPD. 3) Compatibility with Formation and Confining Zone - SEM, XRD and ERD analyses conducted on Niakuk core indicate very low clay content in reservoir intervals (see Exhibit 1-2). As a result no significant problems with formation plugging or clay swelling is expected due to fluid incompatibilities. B. Produced Water 1) Analysis of Composition of Typical Fluid - See Exhibits 1-3, 1-4, and 1-5, respectively, for the compositions of Niakuk, Lisburne, and Pt. McIntyre formation water. 2) Estimated Maximum Amount to be Iniected Daily- Niakuk - The current well configuration calls for roughly 60,000 BWPD. Future development could raise this requirement to roughly 70,000 BWPD:. 3) Compatibility with Formation and Confining Zone - The produced water returning to the Niakuk formation will be a mix ofPt. McIntyre, West Beach, North Prudhoe Bay, Lisburne and Niakuk produced water separated through the LPC. The current development programs for these fields indicates the majority of the produced water will come from Pt. McIntyre (current maximum estimated at 250 MBWPD) with minimal amounts COming. West Beach (current maximum estÜld at 50 MBWPD), Lisburne (current maximum estimated at 20 MBWPD), and Niakuk (current maximum estimated at 50 MBWPD). Since the origin of a vast percentage of the produced water will be the Kuparuk formation, minimal problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. . . SECTION K Injection Pressure 20 AAC 25.402(c)(10) 20 AAC 25252(c)(8) The estimated maximum and average injection pressures anticipated for Niakuk wells are listed in the following table: Type Well Estimated Maximum Injection Pressure (Psig) Estimated Average Injection Pressure (Psig) Niakuk Water Injection 2,850 2,450 Pressure represents - Well Head Injection Pressure (WHIP) . . SECTION L Fracture information 20 AAC 25.402(c)(1l) The estimated maximum injection pressures for enhanced recovery wells will not initiate or propagate fractures through the confining strata, which might enable the injection or formation fluid to enter freshwater strata. There are no freshwater strata in the area of issue (see Section N). Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Injection in the Kuparuk above fracture parting pressure may be necessary to allow for additional recovery of oil. In no instance would such injection pressures breach the integrity of the confining zone. The Kuparuk Formation is overlain by the HRZ shale. The HRZ is a thick shale sequence, which would tend to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. Fracture data from the Kuparuk intervals of the Pt. Mclntyre and West Beach Pools indicate a fracture gradient of between 0.60 and 0.63 psi/ft in current virgin reservoir conditions. Fracture data from Pt. Mclntyre No.9 gave a fracture gradient of 0.624 psi/ft, while data from West Beach No.4 indicated a fracture gradient of 0.602 psi/ft. While no fracture gradient has been obtained in the Kuparuk interval at Niakuk, it is expected that the fracture gradient will be similar since it is Kuparuk rock with similar character. Prudhoe field data also indicates that sandstone fracture gradients may be reduced during waterflooding operations due to reduced in-situ stress associated with the injection of colder water. Declining reservoir pressure can also reduce formation stresses, thereby reducing the fracture gradient. The Niakuk Pool will be produced for a minimum time prior to the start-up of waterflood operations allowing the reservoir pressure to decline somewhat. However, once waterflood operations are initiated, field average pressures will be managed to mitigate fluid migration and sustain reservoir energy. . . SECTION M Formation Fluid 20 AAC 25.402(c)(12) An analysis of formation water samples obtained from Kuparuk sandstone indicates that Total Dissolved Solids are 25,700 ppm. Wireline log TDS calculations indicate a lack of fresh water (NaCl equivalents of greater than 10,000 ppm), with the average resitivity. The method used in these calculations is described in Exhibit M-1. . . SECTION N Aquifer Exemption 20 AAC 25.402(c)(13) The lack of fresh water and underground sources of drinking water in the Niakuk Injection Area eliminates the need for an aquifer exemption. The presence of hydrocarbons, either live or as residual, causes the Kuparuk Formation of the Niakuk Injection area to be unsuitable as a source of drinking water. In addition, Kuparuk Formation water analysis indicates 25,000 ppm total dissolved solids (TDS). Calculation of TDS from wireline logs indicates NaCl equivalents of greater than 10,000 ppm in the formations above the Kuparuk Formation (see Section M and Exhibit M-l). Therefore, no aquifer exemption is requested nor needed. . SECTION 0 . Hydrocarbon Recovery 20 AAC 25.402(c) 14 Simulation studies in the early 1990s indicated benefit from waterflooding at Niakuk. The primary recovery factor was estimated at 4%, whereas waterflooding was expected to achieve 40%. The model used to create these initial estimates was smaller and simpler than what is available today. A more recent review of these mechanisms supports the same conclusion, although in varying degrees. For Western Niakuk, given the current well configuration, simulation suggests a primary recovery factor of around 13%, with waterflooding upwards of 37%. In East Niakuk, the benefits due to waterflooding are less pronounced due to higher degrees of complexity and reservoir heterogeneity. Expansion of the Area Injection Order is proposed so NK-28 can be converted to water injection. This well will support the newly drilled well NK-08A. Segment 3/5 should at least one additional injector to balance voidage. This conversion also should help improve areal sweep by establishing more of a peripheral flood. In addition to injecting at NK-28, NK-17 is expected to start injection in the summer of 2001 and NK-12B has been identified as a future conversion candidate. 'f SECTION P . . Mechanical Integrity 20 AAC 25.402(d) & (e) In drilling Niakuk injection wells, the casing is pressure tested in accordance with 20 AAC 25.030(g). When a producing well is converted to injection, the casing pressure test will be repeated in accordance with 20 AAC 25.412(c). Injection well tubing/casing annulus pressures will be monitored and recorded on a regular basis. BP as the operator of the Niakuk oil pool, will be responsible for mechanical integrity of injection wells and for ensuring compliance with monitoring and reporting requirements. The tubing/casing annulus pressure of each injection well is checked weekly as a routine duty to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70 percent of the casings minimum yield strength. If an injection well is deemed to have anomalous annulus pressure, it will be investigated for tubing/annulus communication using a variety of diagnostic techniques and a mechanical integrity test. If a subsequent investigation proves hydraulic communication between the tubing/casing exists, then a plan for remedial action will be formulated and scheduled. In addition, a variance will be obtained from the AOGCC to continue safe operations, if technically feasible, until the remedial solution is implemented. BP will also maintain annular pressure data in the Injection Well Database and will provide copies with future monthly Injection Reports (Form 10-406) to provide annular pressures, diagnostic comments, and scheduled remedial action. Tubing/casing pressure variations between consecutive observations need not be reported to the Commission. A schedule must be developed and coordinated with the Commission which ensures that the casing/annulus for each injection well is pressure tested prior to initiating injection and at least every four years thereafter. A test surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% over the casing's minimum yield strength. The test pressure must be held for 30 minutes with no more than a 10 percent decline. The Commission must be notified at least 24 hours in advance to enable a representative to witness the pressure test. Alternate EPS approved methods may also be used, with Commission approval; including but not necessarily limited to timed-run radioactive tracer surveys (RTS), oxygen activation logs (OAL), temperature logs (TL), and noise logs (NL). An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. . SECTION Q . Wells Within Area Report on Mechanical Condition of Wells 20 AAC 25.402(h) 20 AAC 25.252(h) To the best of BP's knowledge, the wells within the Niakuk and Western Niakuk Participating Areas were constructed, and where applicable, have been abandoned to prevent the movement of fluids into freshwater sources. Exhibit A-Ia: Exhibit A - 2: Exhibit C-I: Exhibit D-I : Figure 1: Figure 2: Figure 3: Figure 4: Figure 5: Figure 6: Exhibit 1-1: Exhibit 1-2: Exhibit 1-3: Exhibit J -1 : Exhibit J-2: Exhibit J-3: Exhibit J-4: Exhibit J-5: Exhibit M -1 : Pressure Data . '. List of Exhibits Location of updated Niakuk Injection Area Legal Description of Niakuk Injection Area Niakuk Injection Area Surface Ownership Affidavit Niakuk 29 Type Log Kuparuk Structure Map West to East Structural Cross Section South to North Structural Cross Section South to North Structural Cross Section West Niakuk - Representative Structural Cross Section Typical Niakuk Well Schematic Slimhole 4.5-inch Tubing Typical Niakuk Well Schematic 4.5/5.5-inch Tubing Typical Niakuk Well Schematic for Sidetrack with 4.5-inch liner and tubing Beaufort Seawater Composition Niakuk Clay Content Niakuk Produced Water Composition Lisburne Produced Water Composition Pt. McIntyre Produced Water Composition Documentation of Water Salinity Calculations From Well Logs Production Plot Segment 1 Production Plot Segment 2 Production Plot Segment 3/5 PROPOSED NIAKUK INJECTION AREA EXPANSION A-1a 10 Scale 1 :48,000 2IJOO 1000 IJ 16 Feet ProjecIion: ASP4 IlIAD 1927 18 21 o 15 Working Interest in NiaIruk looses: Phillips Alaska 1m.: 36.<W27O% Exxon 35.822B3'Ji, BP 26.66461'!(, Mobil 0.99900% Forest 0.02000% 22 so.œ o 28 GULL ISlAND ..'-" ·_~·_··-'~.-~m···_·_···_~.____nm. T12N T11N o 33 NIAKUK ISlANDS ~35 33 HK-25 o I 34 1.5-21 BPXA Cartography/7-11- . . EXHIBIT A-2 Legal Description of Niakuk Injection Area TI2N, RISE UM Sections 13, 14, 15,22,23,24,25,26, and 27 Section 36: NI2 TI2N, R16E UM Sections 28, 29, 30 Sections 31: NI2 and 32: N/2 OWNERSHIP - IN 50 EXXMOB 501. BPI. 1001. ATOFINA 501. AREA . . Exhibit D-l AFFIDA VIT REGARDING NOTICE TO SURFACE OWNERS IN THE VICINITY OF THE PROPOSED INJECTION WELLS Anne L. Shaw, on oath, deposes and says: 1. I am a Team Leader at BP Exploration (Alaska), Inc., the Operator of the Niakuk Participating Area and Western Niakuk Participating Area within the updated Niakuk Injection Area, Prudhoe Bay Unit; 2. On July 232001, I caused copies of the application for the updated Area Injection Order to be provided to the Surface Owners of all land within a quarter mile of all proposed injection wells within the Niakuk Injection Area as listed below: State of Alaska Department of Natural Resources Attn: M. D. Kotowski P.O. Box 107034 Anchorage, AK 99510 BP Anne L. Shaw P.O. Box 196612 Anchorage, AK 99519-6612 Native Allotment Parcel B Owners Mr. Leroy Oenga P.O. box 201 Barrow, Ak 99723 Mr. Michael M Delia P.O. Box 201 Barrow, AK 99723 Ms. Georgene Shug1uk P.O. Box 91003 Atqasuk, AK 99791 Mr. Wallace Oenga P.O. Box 201 Barrow, AK 99723 Ms. Jenny Oenga c/o 309 Paystreak. Fairbanks, AK 99712 \. STATE OF ALASKA ) ) ) ss. THIRD JUDICIAL DISTRICT SUBSCRIBED AND SWORN to before me this 23 day of July, 200l. //1 ond;;v ~ ( ~ NOTARY PUBLIC IN AND FOR ALASKA ----------.-- . Notay PUbI"lC MONITA J. OUVE State of Alaska My Commission E;cpires t.NJy 7. 2003 þ þ My Commission Expires: ý17~ ~ J-ùó3 þ Figure 1 1 est ~~ ~~I~ Xál!- ·I~n~ Yi[l4~~$ ~ ~...... 9 -- ~ r:: ~ /!IiIIoro C'I: S ~ C'I: Figure 2 . I - To uparuk tr cture p -9800 32 33 ., 5 Sp %p.)W~~~ .... Figure 3 iakuk... Top -7 Base Kuparuk Structural Cross Section W-E Structural Well Cross-Section through Niakuk and Western Niakuk Reservoirs ~~ &~ I : 8900 I 9000 I I 9100 I I 9200 I I 9300 I I 9400 I I 9500 I I 9600 I I 9700 : 9800 I 9900 10000 0' I .....~- -890 N 22 -900 -910 -920 -930 ... ................... Seg owe -9535 -960 lOW l' iakuk... Top -7 Base Figure 4 uparuk Structural Cross Section South ~-- I I 8900 I I I 9000 I ¡ 9100 I I 9200 I I I 9300 I : 9400 I I 9500 I I I 9600 I : 9700 I I ¡ D!3TANi2i»l m:c'tIDJ;¡- S- N Structural Wen Cross-Section through Western Niakuk Reservoir North --- --- ----------- - - ----- NK -14 Seg 1, 3/5 owe .0185 2.2 Miles 0' . 2223' """ 6173' .,'" 4513' "~iI' 8898' .... 11742' -- 11742 7 Figure 5 iakuk- op -7 Base uparuk Structural Cross Section SW-NE Structural Well Cross-Section through Niakuk Reservoir Southwest Northeast - ----- - -- -- -- - -- ----- 9100 NK-38 9200 920 9300 930 940 9500 -950 11.11I II. 9600 9700 9800 8 West Niakuk -- Representative Structural Cross Section West Stratigraphic Zonation -- Highlights Possible Flow Pathways East - - --- - -- 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 ----- -- -- -------^ Gun # 3 ... .IBIT 1-1 TYPICAL SLlMHOLE WELL SceATIC TREE: 4-1/16", 5M. CIW WELlHEAD: 13-518", 5M, FMC AClUA TOR: BAKER :¡:¡¡II¡¡i:j¡: 10-3/4". 45.5#1ft, NT-BO, BTC. :~~itiii~iit~i~~f: 4-1/2" lUBING DATE PBm 7-518". 29.7#11t, NT -80, NSCC. REV. BY COMMENTS " '" " '" '" '" '" / / / / / / / '" '" " " " " " KB. ElEV = BF. ElEV = 4-1/2" OTIS CP-2 TRSSV (3.81" 10) GASlIFT MANDRElS "X" NIPPLE PACKER "X" NIPPLE "X" NIPPLE WLEG NIAKUK WELL: API NO: SEC : TN ; RGE BP Exploration (Alaska) TREE: 7 1 W WElLHEAD: 135 C ACTUATOR: Baker 13-318·. 72 #111, L-80, BTRS 5 1fZ' TUBING OR 4-11Z' TUBING TOP OF r LINER 9-518·, 47#/11, L-80. NSCC r . 29 #/11, L-80, NSCC DATE REV. BY PBTD t4 III uK:> III I Uull~~J ® A ... ~¡.i:~:·~j·jl·:!:·:::·~:l I :8 :8 - ~ ~ I ~ . I - Å ... - .",/"'/..."..../ - ,~,~'.I'./' COMMENTS ELEV c . ELEV c ( Otis Model 10 TRSV) ( 4.562 . 10) GAS LIFT MANDRELS ·SWS· NIPPLE PACKER ·SWS· NIPPLE 'XN" NIPPLE TBG TAIL MARKER JOINT R t(.t\\t~ G \<3<3~ ~ 0 \! '\ COmm\SS\O . G~S COt\S. I" Q\\ & , ~ t>..\'Q,St'-'3. I\t\C\\OÍ<-·' NIAKUK WELL: API NO: SEC : TN :RGE BP Exploration (Alaska) I-3 T '( 1'( c.A L <; /1)£ TR/KJ<. :;"<:'//6# I1TI L TREE = WElL HEA D= ACTUATOR= KB. 8...EV = BF. 8...EV = KOP= Max Angle - Datum MD - Datum TVDss- 4-1/16" 5M CIW 13-5/8" 5M FMC BAKER C 51.88' NK-128 1300' 79 @ 13722' 13800' 8800' 10-3/4" CSG, 45.5#, NT-80S BTC, ID = 9.950" Minimum 10 = 3.725" @ 10843' 4-1/2" HES XN NIPPLE 14-1/2" TBG, 12.6#, L-80 IBT-M, ID = 3.958" I 10855' ~ORA~ONSUMMARY REF LOG: TCP ~ ANGLE AT TOPÆRF: 62 Note: Refer to Production DB for historical perf data SIZE SPF INTERV AL Opn/Sqz DA TE 2-7/8" 6 16175 -16195 0 05/12/01 2-1/2" 6 16330 - 16390 0 03/15/01 17-5/8" CSG, 29.7#. NT 95 HS, NSCC, ID = 6.875" I 2023' -14-112" HES CP-2 TRSSSV NIP, ID = 3.938" . ST MD 3 3239 2 7098 1 10711 GAS LIFT MANDRElS DEV TYÆ VLV LATCH 40 KBG-2LS DOME INTG 59 KBG-2LS DOME INTG 59 KBG-2LS SO INTG DATE 03/25/01 03/25/01 03/25/01 TVD 3037 5471 7249 SIZE 1.0" 1.0" 1.0" 10778' -14-112" HES X NIP, ID - 3.813" 10799' -17-5/8" X 4-1/2" BAKER S-3 A<R, ID = 3.850" 10822' -14-1/2"HESXNIP,ID=3.813" I 10843' -14-112" HES XN NIP, ID - 3.725" I -17-5/8" X 4-112" BAKER ZXP A<R, ID = 4.938" -1 BAKER 7" X 5" HMC LNR HANGER, ID = 4.938" 18...MD - TT NOT LOGGED I -1 TOP OF BAKER WHIPSTOCK EZSV BRIDGE PLUG ~ 16453' I 14-1/2" LNR, 12.6#, L-80 HYD 521, .0152 bpf, ID = 3.958" I DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BA Y UNIT ORIGINAL COMPLETION W8...L: NK-12B 03/19/01 CHIKA K RIG SIDETRACK ÆRMIT No: 201-015 05/08/01 pcr UPDA TED API No: 50-029-23414-02 05/12/01 ATD/tlh ADD ÆRFS SEC 36; T12N; R15E 1327' FSL 996' FEl 06/26/01 JLGltlh SET CIBP BP Exploration (Alaska) . . Exhibit J-l Beaufort Sea Source Water Analysis Determination Summer Winter Un i ts Specific Gravity 1.013 1.024 Mg/L pH 7.5 7.8 Mg/L Calcium 196.0 365.0 Mg/L Magnesium 631.0 1190.0 Mg/L Sodium & Potassium 5680.0 10400.0 Mg/L Strontium 0.0 0.0 Mg/L Barium 0.0 0.0 Mg/L Iron 0.0 0.0 Mg/L Bicarbonate 85.0 142.0 Mg/L Carbon Dioxide Calc. 0.0 0.0 Mg/L Total Dissolved Solids 17852.0 32787.0 Mg/L Chloride 9880.0 18200.0 Mg/L Sulfate 1380.0 2490.0 Mg/L Resistivity @ 70°F 0.422 0.255 Ohms Suspended Solids 6.0 1.0 Mg/L . . Exhibit J-2 Clay Content in Niakuk Reservoir Zones Zone! Well Sam led Zone 3 (NK #1A) Zone 0 (NK #5) Zone E (NK #6) Zone F NK #6 Cia Content· 0-1 % kaolinite, 1-2% illite trace to 1% illite, trace kaolinite &!or chlorite trace only of illite trace 01'11 of kaolinite, trace 01'11 of illite · Based on Scanning Electron Microscopy, X-ray diffraction, and Energy Dispursive X-ray Spectroscopy . . Exhibit 1-3 Niakuk Produced Water Analysis Determination Value Units pH 7.0 Mg/L Calcium 95.0 Mg/L Magnesium 22.0 Mg/L Sodium , 9925.0 Mg/L Potassium 147.0 Mg/L Strontium 16.0 Mg/L Barium 1.7 Mg/L Iron 5.2 Mg/L Bicarbonate 3870.0 Mg/L Chloride 11440.0 Mg/L Sulfate 190.0 Mg/L Total Dissolved Solids 25711.9 Mg/L ,It.\) t.~~\~ R \<j<jf\ ,. \ \3 'si\O~ ,,' () '{ ~Q~~~ \' ~o~s. 0\ ~ G3.S£ \1'3. ()\\ ~"O\<.-.j 1»"3."'''' [\~ . Exhibit J-4 . Lisburne Produced Water Analysis Determination Value Units pH 8.5 Mg/L Calcium 105.0 Mg/L Magnesium 50.0 Mg/L Sodium (calc) 10555.0 Mg/L Sodium (AA) 13875.0 Mg/L Strontium 3.8 Mg/L Barium 1.1 Mg/L Iron 1.1 Mg/L Hydroxyl 0.0 Mg/L Carbonate 228.0 Mg/L Bicarbonate 2618.0 Mg/L Chloride 14261.0 Mg/L Sulfate 750.0 Mg/L Total Dissolved Solids 28753.0 Mg/L ~ . . Exhibit J-5 Pt. McIntyre Produced Water Analysis Determination Value Units pH 7.2 Mg/L Calcium 24.0 Mg/L Magnesium 9.0 Mg/L Sodium 8540.0 Mg/L Potassium 179.0 Mg/L Strontium 7.0 Mg/L Barium 11.0 Mg/L Iron 1.4 Mg/L Hydroxyl 0.0 Mg/L Carbonate 0.0 Mg/L Bicarbonate 3262.0 Mg/L Resistivity @ 68°P 0.4 Ohms l~hlOride 10597.0 Mg/L Silicon 24.0 M g/L . . Exhibit M-l Documentation of Water Salinity Calculations from Well Logs - Four wells, NK-l, NK-3, NK-6 and SD-8, wère selected for the calculation as spatially representative of the Niakuk Injection Area and having wireline logs up-section and through the Kuparuk Formation. The steps in the calculation were: 1) Formation Temperature: Tfm = 0.0222 (Depth fm - Depth base of permafrost) + 32 deg. F 2) Porosity from Sonic Log: 0.625 * (dt-55) Phi = --------------------------- dt 3) Apparent Formation Water Resistivity (m and a from Humble equation): phi**m * Rt R wa = ------------------------- a 4) Water Resistivity @ 75 deg. (Schlumberger): Rwa * Tfm + 6.77 R w @7 5 = ---------------------------- 81.77 5) Total Dissolved Solids in NaCI Equivalents (Dresser Atlas): (3.562 - loglO (Rw@75 - 0.0123)) TDS = 10** ----------------------------------------------------- 0.955 . Niakuk Static Pressure Summary Well Name (continued) Datum Datum Well Date Pressure TVDSS Name Date Datum Datum Pressure TVDSS NK-07 9/20/1994 4311 9200 NK-07 1/1 5/1998 3962 9200 NK-07 11/4/1999 4277 9200 NK-07 1 0/9/2000 4536 9200 NK-07A 6/11/2001 4141 9200 NK-08 9/20/1994 4276 9200 NK-08 4/20/1995 4087 9200 NK-08 11/5/1995 4099 9200 NK-08 8/5/1996 4151 9200 NK-08 1/14/1998 4027 9200 NK-08 11/25/1999 4363 9200 NK-08A 4/23/2001 3811 9200 NK-09 3/27/1995 4386 9200 NK-09 2/7/1996 4189 9200 NK-09 4/30/1997 3935 9200 NK-10 7/8/1994 4297 9200 NK-10 1/15/1995 4202 9200 NK-10i 7/8/1994 4297 9200 NK-10i 1 /1 5/1 995 4202 9200 NK-12A 3/14/1994 4506 9200 NK-12A 7/8/1994 4267 9200 NK-12A 1 0/22/1994 4189 9200 NK-12A 12/28/1994 4162 9200 NK-12A 9/4/1997 4643 9200 NK-12A 1 0/15/1997 4641 9200 NK-12A 11/4/1999 4715 9200 NK-12B 4/12/2001 2456 9200 NK-12B 6/30/2001 2061 9200 NK-13 11/22/1997 4091 9200 NK-13 11m1999 4162 9200 NK-13 3/26/2001 4243 9200 NK-14 9/29/1998 3950 9200 NK-14 6/26/2000 4060 9200 NK-17 3/21/1997 4404 9200 NK-17 12/6/1998 4875 9200 NK-17 11/6/1 999 4963 9200 NK-17 10/8/2000 5004 9200 NK-17i 3/21/1997 4404 9200 NK-17i 12/6/1998 4875 9200 NK-17i 11/6/1 999 4,963 9200 NK-17i 10/8/2000 5004 9200 NK-18 3/13/1994 4561 9200 NK-18 7/15/1994 3890 9200 NK-18 7/23/1994 3,917 9200 NK-18 8/14/1994 3993 9200 NK-18 11/29/1994 3,892 9200 NK-18 3/18/1995 3978 9200 NK-18 5/8/1996 3331 9200 NK-18 10m1996 3232 9200 NK-18 1/15/1997 3406 9200 NK-18 11/6/1999 1 815 9200 NK-18 3/9/2000 1959 9200 NK-18 3/27/2001 2554 9200 NK-19 12/2/1995 3390 9200 NK-19 2/7/1996 3407 9200 NK-19 1/16/1997 3051 9200 NK-19 8/16/1997 2.192 9200 NK-19 7/31/1998 1642 9200 NK-19 11/5/1999 1563 9200 NK-19 10m2000 1572 9200 NK-20 4/9/1994 4.547 9200 NK-20 6/11/1994 3.582 9200 NK-20 6/22/1994 3.780 9200 NK-20 8/14/1994 3832 9200 NK-20 10/22/1994 3.757 9200 NK-20 12/27/1994 4.062 9200 NK-20 3/10/1995 3.492 9200 NK-20 9/17/1995 3.982 9200 NK-20 1/13/1996 4588 9200 NK-20 5/8/1996 3.642 9200 NK-20 12/1/1996 4.149 9200 NK-20 1/15/1997 4.428 9200 NK-20 1/16/1998 2968 9200 NK-20 1/24/1998 3.153 9200 NK-20 5/12/1998 2616 9200 NK-20 5/12/2000 2.616 9200 NK-20 3/8/2001 3012 9200 NK-20 3/30/2001 2.783 9264 NK-21 5/13/1994 3979 9200 NK-21 8/13/1994 3979 9200 NK-21 8/23/1994 4164 9200 NK-21 10/21/1994 4376 9200 NK-21 1/1/1995 4151 9200 NK-21 3/30/1995 2533 9200 NK-21 9/17/1995 4909 9200 NK-21 3/29/1998 5.451 9200 NK-21 11/20/1996 4661 9200 NK-21 1/1/1998 4724 9200 NK-21 10/3/1998 3220 9200 NK-21 12/6/1998 2,872 9200 NK-21 12/22/2000 2613 9200 NK-22 8/23/1994 4.164 9200 . ( continued) Well Name Datum Datum Date Pressure TVDSS NK-22 10/21/1994 4.082 9200 NK-22 12/2/1995 4.466 9200 NK-22 4/24/1996 4.706 9200 NK-22 3/6/1997 4.746 9200 NK-22 7/31/1998 4,747 9200 NK-22 5/18/2000 4,570 9200 NK-23 6/22/1994 4,355 9200 NK-23 12/1 /1994 4,020 9200 NK-23 1/15/1995 3981 9200 NK-23 3/30/1995 3,764 9200 NK-23 6/10/1996 4499 9200 NK-23i 6/22/1994 4,355 9200 NK-23i 12/1/1994 4020 9200 NK-23i 1/12/1995 3,981 9200 NK-23i 3/30/1995 3764 9200 NK-23i 6/10/1996 4.499 9200 NK-27 8/16/1995 4,026 9200 NK-27 3/4/1997 3,866 9200 NK-27 6/22/1998 3890 9200 NK-27 11/15/1999 4007 9200 NK-27 10/10/2000 4290 9200 NK-28 8m1996 4,024 9200 NK-28 5/25/1997 3987 9200 NK-28 2/7/1998 3892 9200 NK-28 9/9/1999 3875 9200 NK-29 3/11/1997 3928 9200 NK-29 8/16/1997 3895 9200 NK-29 2/6/1998 3947 9200 NK-29 10/4/1998 3826 9200 NK-34 7/23/1998 3830 9200 NK-38 8/15/1995 4468 9200 NK-38 6/10/1996 4601 9200 NK-38i 8/15/1995 4468 9200 NK-38i 6/10/1996 4601 9200 NK-38i 5/25/1998 4759 9200 NK-42 12/4/1994 4327 9200 NK-42 3/17/1995 4239 9200 NK-42 4/24/1996 4,534 9200 NK-42 1/24/1998 4318 9200 NK-42 5/18/2000 4,526 9200 NK-43 6/12/2001 3467 9200 NK-61 12/3/1999 3,940 9200 NK-61 1/2/2001 3331 9200 NK-62 5/31/2000 3,540 9200 NK-65i 5/1/1998 4.175 9200 ........ o 8000 7000 6000 5000 ....... 4000 3000 2000 1000 0 2 40000 35000 30000 25000 20000 5000 0000 5000 0 Jan-OO Jan-9g ,Jan-96 Jan-95 8000 7000 6000 5000 ~- 4000 3000 2000 1000 0 40000 35000 Jan-94 30000 o Jan-9] 25000 20000 5000 0000 5000 #4 STATE OF ALASKA ADVERTISING ORDER a NOTICE TO PUBLISHER . I MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDE <oj., CERTIFIED AFFI .~VIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-0211426 F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AI<. 99501 M AGENCY CONTACT DATE OF A.O. lod Colombie PHONE Ma 24 2001 PCN ~ Anchorage Daily News POBox 149001 Anchorage, AI<. 99514 mE MATERIAL BETWEEN TIlE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON TIlE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement ¿$J Legal o Display o Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING NOTICE DATE 2 ARD 3 4 02910 FIN AMOUNT sy CC PGM LC ACCT FY NMR DrST LID 01 02140100 73540 2 3 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM . . AMENDED Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Prudhoe Bay Field, Niakuk Oil Pool - Revision to the affected area of Area Injection Order No. 14 BP Exploration (Alaska) Inc. by letter dated March 26. 2001, has requested that the Alaska Oil and Gas Conservation Commission expand the affected area for Area Injection Order No. 14 (AIOI4) to include a portion of the western extent of the Niakuk Oil Pool. The expansion will consist of sections 15,22 and 27 ofT12N, RISE UM. The commission has set a public hearing on July 24, 2001 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska. In addition, a person may submit written comments regarding the expansion prior to July 24,2001 to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage AK 99501. This notice supersedes the previous public notice in this matter. The public hearing will take place on July 24,2001, not June 12, as previously announced. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before July 17. 2001. ~~ Cammy Tay~ Chair, Alaska Oil and Gas Conservation Commission Published May 29,2001 ADN AO# 02114026 4/896874 STOF0330 P.O. 0211426 $99.75 . . AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Teresita Peralta being fIrst duly sworn on oath deposes and says that he/she is an representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an offIce maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on AMENDED Notice of Public Heàrin9 STATE OF AI.ASÌ<A , Alaska Oil and Gat Conservation Comminion Re: Prudhoe Bay Fiéld, Niakuk OU PO!),I . Revl. sion,tothe affected area o.f .AréalniectionOrder No. 14 ' BP'Explor'atian (Alatka) Inc by letter dated Mav 26. 2001. has requested· that the Alaska Oil and Gas ConSèrvotiol1 Commission eXPQl1d the allected orea for Area In- iection Order No. 14 (AI014) to inc,lude apor' tionof the we$lern ex- tent ofthe Niokuk, Oil Pool.,theexpansion will ççmsistof sections 15, 22 ond 27 of T12N"R15E, UM. May 29, 2001 The commission has set a public heoring on July 24,2001 Qt'9:00 am at the :~~~~~¡~~I, g~::, ~~~s~g~; 333 West 7th A ven ue, Suite 100, AIIChòrage, A1askcl. In Odditiol1¡ 0 perSOn may s.ubm ita written protestor cøm- ments an the applica- tions prior to J uty 24,' 2001 to the Alaska Oil and 'Gas C,onservotion Commis- sion at 333 West 7th Av- I ~j,~;:~;';;~ I lice in Ihit matter. The ~ro~I~Co~jc:it~n~/,', iJ1n',a): June 12,as previously announced. , If YOu lire ,0 pertòn with a disábilify who mpy need 0 tpec;ialmodilrca- tion in order to comment or to attend thep'ublic hearing, pie(Jse cont(Jct Jody Colombie 01793-1221 before July 17. 2001. IS! Cammy Taylor Chair, Alaska Oil'ond Gas Conservation Commission AO-Ô211424 Pub.: May 29. 2001 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. . r. S;g¡"d 7fy¿¡1a/1"--' Subscribed and sworn to before methisLdaYOf~ "0 ð t \.,\,trl N {( {{ ( -~~ ,. -.... Na~Pu~lie~\C ': § th~. ~.. aska..__ .§:' ~ V1 ~"'_. ~"' Ane Í\I. ItJFÄ~ .' ~ $ MY co EXPIIŒSr '\.\\'\ /./JJ f~~;'i)e,\\ I a l$.rrJl'\ STATE OF ALASKA ADVERTISING ORDER INV.MUST BE 1~~r~E~ S!~I~~~~~I~~~ER'CERTIFIED ADVERTISING ORDER NO. AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF AO-02114026 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AGENCY CONTACT DATE OF A.O. AOGCC R 333 West 7th Avenue, Suite 100 o Anchorage, AK 99501 M ¿ Anchorage Daily News POBox 149001 Anchorage, AK 99514 May 29, 2001 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2001, and thereafter for _ consecutive days, the last publication appearing on the _ day of .2001, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2001, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER . . AMENDED Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Prudhoe Bay Field, Niakuk Oil Pool - Revision to the affected area of Area Injection Order No. 14 BP Exploration (Alaska) Inc. by letter dated March 26. 2001, has requested that the Alaska Oil and Gas Conservation Commission expand the affected area for Area Injection Order No. 14 (AI014) to include a portion of the western extent of the Niakuk Oil Pool. The expansion will consist of sections 15,22 and 27 ofT12N, RISE UM. The commission has set a public hearing on July 24, 2001 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska. In addition, a person' may submit written comments regarding the expansion prior to July 24,2001 to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage AK 99501. This notice supersedes the previous public notice in this matter. The public hearing will take place on July 24,2001, not June 12, as previously announced. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before Julv 17. 2001. ~~ Cammy Tay& Chair, Alaska Oil and Gas Conservation Commission Published May 29, 2001 ADN AO# 02114026 I certify that on 1·ø cj. tJ / a copy of the abOve was faxed/mailed to each of the following at ~/ ~resses of record: ane ð~ál ¡;:Sf] l.-.J é --- OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LIBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 CROSS TIMBERS OPERATIONS, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 CROSS TIMBERS OIL COMPANY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 . PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SO BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 MURPHY E&P CO, ROBERT F SAWYER POBOX 61780 NEW ORLEANS, LA 70161 10GCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SO, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 . NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 ENERGY GRAPHICS, MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON, TX 77002 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 EXXON EXPLORATION CO.. T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 PHILLIPS PETR CO, PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 . PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 MARATHON OIL CO. GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 PO BOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 TEXACO INC, R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC POBOX 338 AUSTIN, TX 78767 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 . RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 BABCOCK & BROWN ENERGY, INC., JULIE WEBER 600 17TH STREET STE. 2630 SOUTH TOWER DENVER, CO 80210 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE. AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 FORCENERGY INC., JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 . C & R INDUSTRIES, INC." KURT SALTS GAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 . JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE,ID 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151ST #4 ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 GAFO,GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DNR, DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 . PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES, DIV OIL & GAS WILLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR SERVICES, JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 UON ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 . ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 DEPT OF REVENUE, OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 AMERICNCANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 US BLM AK DIST OFC, RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507-2899 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE. AK 99508 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 . US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 GORDONJ.SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE. AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 AL YESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 . US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV#13 ANCHORAGE, AK 99513-7599 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 ENSTAR NATURAL GAS CO, BARRETT HATCHES POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 . ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE. AK 99519-6247 BP EXPLORATION (ALASKA). INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 RON DOLCH OK PO BOX 83 KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 . ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE. AK 99519-6168 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC. WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 PENNY VADLA PO BOX 467 NINILCHIK, AK 99639 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654·5751 KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 . PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 VALDEZ PIONEER, POBOX 367 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG PO BOX416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 . JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ,AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 #3 bp . . BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 May 1, 2001 Jack Hartz Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Jack, Here is the info that you requested. If you need any further information, please contact Scott Mattison at 564-4362 or email himatMattisSA@bp.com. I will be transferring to a new job May 3rd at which time Scott will be taking over Niakuk. Sincerely, w~~ Wendy Baumeister Niakuk Production Engineer RECEIVED MAY 0 3 2001 Alaska Oil & Ga As Cons. C"""ml' . nchorage ""' SSIOO o . . Hydrocarbon Recovery 20 AAC 25.402(c) 14 The Niakuk development scenario as currently planned includes waterflooding, initially within the Niakuk Oil Pool. A total oil recovery of approximately 40 percent OOIP is expected for this development scenario. This compares to an estimated 4 percent OOIP oil recovery attributable to primary depletion. Waterflooding the Niakuk reservoir within the Niakuk Oil Pool is expected to result in an incremental 69.5 MMSTB beyond primary depletion in West Niakuk and 44.4 MMSTB in East Niakuk. Please see the table below for details. OOIP Primary Secondary Amount Gained (MMSTB) Depletion Depletion from Waterftood Segment 1/3/5 193 7.7 77.2 69.5 Segment 2 123.2 4.9 49.3 44.4 RECEIVED MAY 0 3 2001 Alaska Oil & Gas A Cons. Cofh~' nchorage ""'flssion . . Addendums Exhibit A-la: Plat of Proposed Niakuk Injection Area and Surface Ownership Exhibit A-2a: Legal Description of Proposed Niakuk Injection Area Exhibit G-la: Niakuk #20 Type Log Exhibit G-l b: Niakuk #22 Type Log Exhibit G-2a: Niakuk #09 Type Log Exhibit G-2b: Niakuk #29 Type Log Exhibit G-4a: Top Kuparuk Formation Structure Map with Existing Wells RECEIVED MAY 0 3 20[11 AIeIka 011 & Gas Cons, CornmtSSIO!\ An<:h<>f'age OPOSED NIAKUK I N AREA EXPANSION Exhibit A-1 a 10 16 Scale 1 :31 ,200 2000 1000 0 I I 4000 I ??oo I 18 Foot Projection: ASP4 NAD 1921 Proposed Injection Area 1 21 Working Interest in Niakuk leases: Phillips Alaska Inc 36.49210% Exxon 35.82283% BP 26.66461% Mobil 0.99980% Forest 0.02000% o 2 SD-08 o o 28 GULL ISLAND 33 34 NIAKUK ISLANDS L5-33 o 35 K-25 o o GULl-02 AD T12N T11N L5-21 DSNK L5-32 o L5-d9>-19 BPXA 1-2001/1m1 . . EXHIBIT A-2a Niakuk Area Injection Order Legal Description of Niakuk Injection Area T12N, RISE UM Protracted Sections 13-15, 22-27 Protracted Section 36: NI2 TI2N, R16E UM Protracted Sections 28-30 Protracted Sections 31: N/2 and 32: N/2 -- -lb ... ... #2 STATE OF ALASKA ADVERTISING ORDER IN. MUST BE I~~r~~; S~~I~~~~~J~~~EI CERTIFIED AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-02114015 F AOGCC 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF A.O. Jod Colombie PHONE A ril19 2001 PCN T Anchorage Daily News o POBox 149001 Anchorage, AK 99514 DATES ADVERTISEMENT REQUIRED: April 21, 2001 THE MATERIAl BElWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS SPECiAl INSTRUCTIONS: Type of Advertisement [8j Legal D Display D Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING NOTICE DATE 2 ARD 3 4 02910 FIN AMOUNT Sy CC PGM LC ACCT FY NMR DrST LID 01 02140100 73540 2 3 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Prudhoe Bay Field, Niakuk Oil Pool - Revision to the affected area of Area Injection Order No. 14 BP Exploration (Alaska) Inc. by letter dated March 26, 2001, has requested that the Alaska Oil and Gas Conservation Commission expand the affected area for Area Injection Order No. 14 (AI014) to include a portion of the western extent of the Niakuk: Oil Pool. The expansion will consist of sections 15,22 and 27 ofT12N, R15E UM. A person may submit written comments regarding the requested revision prior to 9:00 am on June 12, 2001 to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. In addition, the Commission has tentatively set a public hearing on June 12, 2001 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission prior to 9:00 am on May 7,2001. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before June 4, 2001. c~c~~~ Chair, Oil and Gas Conservation Commission Published ADN AO# 02114015 AD# DATE . . Anchorage Dally News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PO PRICE PER DAY OTHER CHARGES ACCOUNT 843853 04/21/2001 STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all saia time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was pu5lished in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. /> C, ~t: Signed ~ -- 02114015 STOF0330 $104.49 $0.00 $0.00 $0.00 $104.49 Notièe of PUblic Hearing STATE OF ALASKA AI_Q Oil Qnd GQS CÓllServatlon Commission BP Exploration (Alaska) Inc. by letter datEld March 26, 2001, has r_ested thOl the Alaska Oi,1 and Gas Consèrvatlon Commission expond th!{ affected areo for Areo In' lection Order No. 14, (A10141to include 0 'POr~, tion of the western ex-\ tent to the Niakuk 011 , Poal. The expansion will consist of sections'15, 22 and,27 of T12N, RISE UM, A person maY submi't written comments re- gOrdln!l the requested re- vision prior to 9:00 om on June''2, 2001 to the AlaskaOnand Gas Con, ~;3~~~~tC7{::~~s~~~~~ ,S ulte"100,A nchoro..-, Aloð"', 0 99501: In Oddlt;j¡,,; th!i!\C;M:lmission has ten¡¡ tatiWI'v s.t a pUblic hear- ingon June 12, 2001-at 9:01) om at the Alaska Oil and Gas Conservation, Commission at 333 West 7th Avenue, Suitel~, ,Anchorage, Aloska 99501.' A person mav request that ,the tentativelY scheduled heoring be held by filing 0 Written re- quest with the Commis- sian prior to 9:00 om on May 7, 2001. If 0 request for 0 hear- Subscribed and sworn to me before this date: l/ßv/ó/ Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: ~þ;61 ~Q2 ~G;â~ \l'\'(" frr '-\.\\~~~~"~':~" ~~ ~ ~··~OT.4~··?4 ~. __.)-. ~ ff\_ g : þtSLlC : ê ::.~ '.~ --- ~: " ~~. :'tOF ALÞ:~'~~ .¿, .... '\.- \" /./.1 ítJ¡¡ E'xp¡¡es ~' \ '\ \ .li/}}JJJJ\\\ OTHER CHARGES #2 GRAND TOTAL $0.00 $0.00 $0.00 $104.49 $0.00 $104.49 Ing Is nottimelyiil~. the I commission will con- 'Ider the issuonce Of on "rder withoÍJta heorìng. To learn If the Commls- ~i:~ r'r~~ ?0~1:~::Ucb~ll~ 193-1221. 'if YOU are 0 with Q dis- ability who may need a speciol modification In C!rder to comment or to t ottend the public hea~lng, ' please contact JodY' Co- lombie ot 193-1221 before June 4. 2001. I~ Cammy 011,. ch$1i Tavlor t Choir. Oil a,nd Gas I ;;~;~;;I;:I~::lmi$Slon I RECE'VED MAY 0 1 2001 þJ&Ska au & Gas (¡'On&. CQ(fllftISB10! Anchorage STATE OF ALASKA ADVERTISING ORDER INV.UST BE I~~!~~T~ S~~II~~~;~~I~~ER tERTIFIED ADVERTISING ORDER NO. AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF AO-02114015 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AOGCC 333 West 7th Avenue, Suite 100 o Pu1chorage,AJ( 99501 M AGENCY CONTACT DATEOFA.O. T Pu1chorage Daily News o POBox 149001 Pu1chorage,AJ( 99514 DATES ADVERTISEMENT REQUIRED: Apri121,2001 THE MATERiAl BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECiAl INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of SS INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who. being first duly sworn, according to law. says that ¡she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 19_. and thereafter for _ consecutive days, the last publication appearing on the _ day of . 19_, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 19_, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER ALASKA OFC OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LIBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 CROSS TIMBERS OPERATIONS, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 CROSS TIMBERS OIL COMPANY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 . PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 MURPHY E&P CO, ROBERT F SAWYER POBOX 61780 NEW ORLEANS, LA 70161 10GCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC.. LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY PO BOX 576 HOUSTON, TX 77001-0574 . /Ça//ed "ØJo)J¡ NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 SD DEPT OF ENV & NA TRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPI RAJU 335 PINYON LN COPPELL. TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 ENERGY GRAPHICS, MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON, TX 77002 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 TEXACO INC, R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC POBOX 338 AUSTIN. TX 78767 . PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETR CO, ALASKA LAND MGR POBOX 1967 HOUSTON, TX 77251-1967 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR PO BOX 2100 HOUSTON, TX 77252-9987 PHILLIPS PETR CO, JOE VOELKER 6330 W LP S RM 492 BELLAIRE, TX 77401 WA TTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 . RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 UNOCAL, REVENUE ACCOUNTING PO BOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXON MOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 PO BOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 PHILLIPS PETR CO, PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 C & R INDUSTRIES, INC... KURT SALTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151ST #4 ANCHORAGE, AK 99501 . BABCOCK & BROWN ENERGY, INC., JULIE WEBER 600 17TH STREET STE. 2630 SOUTH TOWER DENVER, CO 80210 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 . US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTH RIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE,WA 98101 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 FORCENERGY INC., JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 PRESTON GATES ELLIS LLP. LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 DEPT OF NATURAL RESOURCES. DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES. DIV OIL & GAS WILLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR SERVICES. JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE. AK 99502-1116 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE. AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 US BUREAU OF LAND MNGMNT. ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 . DEPT OF REVENUE. CHUCK LOGSTON 550 W 7TH AVE. SUITE 500 ANCHORAGE. AK 99501 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE. AK 99501-1994 DEPT OF REVENUE. OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE. AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE. SUITE 800 ANCHORAGE. AK 99501-3560 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE. AK 99503 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 FINK ENVIRONMENTAL CONSULTING, INC.. THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE. AK 99504-3305 US BUREAU OF LAND MNGMNT. ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 US BLM AK DIST OFC, RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE. AK 99507-2899 . YUKON PACIFIC CORP. JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 GAFO.GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE. SUITE 800 ANCHORAGE, AK 99501-3560 DNR. DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE. SUITE 800 ANCHORAGE. AK 99501-3560 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE. AK 99501-3560 N-I TUBULARS INC. 3301 C Street Ste 209 ANCHORAGE. AK 99503 ALASKA OIL & GAS ASSOC. JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE. AK 99503-2035 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 AMERICA/CANADIAN STRATIGRPH CO. RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE. AK 99508 UOAJ ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, FRANK MILLER 949 E 36TH AV STE 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR ATO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 AL YESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 . TRADING BAY ENERGY CORP. PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, STEVE BENZLER A TO 1404 POBOX 100360 ANCHORAGE. AK 99510-0360 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, CHUCK O'DONNELL 1835 S BRAGAW - MS 530B ANCHORAGE, AK 99512 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV#13 ANCHORAGE, AK 99513-7599 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 . US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 GORDONJ.SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, LIBRARY 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 PHILLIPS ALASKA, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LIBRARY POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE. AK 99517-1303 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, BRAD PENN POBOX 196168 ANCHORAGE, AK 99519-6168 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHA VELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 . DAVID CUSATO 600 W 76TH AV #508 ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 ENSTAR NATURAL GAS CO, BARRETT HATCHES POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 PHILLIPS PETR, ALASKA OPERATIONS MANAGER J W KONST PO DRAWER 66 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 . ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 RON DOLCH OK PO BOX 83 KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 PENNYVADLA PO BOX 467 NINILCHIK, AK 99639 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 VALDEZ PIONEER, POBOX 367 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS. AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 . BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 . PACE, SHEILA DICKSON PO BOX2018 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ, AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG PO BOX416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 #1 bp ) ) BP Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 March 26, 2001 Dear Commissioners: RECEIVED MAR 27 2001 ltll!ska OJ! & c. ,¡ ~ ; . , ..., Hi1{fO~ÌI· . . j.l.líit;f?m~aGl ~n~SJfJr Commissioners Heusser, Seamount, and Taylor Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501-3539 BP Exploration (Alaska) Inc., ("BP"), for itself and on behalf of Exxon Mobil Corporation, Mobil Alaska E&P Inc, Phillips Alaska Inc., and Forest Oil Corporation, hereby request expansion of the affected area for Area Injection Order 14 to include sections 15, 22, and 27 of T12N, R15E, thus encompassing all of the Western Niakuk reservoir. Sections 15, 22, and 27 are continuous with the Segment 1/3/5 reservoir found in the other T12N R15E Sections and are overlain by the HRZ shale. These sections border the west boundary of the portion of the Segment 1/3/5 reservoir within the area currently covered by AIO 14 making it an appropriate target for water injection to maximize an efficient sweep of Western Niakuk. Revising Area Injection Order 14 to encompass sections 15, 22, and 27 of T12N, R15E will enable efficient management of the waterflood to ensure increased recovery from the Western Niakuk reservoir. Sincerely, 49~ Randy Frazier G PMA Manager Cc: H. G. Limb M. J. Johnson P. White Phillips Alaska Exxon Mobil Forest Oil