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Home My WebLink AboutAIO 025 -.......- XHVZE Image Project Order File Cover Page This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. =\1.0 O~5 Order File Identifier ,- Organizing (done) ~WO-Sided 11111111111 ""I III DIGITAL DATA R~CAN 'Ø' Color Items: o Greyscale Items: o Diskettes, No. D Other, No/Type: o Poor Quality Originals: o Other: NOTES: Date: 71fó10~ Date: 7/1t(; If) h BY: C Maria) Project Proofing BY: ç Maria ") Scanning Preparation BY: C Maria J x 30 = + Date: 7/ Vó lob Production Scanning o Rescan Needed ""111111111111111 OVERSIZED (Scannable) D Maps: o Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) o Logs of various kinds: o Other:: vvJ;-fl III "111111111 "III /5/ WI I] = TOTAL PAGES 3 Dõ (Count does not i~~;ude cover sheet) ýY, j /5/ 11111111111111 "III Stage 1 Page Count from Scanned File: 3 0 (P (Count does include cover sheet) BY: Page Count Matches Number in Scanning Preparation: r~aria) Date: 7 / I~ /06 If NO in stage 1, page(s) discrepancies were found: Stage 1 BY: Maria Date: Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: Comments about this file: VYES NO .r\ VVJU /5/ YES NO /5/ 1111111111111111111 " 11/11111111111111 Isl Quality Checked III 111/1111I111111I 10/6/2005 Orders File Cover Page.doc . . INDEX AIO 25 POLARIS AREA INJECTION ORDER 1. September 12,2002 2. October 1,2002 3. November 1,2002 4. November 8, 2002 5. N/A 6. ---------- 7. December 9, 2002 8. December 13,2002 9. December 18,2002 10. November 6,2003 11. September 27, 2004 BPXA's request for Area Injection Order AOGCC's Request for more information and BPXA response dated October 31, 2003 BPXA's request for certain exhibits to be held confidential Notice of Hearing, Publication, affidavit of newspaper, copy of bulk mailing list Sign In Sheets for all meetings and hearings BPXA's submittal of exhibit VIII-l Transcript BPXA's request for certain exhibits to be held confidential Exhibits 1-6 and 1-7 Supplemental exhibit VIII-l BP request to amend (AI025.003) AOGCC Proposal to amend underground injection orders to incorporate consistent language addressing the mechanical integrity of wells AIO 25 . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order authorizing underground injection of fluids for enhanced oil recovery in Polaris Oil Pool, Prudhoe Bay Field, North Slope, Alaska IT APPEARING THAT: ) Area Injection Order No. 25 ) ) Prudhoe Bay Field ) Polaris Oil Pool ) ) ) February 4, 2003 1. By letter and application dated September 12, 2002, BP Exploration (Alaska) Inc. ("BPXA") in its capacity as Polaris Operator and Unit Operator of the Prudhoe Bay Unit ("PBU") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") authorizing the injection of fluids for enhanced oil recovery in the Polaris Oil Pool within the PBU. 2. By letter dated October 31, 2002, BPXA amended its Polaris Pool Rules and Area Injection Order ("AIO") Application and withdrew its request for approval of injection of miscible injectant ("MI") as part of the current Enhanced Oil Recovery project. 3. Notice of a public hearing was published in the Anchorage Daily News on November 8, 2002. 4. The Commission held a public hearing December 9, 2002 at 9:00 AM at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. 5. On December 18,2002 and January 22, 2Q03, BPXA submitted for the public record exhibits containing information previously submitted within confidential exhibits. 6. The Commission may issue an order permitting underground injection of fluids on an area basis for wells within the same reservoir and operated by a single operator. FINDINGS: 1. Operator: BPXA is operator of the Polaris Oil Pool in the Prudhoe Bay Field, North Slope, Alaska. Area Injection Order 25 February 4, 2003 . . Page 2 2. Project Area Pool and Formations Authorized for Enhanced Recovery: Strata proposed for enhanced recovery injection are a subset of the Polaris Oil Pool defined in Conservation Order 484. The target injection zones are correlative to Prudhoe Bay Unit well S-200PBl between the measured depths ("MD") of 5,603 feet and 6,012 feet (Schrader Bluff Formation). Development plans for the upper portion of the Polaris Oil Pool (Ugnu Formation) have not been determined and BPXA has not requested authorization to inject fluids into the Ugnu Formation. 3. Proposed Injection Area: BPXA requested authorization to inject fluids for the purpose of enhanced recovery operations on lands within Umiat Meridian TIIN-RI2E, TIIN-R13E, TI2N-RI2E, and T12N-R13E in the Prudhoe Bay Unit. The application for an Area Injection Order provides information surrounding five discrete, widely spaced injections wells. These proposed injectors are wells S-104i, proposed redrill S-200Ai, S-215Ai, W-207i, and W-212i. 4. Operators/Surface Owners Notification: BPXA provided operators and surface owners within one-quarter mile of the proposed area with a copy of the application for injection. The only affected operator is BPXA, operator of Prudhoe Bay Unit. The State of Alaska, Department of Natural Resources is the only affected surface owner. 5. Existing Orders: a. Aquifer Exemption: Aquifer Exemption Order No.1, dated July 11, 1986, exempts freshwater aquifers lying directly below the Western Operating and K- Pad Areas of the Prudhoe Bay Unit. b. Area Injection Order: AIO No.3, dated July 11, 1986, authorizes underground injection of fluids within specified strata lying directly below the Western Operating Area and K-Pad Area of the Prudhoe Bay Unit for the purposes of enhanced recovery and the disposal of non-hazardous oil field waste fluids. AlO No.3, Rule 2 authorizes injection for disposal purposes in strata that correlates with the strata found in PBU Well C-11 between 3,990 feet and 6,293 feet MD. 6. Description of Operation: The Polaris Oil Pool will be developed in phases, beginning at the crests of the accumulations near the S-, M-, and W- Pads, and progressively working towards the outer margins of the pool. Peak production rates are expected to be between 12,000 and 15,000 barrels of oil per day ("BOPD"). Waterflood injection rates are estimated to peak between 20,000 and 25,000 barrels of water per day ("BWPD"). Area Injection Order 25 February 4, 2003 . . Page 3 7. Hydrocarbon Recovery: The Polaris Oil Pool is estimated to contain 350 to 750 million barrels of original oil in place ("OOIP") based on exploratory drilling and seismic mapping. Computer simulation results indicate primary recovery within the target sands of the development area is expected to be 5 to 1 0% of the OOIP, and implementing a waterflood will recover an additionall 0 to 20% of the OOIP. 8. Geologic Infonnation: a. Stratigraphy: The Polaris Oil Pool encompasses reservoirs assigned to the Late Cretaceous-aged Schrader Bluff Fonnation ("Schrader Bluff') and the Early Tertiary-aged Ugnu Fonnation ("Ugnu"). The Schrader Bluff is divided into two stratigraphic intervals that are designated, from deepest to shallowest, the "O-sands" and the "N-Sands." The overlying Ugnu reservoir intervals of the Polaris Oil Pool are infonnally tenned the "M-Sands." The 0- and N-Sand intervals were deposited in marine shoreface and shallow shelf environments. The M-Sands were deposited in deltaic and fluvial environments. b. The Schrader Bluff O-Sands are divided into seven separate reservoir intervals that are named, from deepest to shallowest, OBf, OBe, Obd, OBc, OBb, OBa, and OA. Each of these intervals coarsens upward from non-reservoir, laminated muddy siltstone at the base to reservoir-quality, thinly bedded sandstone at the top. c. The lower portion of the Schrader Bluff N-Sands is dominated by mudstone and siltstone. However, the sediments coarsen upward, and fine- to medium- grained sandstone is prevalent in the upper part of the N-Sands. Three reservoir intervals are recognized within the N-Sands. They are, from oldest to youngest, NC, NB, and NA. d. The Ugnu M-Sands are divided into four reservoir intervals named, from deepest to shallowest, MC, MB2, MB 1, and MA. These intervals consist of unconsolidated, clean sands that are separated by thin, but extensive, intervals of non-reservoir silty mudstone. e. Structure Overview: The Polaris Oil Pool structure lies between approximately 4,800 feet and 5,300 feet true vertical depth subsea ("TVDss") within the affected area. The structural dip ranges up to 4 degrees to the east and northeast, and it is broken by three sets of faults: one trending northwest, the second trending north, and the third trending west. These faults are nonnal, and they divide the structure into a series of reservoir compartments. Northwest- and north-trending faults are the primary controls for oil distribution in the W-Pad, S-Pad and M-Pad areas. The west-trending faults occur most commonly in the down-dip portions of the pool to the east and northeast. They trap oil in the center of the pool: near the Tenn Well C, near N-Pad, and along the southern margin of the pool. Area Injection Order 25 February 4,2003 . . Page 4 f. Confining Intervals: Lower confmement for the Polaris Oil Pool is provided by the non-reservoir, laminated muddy siltstone that constitutes the base of the OBf interval and 1,100 feet of mudstone and silty mudstone assigned to the upper Colville Group. g. The basal portion of the Schrader Bluff N-Sands interval consists of non- reservoir mudstone and siltstone that forms a regionally extensive hydraulic barrier. This barrier separates lighter, higher quality oil in the O-Sands from the heavier oil accumulations in the overlying N- and M-Sand intervals. The MC Sand is separated from the underlying N-Sands by a silty mudstone that ranges in thickness from 15 to 25 feet. h. Upper confinement is provided by a 14- to 25-foot thick mudstone that lies at the base of the MB2 interval and forms a regionally continuous hydraulic barrier. This mudstone layer separates oil-bearing MC Sand from overlying, water-bearing MB2 Sand within the pool. A 9- to 15-foot thick silty mudstone overlies the uppermost MA sand and provides a regionally extensive barrier. 9 . Well Logs: The logs of existing injection wells are on file with the Commission. 10. Mechanical Integrity and Well Design of Injection Wells: BPXA is requesting approval to inject water simultaneously into the Aurora (Kuparuk Formation) and Polaris Oil Pools within well S-1 04i. Water is currently being injected into the Aurora Oil Pool within this well. This well is designed to allow dual injection with packers installed for zonal isolation. Injection valves will be sized for water injection rate control and will be run within mandrels between the packers. Spinner logs will be run to verify injection rates to the separate formations. 11. Type of Fluid / Source: Water for injection will be supplied from Gathering Center 2 and from the Seawater Treatment Plant. In addition, tracer survey fluids and well stimulation fluids will be injected periodically to ensure efficient operation of the water flood. Non-hazardous filtered water collected from Polaris Oil Pool well house cellars and well pads may also be injected. 12. Water Composition and Compatibility with Formation: BPXA provided laboratory analysis of the injection and produced waters. No significant compatibility problems are evident from these analyses. Disposal of PBU produced water within the Ugnu sands has successfully occurred in other parts of the field. Area Injection Order 25 February 4, 2003 . . Page 5 13. Area of Injection Influence: The area of injection influence lies within y,¡ mile radial distance of the point of injection, assuming radial flow of the injected water. Reservoir simulation suggests that within 1,000 feet to 1,500 feet of the injector, the reservoir pressure dissipates to near reservOIr pressure. 14. Injection Rates and Pressures, Fracture Information: The requested maximum water injection rate is 25,000 barrels of water per day ("bwpd") in the project area. The individual well injection rates will range from 1 000 to 5000 bwpd. BPXA requested a maximum surface injection pressure of 2800 psi with an average surface operating pressure of 2300 psi. Step rate tests indicate fractures initiate at about 1000 psi surface injection pressure while injecting at 112 to 2 barrels per minute. A stress test performed in well S-213 indicates a fracture gradient of 0.66 psi/ft for the basal mudstone of the OBa interval. This is a typical silty mudstone within the Polaris Oil Pool. Minimum stress values for the sandstones show an average fracture gradient of 0.61 psi/ft, indicating a stress contrast of approximately 255 psi between reservoir sandstone and confining mudstone. This agrees with the stress contrast of 300 psi estimated using the dipole sonic log from well W-200. 15. Mechanical Condition of Adjacent Wells: Wells recently drilled into the Polaris Oil Pool have been constructed in conformance with Commission regulations. Many pre-existing exploratory and development wells in this area were drilled to deeper targets. The mechanical isolation of some wells in the Polaris Oil Pool has not been demonstrated. Ivishak producing well W -17 is within 255 feet of proposed injector W-212i at the level of MB2 mudstone. Information supplied does not demonstrate cement confinement across the Polaris Oil Pool in well W-17. BPXA's proposed surveillance program includes a pre-injection baseline temperature survey within well W -17 and additional temperature surveys at 2, 5, and 8 months after initiating water injection. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. Water injection will significantly improve recovery. 3. Dual injection within well S-104i is appropriate so long as mechanical isolation ofthe pools within the wellbore is assured and water injection is allocated between the pools. 4. Sufficient information has been provided to authorize five (5) wells to inject water into the Polaris Oil Pool tor the purposes of pressure maintenance and enhanced oil recovery. Area Injection Order 25 February 4, 2003 . . Page 6 5. 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. 6. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 7. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 8. Disposal injection in hydrocarbon bearing strata may harm resource development. NOW, THEREFORE, IT IS ORDERED that: 1. Within the affected area, this order supersedes Rule 2 of Area Injection Order No.3, dated July 11, 1986 and Administrative Approval No. 3.1, dated August 15, 1986. 2. The underground injection of fluids for enhanced oil recovery is authorized, subject to the following rules and the statewide requirements under 20 AAC 25 (to the extent not superseded by these rules) in the following affected area. Area Injection Order 25 February 4,2003 Umiat Meridian Township I Range TI2N-RI2E TI2N-R13E TllN-R13E TI1N-RI2E . Lease ADL 28256 ADL 47448 ADL 28257 ADL 28258 ADL 28279 ADL 28282 ADL 28260 ADL 28261 ADL 28263-1 ADL 28263-2 ADL 47451 ADL 28264 ADL 47452 . Page 7 Sections Sec 22 S/2 S/2 and NE/4 SE/4 See 23 S/2 NW/4 and SW/4 Sec 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26,35,36 Sec 27,33 SE/4 SE/4, 34 E/2 W/2 and SW/4 SW/4 and E/2 Sec 31 SW/4 NW/4 and SW/4 Sec 6 W/2 and SE/4 and S/2 NE/4 and NW/4 NE/4, Sec 7 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4, Sec 8 W/2 SW/4 Sec 1,2, 11 W/2 and NW/4 NE/4, 12 N/2 N/2 and SE/4 NE/4 Sec 3, 4 E/2 E/2, 9 NE/4 NE/4 and S/2 NE/4 and SE/4, 10 Sec 15, 16 E/2 Sec 21 NE/4 NW/4 and NE/4 SE/4 and NE/4, 22 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4 Sec 14 W/2 and W/2 SE/4, 23 W/2 and W/2 E/2 and SE/4 SE/4 and SE/4 NE/4 Sec 26 N/2 N/2 Sec 27 NE/4 NE/4 Rule 1 Authorized Iniection Strata for Enhanced Recovery Authorized fluids may be injected for purposes of pressure maintenance and enhanced oil recovery into strata that are common to, and correlate with the N and O-Sand interval between 5,603 feet and 6,012 feet MD in Prudhoe Bay Unit well S-200PB1. Area Injection Order 25 February 4,2003 . . Page 8 Rule 2 Fluid Iniection Wells The underground injection of fluids for enhanced oil recovery IS authorized In the following wells: Injection Well Permit to Drill Physical Location of Injection Interval S-104i 200-196 Sec 26 and 27, TI2N, R12E S-200Ai 197-239 Sec 27, T12N, R12E (proposed) S-215i 202-154 Sec 34, TI2N, R12E W-207i Proposed well Sec 23, TIIN, R12E (proposed) W-212i 202-066 Sec 22, TIIN, R12E Upon proper application, the Commission may administratively approve additional wells for injection of fluids in the Polaris Oil Pool. The underground injection of fluids must be through a well that is permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412. The application to drill or convert a well for injection must also include a report on the mechanical condition of each well that has penetrated the injection zone within a one- quarter mile radius of the proposed injection well. The information must include cementing records, cement quality log or formation integrity test records. Rule 3 Authorized Fluids for Enhanced Recoverv Fluids authorized for injection include: a. Produced water from the Polaris Oil Pool or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; b. tracer survey fluid to monitor reservoir performance; c. source water from a sea water treatment plant; and d. non-hazardous filtered water collected from Polaris Oil Pool well house cellars and well pads. Rule 4 Authorized Iniection Pressure for Enhanced Recoverv a. Normal injection pressures must be maintained below the parting pressure of the confining mudstone (approximately 0.67 psilft). b. Operating pressure within well W-212i must be maintained below parting pressure of the reservoir sandstone, until offset well W -17 is proven to provide sufficient mechanical isolation to prevent migration of water out of the approved injection stratum. Area Injection Order 25 February 4,2003 . . Page 9 Rule 5 Monitorine: Tubine:-Casin2 Annulus Pressure Tubing-casing annulus pressures within each injection well must be checked and recorded weekly to ensure there is no pressure communication or leakage in any casing, tubing or packer. Rule 6 Demonstration of Tubin1!lCasine: Annulus Mechanical Intee: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 7 Multiple Completion of Water Iniection Wells a. Water injectors may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission. b. Prior to initiation of co-mingled injection, the Commission must approve methods for allocation of injection to the separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Rule 8 Well Intee:ritv Failure Whenever operating pressure or pressure tests indicate communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation and obtain Commission approval to continue injection. Commission approval of an Application for Sundry Approval (Form 10-403) is required before initiating corrective action. Rule 9 Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 2 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 25 February 4,2003 . . Page 10 Rule 10 W-17 Surveillance Prior initiating injection within well W-212i, a baseline temperature survey within W-17 is required. Additional temperature surveys within well W-17 are required at 2, 5, and 8 months after initiating water injection to verify the W-17 wellbore is not serving as a fluid migration path. Results and interpretation of these surveys shall be supplied to the Commission within 30 days of completing the survey. Injection must be terminated in well W-212i if there is any indication of pressure communication or leakage within well W -17 attributed to injection in well W -212i. Rule 11 Plu22ine: and Abandonment of Fluid Iniection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25. Rule 12 Other conditions 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 13 Administrative Actions 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 rreshwater. DONE at Anchorage, Alaska and dated February 4,2003. ;"i ~/i1.u' '1,~ C~y 5~.eci&.li Taylor, Chair () Alaska Oil ana Gas Conservation Commission 5D~ Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission ~/:--¥ Michael L. Bill, P .E., Commissioner 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 Month file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 2300 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 non-action 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., lOth day after the application for rehearing was filed). Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 T.E. Alford ExxonMobilExploration Company PO Box 4778 Houston, TX 77210-4778 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 Shelia McNulty Financial Times PO Box 25089 Houston, TX 77265-5089 James White Intrepid Prod. Co./Alaskan Crude 4614 Bohill SanAntonio, TX 78217 e SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 G. Scott Pfoff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 William Holton, Jr. Marathon Oil Company Law Department 5555 San Fecipe St. Houston, TX 77056-2799 Corry Woolington ChevronTexaco Land-Alaska PO Box 36366 Houston, TX 77236 Donna Williams World Oil Statistics Editor PO Box 2608 Houston, TX 77252 Shawn Sutherland Unocal Revenue Accounting 14141 Southwest Freeway Sugar Land, TX 77478 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 e John Katz State of Alaska Alaska Governor's Office 444 North Capitol St., NW, Ste 336 Washington, DC 20001 Alfred James 200 West Douglas, Ste 525 Wichita, KS 67202 Conoco Inc. PO Box 1267 Ponca City, OK 74602-1267 Michael Nelson Purvin Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 W. Allen Huckabay ConocoPhillips Petroleum Company Offshore West Africa Exploration 600 North Dairy Ashford Houston, TX 77079-1175 Texico Exploration & Production PO Box 36366 Houston, TX 77236 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 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 e Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 e 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, Jnc PO Box 45738 Los Angeles, CA 90045-0738 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Julie Houle Robert Mintz Duane Vaagen State of Alaskan DNR State of Alaska Fairweather Div of Oil & Gas, Resource Eva!. Department of Law 715 L Street, Ste 7 550 West 7th Ave., Ste 800 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Anchorage, AK 99501 Anchorage, AK 99501 Jim Arlington Tim Ryherd Williams VanDyke Forest Oil State of Alaska State of Alaska 310 K Street, Ste 700 Department of Natural Resources Department of Natural Resources Anchorage, AK 99501 550 West 7th Ave., Ste 800 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Anchorage, AK 99501 Cammy Taylor Richard Mount Ed Jones 1333 West 11th Ave. State of Alaska Aurora Gas, LLC Anchorage, AK 99501 Department of Revenue Vice President 500 West 7th Ave., Ste 500 1029 West 3rd Ave., Ste 220 Anchorage, AK 99501 Anchorage, AK 99501 Susan Hill Trustees for Alaska Mark Wedman State of Alaska, ADEC 1026 West 4th Ave., Ste 201 Halliburton EH Anchorage, AK 99501-1980 6900 Arctic Blvd. 555 Cordova Street Anchorage, AK 99502 Anchorage, AK 99501 Schlumberger Ciri John Harris Drilling and Measurements Land Department NI Energy Development 3940 Arctic Blvd., Ste 300 PO Box 93330 Tubular Anchorage, AK 99503 Anchorage, AK 99503 3301 C Street, Ste 208 Anchorage, AK 99503 Rob Crotty Jack Laasch Mark Dalton C/O CH2M HILL Natchiq HDR Alaska 301 West Nothern Lights Blvd Vice President Government Affairs 2525 C Street, Ste 305 Anchorage, AK 99503 3900 C Street, Ste 701 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Mark Hanley Judy Brady 4730 Business Park Blvd., #44 Anadarko Alaska Oil & Gas Associates Anchorage, AK 99503 3201 C Street, Ste 603 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503 Anchorage, AK 99503-2035 Arlen Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 Dudley Platt DA Platt & Associates 9852 Little Diomede Cr. Eagle River, AK 99577 Shannon Donnelly Phillips Alaska, Inc. H EST -Enviromental PO Box 66 Kenai, AK 99611 e Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Bill Bocast PACE Local 8-369 c/o BPX North Slope, Mailstop P-8 PO Box 196612 Anchorage, AK 99519 BP Exploration (Alaska), Inc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Bob Shavelson Cook Inlet Keeper PO Box 3269 Homer, AK 99603 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 e Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,lnc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Jim Ruud Phillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw - MS 575 Anchorage, AK 99515 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Peter McKay 55441 Chinook Rd Kenai, AK 99611 Penny Vadla Box 467 Ninilchik, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 John Tanigawa Evergreen Well Service Company PO Box 871845 Wasilla, AK 99687 Cliff Burglin PO Box 131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 Lt Governor Loren Leman State of Alaska PO Box 110015 Juneau, AK 99811-0015 .,.1...JQ,.rf2 'jt:;~.,f~C{ér:;, ,SAt,iÇ}{J. è1*~ì~ '( ,1-- e Claire Caldes US Fish & Wildlife Service Kenai Refuge PO Box 2139 SOldotna, AK 99669 Charles Boddy Usibelli Coal Mine, Inc. 100 Cushman Street, Suite 210 Fairbanks, AK 99701-4659 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 e Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Kurt Olson State of Alaska Staff to Senator Tom Wagoner State Capitol Rm 427 Juneau, AK 99801 . ~~~~E mJF ~~~~~~~ AI,ASIiA 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 ADMINISTRATIVE APPROVAL NO. AIO 25.01 Lowell Crane Senior Drilling Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage Alaska 99519 Dear Mr. Crane: Area Injection Order No. 25 ("AIO No. 25"), dated February 4, 2003, au- thorizes underground injection of fluids for enhanced oil recovery in the Polaris Oil Pool, Prudhoe Bay Field, North Slope, Alaska. Rule 2 of AIO No. 25 author- izes underground fluid injection in specific wells enumerated in the Order. Subject Rule 2 also allows the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission") administrative approval of additional Polaris injec- tion wells. Proposed well W-209i is permitted for drilling as a service well for injec- tion in conformance with 20 AAC 25.005. AOGCC has verified the mechanical condition of wells within a one-quarter mile radius of the proposed injection zone. AOGCC has determined that fluids injected into proposed well W-209i will enter permeable strata which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of confining strata. The Commission has further determined that injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. Accordingly, Area Injection Order No. 25 is amended to authorize drilling and construction of Prudhoe Bay Field, Polaris Oil Pool welF'W-209i. DO~.Ei~.. Anc~or.i~' At~S~ this 25"' of July 200.3. ~~v(. /)Ÿ- ~ s-áí=ah)t. Palin O. Daniel T. Seamount, Jr. /C1-.~:.4./ \ J C· . ".,¡,uur" ommlSSlOner BY ORDER OF THE COMMISSION .. . ~~!Æ~E rnJF !Æ~!Æ~~~!Æ ~","'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 ADMINISTRATIVE APPROVAL NO. AlO 25.02 Lowell Crane Senior Drilling Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage Alaska 99519 Dear Mr. Crane: Area Injection Order No. 25 ("Ala No. 25"), dated February 4, 2003, authorizes underground injection of fluids for enhanced oil recovery in the Polaris Oil Pool, Prudhoe Bay Field, North Slope, Alaska. Rule 2 of Ala No. 25 authorizes underground fluid injection in specific wells enumerated in the Order. Subject Rule 2 also allows the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission") administrative approval of additional Polaris injection wells. Proposed well W-215i is permitted for drilling as a service well for injection in conformance with 20 MC 25.005. There are no other wells within a one-quarter mile radius of the proposed injection zone. AOGCC has determined that fluids injected into proposed well W-215i will enter permeable strata which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of confining strata. The Commission has further determined that injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. Accordingly, Area Injection Order No. 25 is amended to authorize drilling and construction of Prudhoe Bay Field, Polaris Oil Pool well W-215i. DONE in Anchorage, Alaska this 29st day of July 2003. .----, f"'? ,~s2~~t.·.' ,fjL '-' ChaIr Daniel T. SeaÍnount, Jr. Commissioner BY ORDER OF THE COMMISSION A .,ASIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR ~~!Æ~E (ill r !Æ~!Æ~~~!Æ 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 25.003 Mr. Brian Huff Satellite Resource Manager - Greater Prudhoe Bay BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Huff: By letter dated November 6, 2003 you requested amendment of Rule 4, Area Injection Order 25 that sets forth rules for conducting water injection into the Polaris Oil Pool. Currently, Rule 4 is as follows: Rule 4 Authorized Injection Pressure for Enhanced Recovery a. Normal injection pressures must be maintained below the parting pressure of the confining mudstone (approximately 0.67 psi/ft). b. Operating pressure within well W-212i must be maintained below parting pressure of the reservoir sandstone, until offset well W-17 is proven to provide sufficient mechanical isolation to prevent migration of water out of the approved injection stratum. The Commission ordered this rule to ensure that Polaris injected water does not fracture or migrate out of zone, and based its decision upon information supplied by BPXA. This information suggested a fracture pressure for the confining mudstone of about 0.66-0.67 psi/ft using data from stress tests and dipole sonic log. BPXA performed step rate water injection tests in June in Wells W-212i and S-215i, with verbal approval from the Commission. These tests showed significant improvement in injection rate with increased injection pressure. Temperature logs run in July show the water to be confined to the intended intervals. These tests were performed at injection gradient of 0.75-0.80 psi/ft, well above the expected confining zone fracture pressure gradient of 0.67 psi/ft. Mr. Brian Huff AIO 25.003 November 13, 2003 . . Baseline and two month temperature profiles were run in Well W-17 (255' offset to W- 212i) in accordance with requirements of Rule 10 of AIO 25. The Commission required the logs because confinement across the Polaris Oil Pool in well W -17 was questionable. There was no apparent change in temperature; hence offset injection in Well W-212i has not reached the well. In review of more recent injection data the Commission discovered that injection pressures in wells W-212 and W-207 have greatly exceeded the Rule 4 limiting pressure of 0.67 psi/ft in Wells W-212 and W-207 during August and September. This injection could have resulted in a Notice of Violation. Please take care that requirements of the Conservation Orders are met. The Commission finds that based upon the tests performed on wells W-212i and S-215i, a less restrictive rule is appropriate. It is BPXA's responsibility to ensure the injection stays within the approved injection interval. Rule 4 of Area Injection Order 25 is amended to read as follows: Rule 4 Authorized Injection Pressure for Enhanced Recovery a. Injection pressure must be maintained so that injected fluids do not fracture the confining zone or migrate out of the approved injection stratum. b. Within three months of start of injection in a new or converted water injector, a step rate test and surveillance log must be run for detection of fluids moving out ofthe approved injection stratum. Results must be submitted to the commission. c. If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injector(s). Injection may not be restarted unless approved by the Commission. DONE at Anchorage, Alaska and dated November 13,2003. '\../ Daniel T. Seamount, Jr. Commissioner Chair . ~ ,,", .' - ;.~ .' "..~, ' '" .' #11 r bp . . o November 6, 2003 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Commissioners Alaska Oil and Gas Conservation Commission 333 West ¡th Avenue, Suite 100 Anchorage, AK 99501 RE: Application to Amend Area Injection Order No. 25 Dear Commissioners: BP Exploration (Alaska) Inc. (BPXA), Operator of the Prudhoe Bay Unit (PBU), applies to Amend Rule 4 of Area Injection Order No. 25 for the Polaris Oil Pool. BPXA requests that Rule 4 be amended as follows: Rule 4 a. Authorized Injection Pressure for Enhanced Recovery Normal injection pressures must be maintained such that injected fluids do not fracture or migrate out of the approved injection stratum. b. Through routine surveillance, if fluids are found to be fracturing out of or migrating out of the approved injection stratum, the Operator must notify the Commission. A mitigation plan will be agreed upon between the Commission and the Operator. Rule 4 of Area Injection Order No. 25 currently provides that normal injection pressure must be maintained below the parting pressure of the confining mudstone of approximately 0.67 psi/ft. Tests recently performed in two Polaris injection wells, W-212i and S-215i, demonstrate that fluids will be contained in the approved injection strata while injecting above formation fracture pressure. BPXA supplied fracture propagation information at the time of application for an Area Injection Order for the Polaris Oil Pool (POP). A stress test performed in well S-213 indicated a fracture gradient of 0.66 psi/ft for the basal mudstone of the OBa interval, a typically silty mudstone within the POP. Minimum stress values for the sandstones showed an average fracture gradient of 0.61 psi/ft, indicating a stress contrast of approximately 255 psi between reservoir sandstone and confining mudstone. On the basis of this information, the Commission ordered that POP normal injection pressure be maintained belowO.67 psi/ft to ensure injection stays within the intended injection interval. More recently, BPXA has performed step rate water injection tests in two Polaris wells, W-212i and S-215i (Exhibit A). The Schrader Bluff Formation in these wells should be representative of the Polaris W pad and S pad areas where injection will be occurring. Injection rates of up to 10,000 BWPD and injection gradients of 0.75-0.80 psi/ft were achieved. Injectivity curves are shown as . . , Exhibit B. Temperature surveys showed the water to be confined to the intended intervals, with no fluid movement behind pipe. This pressure exceeded that obtained in the original stress test described above. Rule 10 of Area Injection Order No. 25 requires that a baseline temperature survey and additional surveys be run in well W-17 at 2, 5, and 8-months after initiating injection into W-212i. The baseline and 2-month survey have been run with no indication of fluid migration out of the authorized strata. The 5 and 8- month surveys will be performed as required. Based on the additional injection testing, and surveillance data presented, we request Rule 4 of Area Injection Order 25 be modified as stated above. Thank you for your timely consideration. Any questions regarding this request should be directed to me at 564-5110. Si~JereIY, IMrl f _/ '\ ~¡; /" /A,,_ u· ï . tfri~n Huff Satellite Resource Manager Greater Prudhoe Bay ¡ I I, /ö 5 Attachments Exhibit A - Step Rate Tests W-212 & S-215 Exhibit B -Injection Plots forW-212 & S-215 Cc: M. Vela, Exxon Mobil Corp. K. Griffin, Forest Oil Corp. J. Johnson, CPAI G.M. Forsthoff, Chevron U.S.A. Inc. G. Gustafson, BPXA R. Jacobsen, BPXA D. Schmohr, BPXA M. Kotowski, DNR B. Loeffler, DNR /' 1700 1600 1500 1400 1300 I! 1200 ::I iii iii I! 1100 - Q. " III 41 1000 ~ :;¡;: ~ 900 800 700 600 500 0 1600 1400 1700 1500 Exhiblt..A Rate Test Extension 1240 PSI WHP/1500 BPD 9000 10000 11000 ...... . 1000 2000 3000 4000 5000 6000 7000 Rate BPD W·212i Step Rate Test 6/14103 8000 îS 1300 - ~ e 1200 ;¡ .. 2! 1100-- II. 'g i 1000 :E: ¡ 900 800 700 600 500 0 .. 1000 :2000 3000 4000 5000 6000 7000 Rate (BPD) 8000 9000 10000 - " Exhibit... B W -212 Injection Analysis I--WH_PRESSURE ---. INLRATE "~" WH_TEMP I 1800 160 800 .. . . -1. --~- ------ 1600 -- - - - - 140 1400 120 1200 ~ $; f:." ~ 1000 _Ii - \ -- 100 600--- 1-.- -80 ------ ~u___ _ _ _ _~___ - - - - 60 ø ~ "" ~ 400-- 40 --- - --- - -- - - - --~ ~ -- - - ,. 200 :- 20 o 5/12/20030:00 5/22/20030:00 6/1/20030:00 6/11/2003 (),OO 6/21/20030:00 7/1/20030:00 7/11/20030:00 o 7/21/20030:00 S-215 Injection Analysis I ¡--WH_PRESSURE .-"-- WH3EMP I 2500 160 2000 -140 - - - -- - -~,- - -.-- -100 1500 ~ ~ ~ ...... 1000 - r- oo ~ t..¡ ~ 500 ~ -i¡)" - _. - - - - - - - 80 __L_~ - 60 "f· ;.. - 40 - -- --- - - - - o 5/12/2003 0:00 ~ 5/22/20030,00 6/1/2003 0:00 20 6/11/2003 0:00 6/21/20030:00 7/1/20030:00 7/11/20030:00 o 7/21/2003 0:00 #10 <~c ~ ¡~ 11 /11\\1 r ¡ r "..\ 1; ¡W \ 11 :? ~ ':1. ~ ., ~ ~ j I l-1 i{ j i LJ, í!! '. I: " \~'~W~~ im~= ~-... ~-" : "j ; ! i~: ~ r ~~ :; if, .. ¡!J~. u,_' i)~j ii. U='J C~) !T\ , 1'4 :: ~ 1J ~ Lf1J / j j I / FRANK H. MURKOWSKI. GOVERNOR A"~A~1iA. OIL AlWD GAS CONSERVATION COMMISSION 333 W. PH AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAJ< (907)276-7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the lVlechanical Integrity of Wells The Alaska Oil and Gas ConservatiQn Commission ("Commission"), on its own motion, proposes to amend the rules addressing m~chanical 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 inca ns is tent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Inte~ity 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 correcti ve action on a F ann 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. Injection Order "Demonstration of Mechanical Integrity" Affected Rules "Well Integrity Fail ure and Confinement" "Administrative Action" .A.rea Injection Orders AlO 1 - Duck Island Unit AlO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, U gnu, West Sak Fields AlO 3 - Prudhoe Bay Unit; Western Operating Area AIO 4C - Prudhoe Bay Unit; Eastern Operating Area AlO 5 - Trading Bay Unit; McArthur River Field AlO 6 - Granite Point Field; Northern Portion AlO 7 - Middle Ground Shoal; Northern Portion AlO 8 - Middle Ground Shoal; Southern Portion AlO 9 - Middle Ground Shoal; Central Portion AlO 10B - Milne Point Unit; Schrader Bluff, Sag River, Kuparuk River Pools AlO 11 - Granite Point Field; Southern Portion AIO 12 - Trading Bay Field; Southern Portion AlO 13A - Swanson River Unit AlO 14A - Prudhoe Bay Unit; Niakuk Oil Pool AlO 15 - West McArthur 6 7 9 6 7 9 6 7 9 6 7 9 6 6 9 6 7 9 6 7 9 6 7 9 6 7 9 4 5 8 5 6 8 5 6 8 6 7 9 4 5 8 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 AIO 17 - Badami Unit 5 AIO 18A - Colville River 6 7 11 Unit; Alpine Oil Pool AIO 19 - Duck Island Unit; 5 6 9 Eider Oil Pool AIO 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AIO 21 - Kuparuk River 4 No rule 6 U nit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 Unit; 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 Injection Orders DIO 1 - Kenai Unit; KU No rule No rule No rule WD-l DIO 2 - Kenai Unit; KU 14- No rule No rule No rule 4 DIO 3 - Beluga River Gas No rule No rule No rule Field; BR WD-1 DIO 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DIO 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DIO 6 - Lewis River Gas No rule No rule 3 Field; WD-l DIO 7 - West McArthur 2 3 5 River Unit; W1\1RU D-1 DIG 8 - Beaver Creek Unit; 2 3 5 BC-3 DIO 9 - Kenai Unit; KU 11- 2 3 4 17 DIO 10 - Granite Point 2 3 5 Field; GP 44-11 DIO 11 - Kenai Unit; KU 24-7 DIO 12 - Badami Unit; \VD- 1, \VD-2 DIO 13 - North Trading Bay! Unit; S-4 I DIO 14 - Houston Gas Field; Well #3 DIO 15 - North Trading Bay Unit; S-5 DIO 16 - West McArthur River Unit; WMRU 4D DIO 17 - North Cook Inlet Unit; NCill A-I2 DIO 19 - Granite Point Field; W. Granite Point State 17587 #3 DIO 20 - Pioneer Unit; Well 1 702-15DA VVD\V DIO 21 - Flaxman Island; Alaska State A - 2 DIO 22 - Redoubt Unit; RU D1 DIO 23 - Ivan River Unit; IRU 14-31 DIO 24 - Nicolai Creek Unit; NCU #5 DIO 25 - Sterling Unit; SU 43-9 DIO 26 - Kustatan Field; KFl Storage Injection Orders SIO 1 - Prudhoe Bay Unit, Point McIntyre Field #6 SIO 2A- Swanson River Unit; KGSF #1 I SIO 3 - Swanson River Unit; I KGSF #2 Enhanced Recovery Injection Orders EIO 1 - Prudhoe Bay Unit; I Prudhoe Bay Field, Schrader . No rule Bluff Formation Well V-IOS Inj ection Order "Demonstration of Mechanical Integrity" 2 2 2 2 2 2 2 3 3 " .J 3 No rule 3 3 No rule 2 2 Affected Rules "Well Integrity Failure and Confinement" "Administrati ve Action" '" .J 4 3 5 3 6 " .J 5 3 Rule not numbered 3 5 3 6 4 6 4 6 4 7 No rule 6 No rule 6 Order expired 4 7 4 7 No rule No rule No rule 6 No rule 7 No rule 8 Injection Order EIO 2 - Redoubt Unit; RU-6 ....."...r "Demonstration of Mechanical Integrity" 5 ~ Affected Rules "Well Integrity Failure and Confmement" 8 "Administrative Action" 9 I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FR.Zvl STATE OF ALASKA ADVERTISING ORDER ·§EEBØ"f'1"OM:.f5ØR~ºfÇç?AD[)¡:æ$$ 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 R o M AOGCC 333 West ih Avenue, Suite 100 Aù1chorage,AJ( 99501 907-793-1221 AGENCY CONTACT DATE OF A.O. Joòy Colombie September )7, )004 PHONE pcl\¡ (907) 793 -]??] DATES ADVERTISEME:\fT REQVIRED: T o Journal of Commerce 301 Arctic Slope Ave #350 Aù1chorage, AK 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES MLST BE PRlNTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRVCTIO'lS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPUCA TE 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 Public Notices ',>,..,.'/ ~' Subject: Public Notices From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 29 Sep 2004 13:01 :04 -0800 To: undisclosed-recipients:;, _ BeC: Cynthia B Mciver <bren_mciver@adµún~ate.ak.u,s>,AngelaWebb <angie _ webb@admin.state.äk.us>, Robert E MiIitZ.<robert_tn!n~@laW.state.ak.U$>,~tine' . Hansen <c'.hansen@iogcc.state.ok.us>, T~rriè Hubble <hi1b1>letl@bp.coII1>~Soridrä Stewman <StewmaSD@BP .com>~, Scott & Cammy Tayl()f _<staylor@ataS~.,net> ,:stmek.j <stanekj@unocaI.com>, ecolaw <ecolaw@tnistees.org>, rose~dalè,<ro~agsdale@gci.net>, trmjr 1 <trmjr 1 @aoLçom>, jbriddle'<jbriddle@marathOl1Oi1.coID? ,rockhill' <roc~@aoga.·org>, shaneg <shaneg@evergreengas.com>, jc;farlington <jdarlington®f()~est~itcO~~,~t}lsoµ'- <knelson@petroleumnews.com>, cboddy <~ddy@USJ.~J~'.po~~Nark~DaIton , ' , <mark.dalton@hdrinc.com>, Shannon Donneny <shannon.Øò~eUY@c~11Ocophillips.com>~. ':~ark P. Worcester" <mark.p. worcester@conocophinip~.com>, "Jerry.C.Dethlefs" ." '. . . <jerry.c.dethlefs@Conocophillips.com>, Bob <bob@inletkeeper.org>, wdv<wctv@~nr $tate.ak.\;lS>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@aIaska.net>, tnjnelson <µIjn~~ri@purvitlgertz.com>, Çharles ODonnell <charles.o'donneIl@veco.com>j "RandyL. SkiUeI'rl" <~kiHeRf@BP .co~>, "Deborah J. Jones" <JonesD6@BP~con1>, "Paul G.Hyatt"<hy~g@BP.com>,'''Steven R.Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, DaµBr~s.~kuacnew&@kuac.org>, Gordon Pospisil <PospísG@BP~com>, "Francis S. SOIÌ1merH <So~erES@BP~com>, ~el Schultz <MikeLSchultz@Bp'~com>, "Nick W. Glover" <QloverNW@BP.'éom> ,"DarylJ.~IÇteppin" <K1eppiD:E@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, nRòs~eM. ~ac()bsen" <JacobsRM@BP .com.>, ddonkel <ddonkel@cfl.rr.com> ,CollinS :M~uni . <collins _ mount@revénue.state.~k.us>, mckay <mckày@gci.net>~. Båib~FFulImer <barbara.f.fuHmer@conocophillips.com> ~ bocastwf <bocastwf@bp.cQm>, .Gþarl~s~ark~ .. <barker@usgs.gov>, doug_schultze <doug_schultZe@Xtoenergy.~òm>; Hà.nkAlford " <hank.alford@exxonmobitcom>~, Mark Kovac ,<yesn() 1 @gcij¡~t?",. g$þ:foff· .. <gspfoff@aurorapower.com>,' Gregg Nady <gregg..nady@shell..eÓ1:I1>, :Fied ·Steecç <fred.steece@state.sdaUS>, rcrotty <rcrotty@ch2~.com>, jejones :<jejol1es@a~ompôWer.com>, dapa <c:Iapa@alaska.net> , Jroderick <jroderick@gci.net>" eyancy' <e~~Y~Ø-tit~.ï1f~t>~, n James· M; ~uudu <jatnes.m~ruud@conócoPl1illips.com>" Br.it Liyely <n:t~~a.@<dç~~,jah, , ' <jah@dnr.state.ak.us>, Kurt' E Olson <kurt:- olson@tegis:st~te.~~uS>,htÌoþ:oj~.,<1>tt0noje@bp.com?, Mark Hanley <mark.,...hanley@anadarko.com>, loren_ternan <lorep._Jetn(Ul{@gov.stat¢.ak~US>, Ju1ie Houle <'¡ulie_houle@dnr.state.ak.us>, John W·Katz<jwkatz@SsQ~org>,S~JJIiU . <suzan _ hill@dec.state.ak.tW, tablerk <tablerk@~no'?3l.c,om>:,~t;éKly <~~oga.~rg>, Brian Havelock <beh@dnr.state.~us>, 'bpopp <bpopp@bt>rough.kenaì~ak.US>~ Jim \Vhìte' <jimwhite@satx.rr.com>, uJobn S.,Hawortf:Ìfl <jòÏm~&haworth@~Xxo~~il:cotri>, rnady <marty@rkindustrial.com>, ghammons <ghammOris@åól.c~~QtJileài1- _ ' ' , <nTIc1ean@pobox.alaska.net>, tnlan 7200<mkm7?l~coni>¿~n$í~Gille$pi~ ~: <itbmg@1Í~~aSJca.edu~, David L Boel¢ns <dò~le~@âtlr~~w~raçø!Íl>, !op4 pllrkee <TDURKEE@KMG.com>, Gary Schultz <gary--"~hultz@dnr.s~a~.tlP; Wa~'~ancier <RANCIEk@petro-canada.ca>"Bill Miner <Bill ~Mifler@xtoål~1¥cprµ>~ 'Brahd~n"Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwilislovv@fOrestq:i1.ë;oril>; 'GärtyCatroo" <catrongr@bp.com>, ShaI1J1aine, Çopeland<co.peI(lSv@bp.~com~,$'UzaIJhe~ p¡Ìlex~". ' , " <:sallexan@helmenergy.com>, KriStin Dirks <krištip~dir~@dnr.~e;~~~,K:,!ynèU Zem~ <kjzeman@m~athOno~l.com>"JöhnTower <Jofu1.:Tower@~ia:dO~.gov>,B.ijì:Føwlet"" :- <Bill_ Fowler@anadarko.COM> ,'Vaughn Swártz<Vaùg6n~~waÍ1z@rbCctn:c()ßi>~.'SCott Cranswìck 10f2 9/29/2004 1:10 PM Public Notices <seotLcranswick@rnl11s.g()v>,· Brad McKirn <tncki.mhs@BR~c(HTI> ~~~al?e... fïl"lcl.·the...a.tt~?h~d···Nôt:i: ce·...and.·Attach1Tt~ntfor·t.l1~JÞr~R()i?~(ìªmendl11entÓf :tµlde:t:'groundinject;:ion orders· and the Public Notice HappyVaJ.1:ey.#-lO. Jþdy Colombie .. ..._..______.__....._......__.__..__.__.._...-.........__..._....-._....·___.._u.__·..··....··.·_ : ..... _» ....... ..... . .. .. .. ... ..iCol1,~¢Ì1t-'I'ype: a.ppTication/mswon:L: ¡Mechanlçal(níegrltyrpropo~al~t:I~J . ............. ................. ... ....... ......... ..... ...\.. ..... ..1;,.;..... ·&:A. ¡··Contept-F,nc~pJ.J1g;l)asÇWH' . __~__________ ~.__,_~_~"~.._____ _~~_._ ~ <. ·_n..________,·~_~v_____I_~..~,,_,,~... ICt)ntept·tr~pe: åpp~ícatìønÆ111sW"ø~(Í Mechanieál·fntegnty··ofWells Notice.doc¡........ ...... ..................m.. . ...... . ·····b· . ..·6.4.. : Content-Encoc.þng:·. ... age . _ ~ Content-Type:a.pplicél.tiowmswQrd Happy¥alleyt 0,- HeanngNotIce.doc ;.. C()ntent..EhlC{)tliJfg:Jjås~64 . - - - - ." .___~__.. n_·___'I__~'_.~_'_~___~ __4~__"'~,__ __.~._._ _~___,.. ~-?_._ -'-__.,"-__..__T___.._..'--......,.___. ._____m..;,.____...__________·_,_~_~...,.......-.- ._.__.___............_~_.__._..:.,_o_. 20f2 9/29/2004 1: 10 PM Public Notice .-............ -~ Subject: Public Notice From: lady Colombie <jody _ colombie@admin.state;ak.us> Date: Wed, 29 Sep 200412:55:26 -0800 To:.legal@alaskajòurn~.com Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Content-Type: applicationlmsword Mechanical Integrity of Wells Notice.doc Content-Encoding: base64 on.. _ u ._.._.._._._.....___..__._____ ."_._...__._du....__....____._"..._.____.._h..___......______...d____.._...__.__nh no __ Ad Order form.doc n _ _ _.._ _.___ __..___"_ _u_ _ ___ _.. _ ___.. uu_"___ 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 all~d /ú"/Í frlJ David McCaleb I IHS Energy Group GEPS 5333 Westheimer, Ste 100 Hous~n.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 Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1 655 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 Angeìes, 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, W A 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gam bell 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 190083 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,.,..,,,,,,,/ ~rs - Well Integrity ... '~ Subject: [Fwd; Re; Consistent WordÏ11gforInJ~ctioI1·0I"ders-W¢11mt~griW(It~visect)] From: John Nonnan <jo~ nonnan@admin.state~ak~u$> Date: Fri, 01 Oct 2004 11:09:26-0800 To: Jody J Colombie<jody___colombie@admin.state.ak.us> 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: i im regg@admin.state.ak. us CC:dan seamount@admin.state.ak.us, john norman@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> 8/25/20043:15:06 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 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 redlines on the second document attached. »> James Regg <jim regg@admin.state.ak.us> 8/17/2004 4:33:52 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 10f2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection .ers - \Vell Integrity... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent NUT s 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, 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 DIOs Administrative Actions - 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 oftenns 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. Norman <John Norman@admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission 20f2 1 f\ ¡1 ¡1f\(\A A .(\"'7 TH",f" .[Fwd: Re: Consistent Wording for Injection (__ :s - Well Integrity... ~' Subject: [Fwd: Re: Consistent Wording for Injection Orders~W¢l1Jn.têgrity(Revised)] From: John Nonnan <john_norman@admm.statë.ak.us> Date: Fri, 01 Oct200411:08:55 -0800 To: Jody JColombie·<jÖqy__colombie@admin.state.ak.us> 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@law.state.ak.us> To:dan seamount@¿admin.state.ak.us, Jim regg@admin.state.ak.us, john nonnan@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 <jim regg(G¿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 i\ilechanical 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 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 010 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 DIOs Administrative Actions 1 of 1. 10/2/20044:07 PM [Fwd: Re: Consistent \-Vording for Injection ers - \-Vell 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 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 John K. Nonnan <John Norman@!admin.state.us> Commissioner Alaska Oil & Gas Cooservation Commission Content-Type: applicationlrnsword Injection Order language - questions.doc Content-Encoding: base64 _.- - -- . -. -- _.-. -- -- - --- --.----"----- ---." - ---------- "----- ----------- -------------- -- - Content-Type: applicationlms\vord Injection Orders language edits.doc Content-Encoding: base64 20f2 1 nnnnnÆ ¡j ·n'i D~.f -'"""""---.... o.~ 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 Integrity 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 every two years in the case of a slurry injection \velI), and before rcturnin,g a \\7cl1 to service foJIo\vin.g a-ftef a workover affecting mechanical integrity, and at lellst once every 4 years whil~ actively injecting. For :;lurry injection \vells, the tubing/casing annulus inust be tested for mechanical integrity every 2 years. Unless an alternate lTIeanS is approved by the COlTInlission. Inechanìc.al integrity ITIUst be demonstrated by a tubin.g pressure test using a +he M±+-surface pressure of must be 1500 psi or 0.25 psilft multiplied by the vertical depth, whichever is greater, that m-H&t-showâ stabilizing pressure that does8.nd Inay not change more than 1 O~ percent during a 30 minute period. --Aflÿ altenlate illcans (}of dem.onstrat-ing mechanical integrity must be approved by the COInmission. The Commission must be notified at least 24 hours in advance to enable a representative to vvitness pressure tests. Well Integrity Failure and Confinement Except as othenvise provided in this rule, +!he tubing, casing and packer of an injection well must demonstrate Inaintain integrity during operation.\Vhenever any pressure conlillunlcation. leakage or lack of injection zone isolation is indicated by injection rate~ operating pressure obsen!ation~ test survey. log. or other evidence. t+he operator fRHSf-shaIl immediately notify the Commission and submit a plan of corrective action on ª-Form 10·403 for Commission approval.:. \vhenever a,ny pressure cOffilnunication, leakage or lack of injection zone isolation is indicated by injection rare. operating pressure t1bservatíon, test, survey. or log. The operator shall shut in the \vell if so directed bv the COITI111ission. The operator shaH shut Ín the \veIl \vithout a\vaitinJ2: a response from the COffilnission if continued operation \-vould be unsafe or would threaten contamination 0 f fresh waterIf there is no threat to freshwater, injection Inay continue until the Cornlnission requires the \\'elt to be shut in or secured. Until corrective action is successfully completed, 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. .[Fwd: Re: [Fwd: AOGCC Proposed WI Lang~_.: for Injectors]] \~' Sub~ect: [Fwd: Re: [Fwd: AOGCC Proposed WI Latiguage for Injectors]] From: Winton Aubert <winton~aubert@adInin.state.alclls> Date: Thu, 28 Oct 2004 09:48:53 -0800 To:JodyJColombie'<jôdy~ coloinbie@admin.state.ak.tis> 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 <EngelHR@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 _ç"1 1 ()J") SlJ")()()J. 1 1 .()Q AM [Fwd: Re: [Fwd: AOGCC Proposed \VI Lar ~e for Injectors]] returnj.ng a well to service following a workover affecting mechanical integrity. II 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 rater operating pressure observation¡ test¡ survey¡ log¡ or other evidence¡ the operator shall * irnrnediately*_** 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: IIAII 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 lithe operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-40311. 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 donrt consider an AA as IIcorrective 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 Ai Denis¡ John R (ANC) i Miller¡ 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 1012R0004 1 1 'OQ AM #9 bp -- "-t BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 December 18, 2002 BY U.S. MAIL RE: Polaris Pool Rules and Area Injection Order Supplemental Information RECEIVED DEe ,4Jaskao~/& 2. J 2002 11 Ga A S Cons (J, nOhoran' OfJ1l17íso'- }Ie "lor Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioners: We would like to provide the Commission with the attached supplemental information, "Reservoir Static Pressure Acquisition Area Map" (Exhibit VIII-I). We understand this Map may be placed in the public domain and used to better define the static pressure acquisition requirements as defined in our September 12,2002 Polaris Pool Rules and Area Injection Order Application (Rule 7, Page 54). Sincerely, /"-~~~ Gil Beuhler GPB Satellites Team Leader Cc: R. Smith (BP) M.M. Vela (ExxonIMobil) J.P. Johnson (ConocoPhillips) S. Wright (Chevron Texaco) P. White (Forest Oil) ris Pool/Injection A Reservoir Static Pressure Acquisition Area Map Schrader Bluff reservoir static pressure acquisition areas. Polaris Production Well . 11<221112! Key Regional Polaris Definition Well Exhibit VIII-1. Polaris Pool and Proposed Participating Area Boundary #8 bp . GPB RESOURCE DEV . l4I002 12/13/2002 14:34 FAX B P Exploration (Alaskall nc. 900 East Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (9071561-5111 December 13, 2002 BY FAX AND U.S. MAIL Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Polaris Pool Rules and Area Injection Order Application Confidentiality of Exhibits 1-6 and 1-7 Dear Commissioners: At the hearing on December 9, 2002, you asked if the applicants consider Exhibits 1-6 and 1-7 to the Polaris Pool Rules and Area Injection Order Application ("Application") to be confidential because the exhibits contain trade secrets. The answer is "yes," the Polaris Owners do consider Exhibits 1-6 and 1-7 to be confidential because they contain trade secrets. AS 45.50.940(3) provides that information qualifies as a trade secret if it "(A) derives independent economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from its disclosure or use, and (B) is the subject of efforts that are reasonable under the circumstances to maintain its secrecy." These exhibits include interpretations of geological and geophysical data, including reservoir compartments and polygons, reservoir characteristics, faults, structure and isopach maps, and the like, from which the Polaris Owners derive independent economic value. These exhibits also reflect our use and application of the information, which provides us with a competitive advantage over others who do not have it. This information is not generally known to or ascertainable by other persons, and other persons would obtain economic value from it. The Polaris Owners take significant and reasonable measures to maintain its secrecy. For these reasons, the exhibits are required to be held confidential by the Commission. In addition, as you know, the Polaris Owners also consider these exhibits to be confidential because they contain engineering, geological and other information that is being voluntarily provided to the Commission that is not required to be provided under AS 31.05.035(a). Therefore, these exhibits must also be held confidential under AS 31.05 .035( d). -'\lasKø \. 1, .i 12/13/2002 14:35 FAX GPB RESOURCE DEV 4t ~003 - We are somewhat at a loss about why the Commission is requesting this further explanation. We are unaware of any request for public disclosure of these exhibits, and there was no adverse party at the hearing, thus completely obviating any due process basis for disclosure. Moreover, in our view these two exhibits go above and beyond what the Commission needs to rule on the application. Therefore, we question the basis and procedure for any action by the Commission relating to the confidentiality of these exhibits in the present context. Consequently, if the Commission is considering issuing an order making these exhibits public, please let us know, for we may wish to withdraw them from the application. We understand that, with the submission of this letter, the AOGCC will consider the record to be closed. Sincerely, ~~ Oil Beuhler GPB Satellites Team Leader Cc: R. Smith (BP) M.M. Vela (ExxonIMobil) J.P. Johnson (ConocoPhillips) S. Wright (Chevron Texaco) P. White (Forest Oil) #7 . e AOGCC December 9,2002 .. Page 1 1 2 3 ALASKA OIL AND GAS CONSERVATION COMMISSION ',/ PUBLIC HEARING ----------------------------------------- In Re: 4 Application by BP Exploration For 5 Polaris Pool Rules and an Area Injection Order. 6 7 8 ----------------------------------------- TRANSCRIPT OF PROCEEDINGS 9 10 Anchorage, Alaska December 9, 2002 9:00 o'clock a.m. COMMISSIONERS: CAMMY OECHSLI TAYLOR, Chairperson DAN SEAMOUNT MIKE BILL . 11 12 13 14 15 16 17 18 19 20 21 22 23 24 * * * * * * RECEIVED tr5 DEC 1,3 2002 l\løRaon & Gas Cons. Gommlssioll Am::horage 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net . tÞ1 Page 2 PROCEEDINGS (On record) CHAIR TAYLOR: Good moming, I'd like to call this hearing to order. Today is Tuesday, December 9th, 2002. The time is approximately 10 minutes after 9:00. We're at the AOGCC offices at 333 West Seventh, Suite 100. The subject of the hearing today is BP's application for Polaris Pool Rules and Area Injection Order. I would like to introduce to my left Commissioner Mike Bill, to my right Commissioner Dan Seamount. My name is Cammy Taylor. To my very far right is Julie Gonzales, she is here from Metro Court Reporting. This will be recorded and transcribed. Anybody wishing to secure a copy of that transcript may do so directly through Metro Court Reporting. The notice of the public hearing was published in the Anchorage Daily News on November 8th, 2002. We will conduct these proceedings today in accordance with our regulations, 20 AAC 25.540. We would like the applicant to present testimony first. If there are any others wishing to present testimony, we'll hear from them after that. We would ask that all persons wishing to testifY be sworn and that each witness state their name and if they would spell it for the record so that it can be transcribed correctly. If you'd identifY who you represent. Any person wishing to provide expert testimony today, 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 3 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 .25 we will ask that you state your qualifications and the Commission will make a determination about your qualifications and for what field you're wishing to be sworn as an expert. Any persons wishing to make an unsworn statement, we'll take those after all of the testimony is taken today. We also ask that if persons in the audience have questions, they not direct questions directly to the witnesses, but if you would write them down, state the question, your name, and who you would like the question directed to, you may give that piece of paper to one of the Commission members. And we have four people, I think, sitting in the audience who could take those. If you would just raise your hands. If you want to have a question passed to them, they will make sure that it comes up to the front. The Commission will review them and make a determination about asking the question. We would like to invite the applicant to introduce themselves and proceed with their presentation today. MR. BEUHLER: Thank you. Good morning, thank you for your time today. My name is Gil Beuhler. My surname is spelled B-e-u-h-I-e-r. I am the Greater Prudhoe Bay satellite resource manager for BP Exploration Alaska. I received a Bachelor of Science Degree in Petroleum Engineering from the University of Kansas in 1983. CHAIR T AYLOR: Mr. Beuhler, could I interrupt you for just a second? Do you want to go ahead and proceed with your e AOGCC December 9,2002 Page 4 I 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 testimony and your sworn statement at this time? MR. BEUHLER: Yes, ma'am. CHAIR T AYLOR: Why don't I swear you in. (Oath administered) MR. BEUHLER: I do. CHAIR TAYLOR: Thank you. MR. BEUHLER: Thank you. I've worked in the oil industry for over 19 years with a variety of experience in the Lower 48 and Alaska. I've been in Alaska since 1997 and have been with BP since 1998. I joined the Greater Prudhoe Bay satellite team in 1998 and I have testified as an expert witness in Texas before the Railroad Commission, in New Mexico before the New Mexico Oil Conservation Division, and in Alaska before this Commission at the Borealis Pool Rules Hearing. And I would like to be acknowledged today as an expert witness. CHAIR TAYLOR: Commissioner Bill, do you have any questions or any objections? COMMISSIONER BILL: No questions, no objections. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: I have no questions nor objections. CHAIR TAYLOR: You can proceed with your testimony as an expert witness. MR. BEUHLER: Okay, thank you. We have prepared the Page 5 I 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Polaris Pool Rules and Area Injection Order application submitted on September 12, 2002, and revised as of this date, October 31 st of 2002, and we ask that the Commission enter in its entirety this application into the record. CHAIR TAYLOR: The Commission will do so. MR. BEUHLER: Thank you. And for the purposes of this hearing, we offer excerpts from that application, if it pleases the Commission. Thank you. And the first section, entitled geology, will be presented by Greg Bernaski. CHAIR TAYLOR: Greg, do you wish to be sworn in as an expert witness today? MR. BERNASKI: I do. CHAIR TAYLOR: Would you raise your right hand, please? (Oath administered) MR. BERNASKI: I do. CHAIR T AYLOR: And you wish to be sworn as an expert in the field of petroleum geology? MR. BERNASKI: Yes. CHAIR TAYLOR: Please proceed. MR. BERNASKI: My name is Greg Bernaski. My surname is spelled B-e-r-n-a-s-k-i. I am a geologist with BP Exploration Alaska. I received a Bachelor of Science degree and a Master of Science degree in geology from the University of Wyoming. I've been employed as a geologist by BP, and the 2 (Pages 2 to 5) 907.276.3876 METRO COURT REPORTING, INC. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e tÞ\ Page 6 Sohio Petroleum Company, for 17 years. I've worked on a variety of Alaskan projects since 1993, including Prudhoe Bay, Ivishak, and Sag River reservoirs, and the Polaris and Orion Schrader Bluffreservoirs. I've been working with the Greater Prudhoe Bay satellites team since December, 1998. Prior to joining BP in Alaska, I worked on deep water field appraisal and development projects for BP in the Gulf of Mexico. I would like to be acknowledged today as an expert witness in geology. CHAIR TAYLOR: Commissioner Bill, do you have any questions? COMMISSIONER BILL: No questions nor objections. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: No questions, no objections. CHAIR TAYLOR: We'll consider you an expert witness for your testimony today. Go ahead and proceed. MR. BERNASKI: Thank you. The area for which the Polaris Pool Rules are proposed is located within the Prudhoe Bay Unit, or PBU, on Alaska's North Slope, as illustrated in Exhibit I-I. The Polaris Pool overlies the PBU Sadlerochit reservoir in the vicinity ofPBU S, M and W Pads and overlies the Aurora Pool Kuparuk River formation reservoir in the vicinity ofPBU S Pad. The reservoir interval for the Polaris Pool is the Schrader Bluff and the lower U gnu formations. Within the Polaris Pool, the Schrader Bluff and lower U gnu 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 7 I formations are divided into 14 distinct sand units encompassed 2 by the 0 and N intervals, 0 sand intervals of the Schrader 3 Bluff, and the M sand interval of the lower Ugnu. 4 The North Kuparuk state 26-12-12 well, drilled in 5 1969, was the first well to penetrate and log hydrocarbons in 6 the Polaris Pool. Since 1969, the Polaris Pool interval has 7 been logged in 64 Schrader Bluff penetrations in PBU Ivishak, 8 Kuparuk, and Schrader Bluff development and appraisal wells in 9 the Polaris Pool area. Polaris Pool hydrocarbon presence is 10 recognized from log data from 59 Polaris Pool wells which have II at least gamma ray and resistivity log data. 12 Exhibit 1-2 shows the location of the Polaris Pool 13 area. Exhibit 1-2 also shows that the boundaries of the 14 Polaris Pool area coincide with the boundaries of the Polaris 15 Participating area. Two boundaries are the same. The Polaris 16 Pool hydrocarbon accumulation is bounded by faults on the 17 updip west and south sides and by dip closure into the 18 regional aquifer on the north and the east side. 19 As shown on the Schrader Bluff structure map in 20 Exhibit 1-3, the Polaris pool -- excuse me, the Polaris 21 structure crests at W Pad in the southwest Polaris Pool 22 region, minus 4800 feet TVD subsea at the mid Schrader Bluff 23 OA mapping horizon, and trends down dip to the north and to 24 the east through faulting and regional dip. North-south, 25 east-west, and northwest-southeast trending faults subdivide e AOGCC December 9,2002 I 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 8 the Schrader Bluff reservoir into discrete high-standing and low-standing fault blocks within the Polaris Pool area. Sealing faults are predicted in the Schrader Bluff reservoir based on the prevalent low net to gross reservoir lithologies. At this point, I'll make a comment on a matter of procedure. The Polaris Pool Rule document contains a number of confidential exhibits. We will refer to these exhibits during the course of our testimony, but do not intend to display them on the overhead projector. For your reference, these confidential exhibits do exist in the Polaris Pool Rules copy which I believe each of the Commissioners has in front of you. So we'll proceed in that fashion. Confidential Exhibit 1-4 shows the Polaris Pool fluid limits in relation to regional structure features along a cross section line connecting the Wand S Pad areas. Based on differences in rock quality and potential spill points for the various sand units, it is believed that oil-water contacts vary by depth -- excuse me, contact depths vary by sand unit and by fault block within the Polaris Pool. All current Polaris Pool production is from the Nand 0 sands at S Pad, and from the OB sands only at W Pad. Exhibit 1-5 shows the open-hole wireline log character of the Schrader Bluff and lower Ugnu M, N, and 0 sands in a type log from the S-200PBI well and illustrates the vertical stratigraphic extent of the Polaris Pool. As shown in Exhibit Page 9 I 1-5, the Polaris Pool M, N, and 0 sands are further subdivided 2 into seven 0 sands, three N sands, and four M sands. The 0, 3 N, and M sand intervals are present across the entire Polaris 4 Pool area and, as a package, thin slightly from southwest -- 5 south-southwest to north-northeast across the Polaris Pool 6 area. Reservoir quality sand units within each interval are 7 regionally extensive but can be locally characterized by 8 substantial thickness and net to gross variations between 9 wells spaced less than 1000 feet apart. 10 The contact between the basal Schrader Bluff 0 sands II and the underlying Colville section is gradational from the 12 Colville mudstones to the basal Schrader Bluff low 13 permeability sands. Colville mudstones and muddy siltstones, 14 ranging up to 1100 feet thick at Polaris, form the basal IS confining unit of the Polaris Pool. The top of the Ugnu M 16 sand interval is characterized by an upward gradation from a 17 silty fining upward Ma sands to a regionally continuous 10 to 18 25 foot thick mudstone which isolates the M sands from 19 overlying fluvial U gnu sands. This upper mudstone forms the 20 upper confining layer ofthe Polaris Pool. 21 The lowermost Polaris Pool unit, the Schrader Bluff 0 22 sand interval, forms the primary development target in the 23 Polaris Pool and is subdivided into seven -- seven separate 24 reservoir horizons, from deepest to shallowest, the OBf, the 25 OBe, the OBd, OBc, OBb, OBa, and OA. The total 0 sand 3 (Pages 6 to 9) 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e .] Page 10 interval thickness ranges from 300 to 340 feet at Polaris. In general, each of the 0 sand intervals clean upward from basal non-reservoir laminated muddy siltstone to reservoir quality laminated and thin-bedded sand units at the top. The Polaris Pool N sand interval overlies the 0 sand interval and ranges between 100 and 160 feet thick in the Polaris Pool area. Polaris Pool N sands are subdivided into three reservoir units, from deepest to shallowest, Nc, Nb, and Na. The N sand interval consists mainly of non-reservoir muds and siltstones interbedded with a limited number of thin, but generally extensive, unconsolidated reservoir sands. Thick, regionally extensive mudstones within the lowennost N sand interval fonn an important regional vertical barrier which segregates the lighter, higher quality oil in the 0 sands from -- from heavy oil and extensive wet sands in the N and the M sand interval. The Polaris Pool M sand interval overlies the N interval and ranges between 180 and 250 feet thick in the Polaris Pool area. Polaris Pool M sands are subdivided into four reservoir units, from deepest to shallowest Mc, Mb2, Mb I, and Ma. The M sand interval consists of very high quality unconsolidated clean sands separated by generally thin, but extensive non-reservoir mudstone units. Mudstones within the M sand interval vertically separate individual hydrocarbon and 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 11 1 water-bearing M sand units, even in highest net to gross 2 units, and provide competent top seals to the Polaris Pool 3 development interval. M sand hydrocarbons consist of heavy, 4 biodegraded crude, 12 to 14 degree API gravity, based on 5 fluids extracted from sidewall and conventional core plug 6 samples. To date, no M sand production has been attempted and 7 no M sand downhole oil sampling has been successful. 8 Schrader Blufffonnation Structure. Exhibit 1-3 is a 9 structure map on the top of the Schrader BluffOA sand in the 10 Polaris Pool area, with a contour interval of 20 feet. II Although the Schrader Bluff interval generally dips eastward 12 and northward at gentle dips of 0 to 4 degrees in the western 13 portion of the Prudhoe Bay unit, it is -- it is broken up into 14 a series of distinct fault blocks, as indicated by 3D seismic 15 data. The structural character of the Schrader -- at the 16 Schrader Bluff level in the vicinity of the Polaris Pool is 17 dominated by three different fault trends. Northwest- 18 southeast, north-south, and east-west. 19 Structure in the S Pad and M Pad area consists of a 20 complexly faulted structural high, which plunges to the 21 southeast, where it is truncated by a large east-west fault 22 near M Pad -- N Pad, sorry. The structure is dominated by 23 northwest-southeast striking pair of antithetic faults which 24 intersect a large north-south trending, west-dipping fault 25 system. The northwest-southeast antithetic pair subdivides . e AOGCC December 9, 2002 Page 12 I the Sand M Pad structure into three major fault -- three 2 major fault sub-blocks. A crestal area and northeast-dipping 3 flank, with S-200 and S-201 in the fault block. A crestal 4 graben located between the two northwest-southeast faults, 5 which runs from just south of the S Pad surface location to 6 just south of the M Pad surface location. A fault-bounded 7 structural high south of the graben, with development wells S- 8 213 and S-216 situated in the third fault block. 9 Tenn Well C Area. Tenn Well C, or TW-C, is located in lOa saddle downdip from the structural high at W Pad to the II south, and down thrown by faulting from the southern S and M 12 Pad fault block. A long, north-south fault lies to the west. 13 TW-C appears to be separated ftom the V-200 fault block by 14 small offset faults, some of which are inferred from fluid 15 contact data. A fault system separates the Tenn Well C block 16 from the southern S Pad fault block. 17 The structural trap at W Pad is fonned by the 18 intersection of a major northwest-southeast oriented fault 19 with a large-offset north-south trending fault system, with 20 dip closure to the east and north -- northeast. The downdip 21 extent of the structural closure to the southeast is dependent 22 up the juxtaposition of several sand intervals across, and 23 clay smearing along a small east-west trending fault. The W 24 Pad trap appears to be less intensely faulted than the Sand 25 the M Pad areas. Page 13 I Reservoir compartments. Elements of each of the major 2 area fault systems were used to subdivide the Polaris Pool 3 into reservoir compartments for development planning purposes. 4 The location and areal extent of these reservoir compartments 5 is marked by the polygon boundaries shown in Confidential 6 Exhibit 1-7. Each compartment was defined along mapped fault 7 trends and was assumed to be hydraulically isolated by sealing 8 faults from adjacent compartments. The sealing character of 9 the faults fonning the compartment boundaries is inferred from 10 both limited fluid contact and pressure data at Polaris, and II from analog studies which show a high probability of clay 12 smear seals fonning along faults in the Polaris low net to 13 gross reservoirs. Polygon nomenclature is summarized below. 14 S and M Pad North, Sand M Pad Graben, S and M Pad 15 south, W Pad slash Tenn Well C polygon, K 22-11-12 polygon, 16 and the Horst Block polygon. 17 Confidential Exhibits 1-8 and 1-9 show the depths of 18 the interpreted oil/water contacts, or OWCs, in the M, N, and 19 0 sands in the Polaris Pool in the Sand M and W Pad areas. M 20 sand oil-water contacts are relatively well defmed by 21 existing well control. Nand 0 sand oil-water contacts are 22 less well defined due to the lack of well control in down 23 structure areas. No gas/oil contacts have been logged in any 24 Polaris sand nor is the presence of free gas in the Polaris 25 Pool n any of the Polaris Pool intervals predicted from oil 4 (Pages 10 to 13) 907.276.3876 METRO COURT REPORTING, INC. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e .] Page 14 PVT test results. Each sand in the Polaris N and 0 interval was assumed to be vertically isolated from overlying and underlying sand -- sands and was assumed to have a different associated oil-water contact depth. The Nand 0 sand expected case oil column heights at S and M Pad range between 210 feet at the OBfto 290 feet at the Nc interval. W Pad expected case oil column heights range from 35 feet in the OA sands to 290 feet in the OBc sands. In contrast to the minimal number of Polaris N and 0 sand fluid contacts logged, Mb and Mc oil-water contacts have been logged in numerous wells in the S, M, and W Pad areas. Ma sand oil- water contacts have not been logged in any Polaris well. Similar to the Polaris Nand 0 sand intervals, M sand oil- water contact levels logged in different M sand intervals indicate that each sand behaves as a separate reservoir unit. The limits of the Polaris Pool are defined by updip fault boundaries and downdip at the zero foot limits ofM, N, and 0 sand expected case net pay. Polaris is bounded on the west and south by northwest and northwest-southeast faults where the reservoir is juxtaposed against impenneable silts and mudstones of the upper Schrader Blufffonnation and the overlying Ugnu. To the east and north, the Polaris Pool limit is defined by the downdip intersection of the top of the reservoir with the expected case 0, N, and M sand oil-water contacts. 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 15 1 Confidential Exhibits 1-10, 1-11, and 1-12 show the 2 location of the proposed Polaris Pool Rules area in relation 3 to the Polaris Pool fault boundaries and expected case limits 4 of 0, N, and M sand net pay. Confidential Exhibit 1-10 is a 5 Polaris Pool composite 0 sand net pay map showing the combined 6 thickness and extent of the Polaris area OA through OBfsand 7 net pays in relation to the proposed Pool Rule and 8 participating area boundary. This map has a contour interval 9 of 10 feet. Confidential Exhibit 1-11 is a Polaris Pool 10 composite N sand net pay map showing the combined Na through II Nc sand net pay thickness, with a contour interval of five 12 feet. Confidential Exhibit 1-12 is a Polaris Pool composite M 13 sand net pay map showing the combined Ma through Mc sand net 14 pay thickness, with a contour interval of 10 feet. 15 Confidential Exhibits 1-13, 1-14, and 1-15 show the 16 limits of the Polaris Pool Rule area in relation to the 0, N, 17 and M sand oil pore-foot thickness contours, respectively. 18 Similar to the net pay maps in Confidential Exhibits I -10 19 through 1-12, the 0, N, and M oil pore-foot thickness maps 20 represent the combined oil pore-foot thickness for all of the 21 0 sands, in Confidential Exhibit 1-13, all of the N sands, 22 Confidential Exhibit 1-14, and all of the M sands, 23 Confidential Exhibit 1-15. 24 This concludes my testimony. 25 CHAIR TAYLOR: Commissioner Seamount, do you have any e AOGCC December 9, 2002 Page 16 1 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 questions? COMMISSIONER SEAMOUNT: Not at this time. CHAIR TAYLOR: Commissioner Bi11, do you have any questions? COMMISSIONER BILL: Not at this time. CHAIR TAYLOR: Thank you. Raise your right hand. (Oath administered) MR. REINTS: I do. CHAIR TAYLOR: Would you please proceed, identify yourself by name and spell your last name for the court reporter, please. MR. REINTS: My name is Rydell Reints. That's spelled -- my surname is spelled R-e-i-n-t-s. I am a reservoir engineer for BP Alaska, Inc., working as a reservoir engineer for the Polaris development project. I received a Bachelor of Science Degree in petroleum engineering from the Montana College of Mineral Science and Technology, or Montana Tech, in 1988. In that year I joined ARCO Alaska, which was later acquired by BP. I worked as operations engineer, both field- based and town-based, in Prudhoe Bay. In May of'95 I began my career as a reservoir engineer and have worked on -- .as a reservoir engineer on a variety of Alaska projects, including Prudhoe Bay, Midnight Sun, Borealis, Polaris, and Orion fields. I have been working in the Greater Prudhoe Bay satellites team since April of 1998. I would like to be Page 17 I acknowledged today as an expert witness in reservoir 2 engineering. 3 CHAIR TAYLOR: Commissioner Bill, do you have any 4 questions or any objections? 5 COMMISSIONER BILL: No questions, no objections. 6 CHAIR TAYLOR: Commissioner Seamount? 7 COMMISSIONER SEAMOUNT: No questions, no objections. 8 CHAIR TAYLOR: We'll accept you as an expert witness 9 in reservoir engineering. Please proceed. 10 MR. REINTS: Reservoir management and developed 11 scenarios for Polaris have been evaluated using pattem and 12 partial field reservoir simulation models. Analysis of well 13 spacing and pattern configuration were perfonned with the 14 simulation models to identifÿ well locations. Evaluations of 15 Polaris using the Polaris log model and reservoir simulation 16 models have identified water flooding as a viable development 17 option. Low recovery estimates for primary depletion are 18 influenced by low solution gas oil ratio, low initial 19 reservoir pressure, and viscous oil. 20 Porosity and penneability values were measured by 21 routine core analysis from S-200PBl and W-200PBl. 22 Confidential Exhibit II-I shows values for porosity and 23 horizontal penneability by zone that were used in the 24 reservoir simulation model. 25 Water saturations were characterized using a Leverett 5 (Pages 14 to 17) 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net ·1 . e Page 18 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 J-function to capture the variations in water saturation with variations in porosity and permeability. Each interval was assumed to have a separate oil/water contact. The contacts were varied in the model to represent various structural locations within the reservoir. Relative permeability curves for the Polaris accumulation are based on unsteady state relative permeability experiments on S-200PBl and W-200PBl core. The range of results was narrowed to a single curve that is nearly identical to the curve used to model the Schrader Bluff Pool in the Milne Point Unit. Confidential Exhibit 11-2 shows the relative permeability curve used in the reservoir simulation. Initial reservoir pressure is somewhat variable. Average initial reservoir pressure is estimated at 2,180 psi at 5,000 feet TVD subsea in the S Pad area, and 2,240 psi at 5000 feet TVD in the W Pad area. Reservoir temperature is approximately 98 degrees Fahrenheit at this datum. Reservoir fluid PVT studies were conducted on down- hole samples from the OBd, OBa slash OBb, and OA sands in S- 200 well, and from the OBdlOBe sand in W-200. PVT samples show significant variations in fluid properties both horizontally and vertically. Exhibit 11-3 shows a summary of fluid properties in the Polaris accumulation. The PVT properties used in reservoir simulation were derived from measured values. The PVT tables used to represent the S Pad Page 19 1 area are shown in Confidential Exhibit 11-4. 2 Estimates of hydrocarbon in place for Polaris are 3 derived from net oil pore-foot maps and reflect current well 4 control, stratigraphic and structural interpretation, and rock 5 and fluid properties. The current estimate of oil and gas in 6 place are as follows. For the Me sand, 25 million to 120 7 million barrels of oil in place, stock tank barrels. For the 8 N sand, 25 to 80 million barrels stock tank. For the 0 sands, 9 300 to 550 million stock tank barrels. For a total for the 10 Schrader in the Polaris area of 350 to 750 million barrels 11 stock tank. Original gas in place is estimated at 84 to 250 12 bcf. 13 Two wells, S-200 and W-200, have been tested long- 14 term. Stable production has been established in W-20l and S- 15 213. Since the submittal of this application, stable 16 production has been established in S-20l, W-2ll, and W-203 as 17 well. Exhibit IV -1 shows a representative well test results 18 for all Polaris wells. 19 Several reservoir models using data from the Polaris 20 Pool were constructed to evaluate development options, 21 investigate reservoir management practices, and generate rate 22 profiles. Development options evaluated for the Polaris Pool 23 include primary depletion and water flood. Preliminary 24 screening of miscible gas flooding is also in progress. Model 25 results indicate that primary depletion would recover it AOGCC December 9, 2002 Page 20 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 approximately five to 10 percent of the developed area oil in place. Low primary recovery is a result of a combination of low GaR, low initial reservoir pressure, and viscous oil. Water flood has been identified as a viable development option for Polaris. It is anticipated that overall field development will involve 15 to 25 injectors and 25 to 35 producers. Water flood recovery ranged from 15 to 30 percent of OOIP, inclusive of primary recovery, in the developed area at one and a half hydrocarbon pore volumes injected. Polaris water flood oil and water production and injection forecasts are shown in Exhibit 11-5. Simulation and development planning efforts show that horizontal wells have the potential to enhance rate and recovery in some areas while reducing development costs and minimizing facility expansion requirements. Horizontal well potential is currently being evaluated in the W Pad area where the target has been narrowed to three sands, the aBa, aBc, and OBd. A tri-lateral well, W-203, that targeted approximately 3,500 feet of horizontal section in each of these three sands has been drilled and is currently on production. Initial development will take place in a step-wise approach, working from the crests towards the outer limits of the Pool, incorporating data gathering necessary to refine development plans. Phase I development focuses on developing and establishing water flood operations in select portions of Page 21 1 three primary areas. Phase I development will be used to 2 validate the development assumptions and refine Phase II and 3 III development plans. 4 Sand M Pad north block development includes 5 sidetracking S-200 to repair a split liner, then converting 6 the well to injection to support wells S-20l and other 7 potential wells. Aurora well S-104i will provide additional 8 crestal production -- will provide support for additional 9 crestal producers through commingled injection in the Schrader 10 Bluff and Kuparuk. Development of the S and M Pad south block 11 consists of two existing producers, $-213 and $-216, and 12 planned supporting injector $-2l5i. 13 Phase I development in the W Pad area consists of 14 drilling one producer, W-211, and supporting injector, W-2l2i, 15 which will also support existing well W-200. A tri-lateral 16 horizontal well, W-203, in the downdip area ofthe W Pad 17 polygon, has recently been drilled. It is anticipated that 18 offset injectors will be planned once horizontal well 19 performance has been evaluated and incorporated into the 20 development plans. 21 Phase II development is directed at completing 22 development in the -- development in the north, graben, and 23 south S Pad polygons, and W Pad polygon, and the K22-ll-l2 24 polygon. The Phase II drilling program is designed to access 25 down-dip areas with higher water saturation as well as higher 6 (Pages 18 to 21) 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net . .1 Page 22 risk, structurally complex areas. Polaris Phase III development would involve developing areas that require improved understanding of fault transmissibility and presence, or refinements in drilling techniques to reach the targets. Phase II results and performance data will be key in moving forward with Phase III areas. Due to faulting, the patterns are expected to be irregular and wells may be areally very close to adjacent wells, but will be isolated due to reservoir compartmentalization. To allow for future flexibility in developing the Polaris Pool and tighter well spacing across fault blocks, a minimum well spacing of 20 acres is requested. The objective of the Polaris reservoir management strategy is to operate the Pool in a manner that will maximize recovery consistent with good oil field engineering practices. The reservoir management strategy for the Polaris Pool will continue to be evaluated throughout the life of the field. CHAIR T AYLOR: Would you raise your right hand? (Oath administered) MR. MATTISON: I do. CHAIR TAYLOR: Could you please state your full name for the record and spell your last name for the court reporter? MR. MATTISON: My name is Scott Mattison, and my 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 23 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . surname is spelled M-a-t-t-i-s-o-n. I'm an Engineer with BP Exploration Alaska, currently working as a facility engineer for the Polaris Project. I received a Bachelors degree in science in chemical engineering rrom Louisiana State University. I joined BP in June 2000 via the acquisition of ARCO. I had worked for ARCO in Alaska on a variety of projects since 1981. I've been with the Greater Prudhoe Bay satellite team since July 2001, and I have testified as an expert witness in Alaska before the AOGCC in previous hearings. CHAIR TAYLOR: Do you wish to be qualified as a facilities engineer? MR. MATTISON: Yes, I do. CHAIR TAYLOR: Okay. Commissioner Bill, do you have any questions or any objections? COMMISSIONER BILL: No questions, no objections. CHAIR T AYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: I have no questions nor objections. CHAIR TAYLOR: Okay. Please proceed, we'll consider you an expert witness for purposes of this hearing. There's water in that pitcher, too, if you'd like. MR. MATTISON: I hope my whistle will hold out. Polaris wells will be drilled from existing IP A drill sites, M Pad, S Pad and W Pad, and will utilize existing IP A pad e AOGCC December 9,2002 Page 24 1 facilities and pipelines to produce Polaris fluids to 2 Gathering Center 2 for processing and shipment to Pump Station 3 1. Polaris fluids will be commingled with IP A fluids on the 4 surface at the respective well pads to maximize use of 5 existing IP A inrrastructure, minimize environmental impacts, 6 and reduce costs, and maximize recovery. 7 The GC-2 production facilities to be used include 8 separating and processing equipment, inlet manifolds and 9 related piping, flare systems, and onsite water disposal. 10M Pad, S Pad and W Pad have been chosen as surface 11 locations for Polaris wells to reach the expected extent of 12 the reservoir while minimizing new gravel placement, 13 minimizing well step out, and allowing the use of existing 14 facilities. An expansion of existing S Pad to accommodate 15 additional wells was completed in April 2000. A schematic of 16 the S Pad drill site layout, including contemplated Polaris 17 facilities, is shown in Exhibit III-2. And there's space for 18 one additional Polaris well on the northern pad. 19 Schematics of existing M Pad and W Pads are included 20 as Exhibits III-3 and III-4. 21 A trunk and lateral production facility capable of 22 accommodating up to 20 Polaris wells is planned as an 23 extension to an existing S Pad manifold system. The size and 24 type of well tie-in manifold system required at M Pad and W 25 Pad have not been determined. Water for the water flood Page 25 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 operations will be obtained by extending an existing 6 inch water injection supply line at S Pad. Should water injection pressures be insufficient, injection pressure will be boosted locally. Artificial lift will be performed either with artificial lift gas or with jet pumps using injection water as the power fluid. It is anticipated that the water for water flood operations, artificial lift gas, and MI, if needed, can be supplied to Polaris wells at M Pad and W Pad from the existing pipeline inrrastructure. Should injection pressure be insufficient for Polaris requirements, it could be boosted locally. Wells will be tested using existing well test facilities at S, M and W Pads. Wells will be put into test using either automated or manual divert valves. And this is a slight modification to the document as submitted, which said automated divert valves. The divert valves on north S Pad are manual. Well pad data gathering will be performed both manually and automatically. The data gathering system will be expanded to accommodate the Polaris wells and drill site equipment. No modifications to the GC-2 production center will be required to process Polaris production. And that concludes my discussion of the facilities. 7 (Pages 22 to 25) 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 rnetro@gci.net e .] Page 26 CHAIR TAYLOR: Commissioner Bill, do you have any questions? COMMISSIONER BILL: Not at this time. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: No questions. CHAIR TAYLOR: Thank you. Would you raise your right hand? (Oath administered) MR. SCHMOHR: I do. CHAIR TAYLOR: Thank you. Would you please provide your name and spell your last name for the court reporter? MR. SCHMOHR: Okay. My name is Donn Schmohr. My sumame is spelled S-c-h-m-o-h-r. I'm an engineer for BP Alaska Exploration, currently working as a petroleum engineer for the Polaris development project. I received a Bachelor of Science Degree in mechanical engineering in 1977 from the University of Nebraska. Ijoined Sohio, which was acquired by BP, in March of 1980, and have worked in Alaska on various projects since 1980. I have taken po stings in Dead Horse; Midland, Texas; London, England; Bogota, Colombia; and Anchorage. I've been working with the Greater Prudhoe Bay satellite development team since March 1999. I'd like to be acknowledged today as an expert witness in petroleum engineering. CHAIR TAYLOR: Commissioner Bill, do you have any 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 27 1 questions or objections? 2 COMMISSIONER BILL: No questions, no objections. 3 CHAIR T AYLOR: Commissioner Seamount? 4 COMMISSIONER SEAMOUNT: I have no questions nor 5 objections. 6 CHAIR TAYLOR: Please proceed, we'll consider you an 7 expert in the field of petroleum engineering. 8 MR. SCHMOHR: Okay, thank you. A number of 9 exploration and appraisal wells, and development wells, that 10 targeted the deeper Kuparuk and Ivishak production have been 11 drilled and logged in the Schrader Bluff formation. However, 12 only the recently drilled S-200, S-201, S-213, S-215i, S-216, 13 W-200, W-201, W-203, W-211 and W-212i have been drilled and 14 completed in the Polaris Pool. These well locations are 15 shown in Exhibit 1-2. They're the -- they're the wells -- the 16 wells located with the squares here are the existing wells. 17 Polaris development wells will be directionally 18 drilled utilizing drilling procedures, well designs, and 19 casing and cementing programs similar to those currently used 20 in the Prudhoe Bay Unit and other North Slope fields. Surface 21 hole will be drilled no shallower than 500 feet TVD below the 22 base of permafrost level. 23 The production hole will be drilled below surface 24 casing to a target depth in the Schrader Bluff formation, 25 allowing sufficient rathole to facilitate logging. Production e AOGCC December 9,2002 Page 28 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 casing will be set from the surface and cemented. Multi- lateral, horizontal and conventional wells may be drilled at Polaris. The horizontal and multi-lateral well completions could be perforated casing, slotted liner, barefoot section, or a combination. All conventional wells will have cemented and perforated completions. Fracture stimulation may be necessary to maximize well productivity and injectivity. Polaris wells will be completed in a single zone, the Schrader Bluff formation. Injectors may be single or multi- zone, Kuparuk, Schrader Bluff, Sag and/or Ivishak Formations, utilizing a single string and multiple packers as necessary. As shown in the typical well exhibits, IV-2, for conventional producers, and Exhibit IV-3 for a conventional injection well, and Exhibit IV-4 for a multi-zone injector. A sufficient number of mandrels will be run to provide flexibility for varying well production volumes, gas lift supply pressure, and water-cut. Additionally, jewelry will be installed so that jet pumps can be utilized, providing further flexibility for artificial lift. The injectors will be designed to enable multi-formation injection where appropriate to the Kuparuk, Schrader Bluff, Sag or Ivishak formations. Open hole electric logs may supplement or replace logging well drilling, logging, including gamma ray, resistivity, density and neutron porosity and other logging tools when wellbore conditions allow their use. The Page 29 1 horizontal wells and multi-lateral wells will typically 2 utilize seven inch intermediate casing set in the Schrader 3 Bluff formation. The reservoir section will be drilled with a 4 six and one-eighth inch horizontal production hole, completed 5 with a four and a half inch or three and a half inch slotted 6 or solid liner, and cemented and perforated as necessary. 7 All well completions will be equipped with a nipple 8 profile at a depth just below the permafrost should the need 9 arise to install a downhole flow control device or pressure 10 operated safety valves during maintenance operations or for 11 future MI service. 12 Fracture stimulation has been implemented for all 13 vertical Polaris producers drilled to date and may be 14 implemented in the future to mitigate formation damage, for 15 sand control, and to stimulate Polaris wells. 16 An updated isobar map of reservoir pressures will be 17 maintained and reported at the common datum elevation of 5,000 18 feet TVD subsea. An initial static reservoir pressure will be 19 measured on each producer or injection service well. A 20 minimum of one reservoir pressure will be taken each year in 21 each of the six Polaris reservoir polygon areas when at least 22 one Polaris production well has been completed in the 23 respective polygons. 24 Surveillance logs may be periodically run to help 25 determine reservoir performance, for example, production 8 (Pages 26 to 29) 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e .] Page 30 profile and injection profile evaluations. Surveillance logs will be run on commingled injection wells annually to assist in the allocation of flow splits. Approval is requested to complete commingled injectors where deemed prudent, including approval for commingled water injection in well S-104i in the Aurora and Polaris pools. Well S-104i is completed with isolation packers and injection mandrels, which will allow multi-zone water injection. Installing a restrictive orifice in the injection mandrels will control injection rates. Polaris production allocation will be done according to the PBU Western Satellite Production Metering Plan, described in the letter dated April 23rd, 2002. Allocation will rely on perfonnance curves to detennine the daily theoretical production from each well. The GC-2 allocation factor will be applied to adjust the total Polaris production. All new Polaris wells will be tested a minimum of two times per month during the first three months of production. A minimum of one well test per month will be used to tune the perfonnance curves and to verifY system perfonnance. Regarding the area injection operations. This application requests authorization for water injection to enhance recovery from the Polaris Pool. The proposed area of injection operations is the Polaris Participating area outline. 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 31 BP Alaska -- BP Exploration Alaska is the operator of the Polaris Participating area. The application contains an affidavit showing that the operators and surface owners within a one-quarter mile radius of the area and within the Polaris Participating area have been provided a copy of this application for injection. Fluids requested for injection for the Polaris Oil Pool are: produced water from the Polaris or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance enhanced -- and enhanced recovery; tracer survey fluid to monitor reservoir perfonnance; fluid injected for purposes of stimulation; source water from the seawater treatment plant. Now I'd like to speak to the mechanic integrity of wells within a quarter mile of the injectors. Exhibit VIl-2 shows all Schrader bluff penetrations at the Ma sand, and a quarter mile radius is shown around the location of the point at which each existing and currently-planned injection well is estimated to intersect the top of the MA sand. So these are each one of the injectors with a quarter mile radius. And these are all the penetrations in the MA sand. Currently, there are three Polaris injection wells that have been drilled and cased, W-212i, S-215i and S-104i, which is the dual Kuparuk and Schrader Bluff injector. This application also provides infonnation on the area of review for two additional proposed injection wells, W-207i and S- 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . e AOGCC December 9,2002 Page 32 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 200i, which are planned to be drilled in the near future. Standards of mechanical integrity. The following application -- or this application assumes that the standards in the Commission s regulations apply to the operations described in the Application. In particular, a Polaris Pool injection well is considered to have mechanical integrity if it satisfies the requirements provided in 20 AAC 25.412, and a Polaris production well is considered to have mechanical integrity if it is cased and cemented in accordance with 20 the regulations. Standards of Confinement. A penetration not completed within the Polaris Pool is considered to provide confinement if injection fluids within the Polaris Pool if calculations show the top of cement is above the top of the Ma sand and the cement job appears to have been pumped successfully, or if cement evaluation logs are available that show cement above and below the Schrader fonnation, or if the penetration is far enough from the injector that it is reasonable to assume the reservoir pressure at that point will not rise above original reservoir pressure. Zonal isolation in the Schrader Bluff at the W -17 Schrader Bluffpenetration needs to be addressed. W-212i, is located 255 feet from the W-17 penetration. W-17 is currently a low rate, shut-in, and secured Ivishak producer that has confinned holes in the tubing. There are conceptual plans to Page 33 I use this well in the future as an Ivishak injector. That's W- 2 17. After extensive review of the W -17 completion, we cannot 3 provide assurance that there will be zonal isolation since the 4 calculated top of cement on the nine and five-eighths casing 5 is very close to the Schrader Bluff. There is no cement 6 evaluation tool available that can log through tubing and 7 casing to detennine if there is cement and zonal isolation in 8 W-17. 9 We propose to perfonn a baseline temperature survey on 10 W-17 prior to injecting in W-212i and perfonn subsequent 11 temperature surveys at two, five and eight months after 12 initiating water injection. In addition, we will provide the 13 AOGCC evidence of zonal isolation within 12 months of 14 commencing water injection, or shut in W-212i. Evidence of 15 zonal isolation will either be in the fonn of conclusions 16 resulting from the temperature logging program, a cement 17 integrity log in W -17 across the Schrader Bluff interval, or 18 plans to execute an alternative plan that is approved by the 19 Commission that would eliminate the risk of injected fluids 20 from moving out of zone. If the temperature logs indicate 21 fluid movement out of the pool, W -212i will be shut in until 22 an engineered solution is complete to eliminate the fluid 23 movement. W -17 does have evidence that the cement job on the 24 13 and three-eighths casing was successful. 25 A reservoir simulation model ofthe W Pad area has 9 (Pages 30 to 33) 907.276.3876 METRO COURT REPORTING, INC. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e ., Page 34 been used to estimate how the reservoir pressure dissipates between the injector, W-2l2i, and the producer, W-200. Exhibit VIII-l shows the maximum observed pressure between W- 2l2i and W -200, which occurs after approximately four years of water injection. The reservoir pressure at various points between the two wells were extracted ITom the simulation model and plotted as a function of distance from the injector. This evaluation shows that at a range of 1,000 feet to 1,500 feet ITom an injector, the pressure has dissipated to near reservoir pressure. This shows that the one-quarter mile area of investigation is a reasonable n is reasonable for water injection in the Polaris pool. So at zero here, this would be the injector, this would be the distance away ITom the injector to the producer over here. And the pressures at each point along there. Maximum fluid injection requirements at the Polaris Pool are estimated at 20,000 to 25,000 barrels of water per day. The expected average surface water injection pressure for the project is 2,300 psi. The estimated maximum surface injection pressure us 2,800 psi. The expected maximum injection pressure for Polaris Pool injections will not propagate fractures through the confining strata. Each Schrader Bluff 0, N, and M sand is separated ITom the adjacent overlying and underlying sand by 10 to 75 feet thick non- reservoir silty mudstones which provide effective fluid 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 35 1 isolation. 2 Reservoir simulation studies indicate incremental 3 recovery from waterflooding to be approximately 10 to 20 4 percent of the original oil in place, relative to primary 5 depletion. 6 BP Exploration, in its capacity as Polaris operator 7 and unit operator, respectfully requests that the Commission 8 adopt Pool Rules and Area Injection Order as proposed in the 9 application. This concludes our prepared testimony and we'd lObe happy to answer any questions you have. 11 CHAIR TAYLOR: Thank you. 12 MR. SCHMOHR: That final exhibit, we've got some 13 copies here for you, that we'd like added to the application. 14 CHAIR TAYLOR: We'll do that. It looks like a handful 15 of them here. 16 MR. SCHMOHR: Yeah, I think there's 10 there. 17 CHAIR TAYLOR: Okay, thank you. Let's make sure that 18 one gets in each file. Commissioner Bill and Commissioner 19 Seamount, would you like to start with questions now or would 20 you like to take a break first? 21 COMMISSIONER BILL: I'd prefer a break. 22 CHAIR TAYLOR: Okay. What if we take a 15 minute 23 break. 24 COMMISSIONER SEAMOUNT: Are we going to call each of 25 the witnesses back then to answer questions? . e AOGCC December 9, 2002 Page 36 1 CHAIR TAYLOR: If they could be available, they're 2 still under oath and..... 3 COMMISSIONER SEAMOUNT: Okay. 4 CHAIR TAYLOR: We can do it however you want. We can 5 pose the questions to individual people or we can pose the 6 question and you can decide who would most appropriately 7 respond to it. 8 MR. SCHMOHR: Okay. 9 (Indiscernible - background conversation) 10 MR. BEUHLER: Yeab, I'd also like to swear in Doug Von 11 Tish. 12 CHAIR TAYLOR: Were you going to provide testimony or 13 just be prepared to answer questions? 14 MR. YON TISH: Just for questions. 15 CHAIR TAYLOR: Okay. Would you raise your right hand, 16 please? 17 (Oath administered) 18 MR. YON TISH: Yes. 19 CHAIR TAYLOR: And do you wish to be qualified as an 20 expert witness? 21 MR. YON TISH: Yes. 22 CHAIR TAYLOR: Well, why don't you state your name for 23 the record, spell your last name, and then provide your 24 qualifications for us. 25 MR. YON TISH: My name is Doug Yon Tish. My surname Page 37 1 is spelled V as in Victor, o-n, space, T as in Tom, i-s-h. 2 I'm a geophysicist with BP Exploration Alaska, Incorporated. 3 I received Bachelor of Arts degree and Master of Science 4 degrees in geological science ITom Cornell University. I have 5 been employed as a geophysicist by BP and Sohio Petroleum for 6 19 years. I have worked on a variety of Alaskan projects 7 since 1994, including the Prudhoe Bay field, and the Midnight 8 Sun, Polaris, and Orion Pools. I have been working with the 9 Greater Prudhoe Bay satellites team since August 1998. Prior 10 to joining BP in Alaska, I worked on field development and 11 appraisal projects for BP in Australia, and on exploration 12 projects in the Gulf of Mexico for BP and Sohio. I would like 13 to be acknowledged today as an expert witness in geoscience. 14 CHAIR TAYLOR: Commissioner Bill, do you have any 15 questions or any objections? 16 COMMISSIONER BILL: No questions, no objections. 17 CHAIR T AYLOR: Commissioner Seamount? 18 COMMISSIONER SEAMOUNT: No questions, no objections. 19 CHAIR TAYLOR: Thank you, we'll consider you an expert 20 for purposes of answering questions then this afternoon n or 21 I mean this morning when we return. Mr. Beuhler, there will 22 be actually one thing we should take up, at least for you to 23 consider during the break. There were a number of exhibits 24 that BP submitted and requested that they be held 25 confidential. Two of them in particular, 1-6 and 1-7. The 10 (Pages 34 to 37) 907.276.3876 METRO COURT REPORTING, INC. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e .1 Page 38 Commission is not clear on what the basis for the trade secret request is. If you're not able to take it up when we return, we can certainly give you time to provide something in writing back to us, but what the Commission is looking for is some support for the finding that it is entitled to confidentiality under the trade secret standard that would indicate that the information derives independent economic value as a result of it being held confidential, and that by release of that you would lose that. MR. BEUHLER: Okay. We can certainly answer that when we come back from break. CHAIR TAYLOR: Great. Thank you very much. MR. BEUHLER: Thank you. CHAIR TAYLOR: We'll take a break, it's approximately 12 minutes after 10:00. (Off record - 10:13 a.m.) (On record - 10:45 a.m.) CHAIR TAYLOR: We're back on record, the time is approximately 10:45. And once again, we've demonstrated that we're not very good at keeping track of time. We apologize for the longer than 15 minute break. I think we'll start with some questions. Commissioner Seamount will start with the first set of questions. COMMISSIONER SEAMOUNT: Okay, I've only got a few questions. I'd like to put Exhibit 1-2 up on the screen. And 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 39 I 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . don't know who wants to answer this question, I'm assuming it would be Mr. Bemaski, Mr. Reints, or Mr. Von Tish. I don't know which one wants to answer it, or whether you're willing to answer it. In the area to the west of the proposed pool rules boundary, it looks like it's about, oh, a mile wide swath, give or take. Am I to interpret this area as an area of no potential for Polaris Pool type production? MR. VON TISH: In the area west of this fault and south ofthis fault, we interpret that as being an area of no potential production, at least in this area. In this northern area, wells drilled to date have no indicated pay in this area. However, these blocks are high standing Horst blocks that have not been penetrated that could potentially have pay. COMMISSIONER SEAMOUNT: Okay, thank you, Mr. Von Tish. Let's see. Is -- within that -- the area of the pool, is there any known areas of shallow free gas? MR. BERNASKI: No. No, there's no indication offree gas in the Polaris Pool. The sand's (indiscernible)..... COMMISSIONER SEAMOUNT: Okay, thank you, Mr. Bernaski. COMMISSIONER BILL: We may need to have you say the same thing on the -- for the tape. MR. BERNASKI: There is no indication of free gas in any sand in the Polaris Pool. CHAIR TAYLOR: What about the shallower zones? MR. BERNASKI: Above the top of the Ma? e AOGCC December 9,2002 Page 40 1 CHAIR TAYLOR: Yes. 2 MR. BERNASKI: The -- the nearest indication of free 3 gas in the Polaris Pool area would be in what we call the Sv 4 sands, which are roughly 12 to 1,500 feet shallower than the 5 -- excuse me, in the uppermost Ug4 and Sv sands, roughly 1,200 6 feet shallower than the Polaris Pool. There is some 7 indication of potential coal gas, or methane, in the U g4, and 8 certainly gas hydrates up in the Sv sands at a depth of 9 roughly 2,000 to 3,000 feet TVD subsea. 10 COMMISSIONER SEAMOUNT: In regards to shallow gas, 11 have you accounted for drilling rig equipment such as diverter 12 lines when applying for drilling permits? 13 MR. BEUHLER: Excuse us one moment. 14 MR. SCHMOHR: We have, it's done a case by case issue 15 on -- with the off- -- what we've seen from the offset wells 16 in that particular block that we're drilling in. 17 COMMISSIONER SEAMOUNT: Okay. I have one last subject 18 I'd like to talk about, and that would be fracture 19 stimulation. It might be helpful if you put Exhibit 1-5 up. 20 Do you typically fracture stimulate most of the wells in this 21 pool? 22 MR. SCHMOHR: Typi- -- well, all of the vertical wells 23 have been ITacked (Ph) and we frac them for a couple of 24 reasons. One is for sand control, it's an effective sand 25 control method, in addition to the stimulating benefits of Page 41 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 getting paths in your wellbore damage. So we've done, you know, all-- all producing wells except for one, the tri- lateral, that we've drilled have been ITacture stimulated. And most of them have either two or three ITaCS per well. COMMISSIONER SEAMOUNT: Okay. Is there a zone that you typically frac more than the others? Or do -- I mean, what would be, you know, a typical frac job on -- to -- are you -- do you ever frac the M sands? MR. SCHMOHR: No, we -- so far we've fracked the N sands and the 0 sands. The OA is wet in the W Pad area, so, of course, we haven't ITacked that. We have no production from the Mc or above. That's -- the Mc's an area that we may look at in the near future. COMMISSIONER SEAMOUNT: Okay, so you haven't fracked the Mc then? MR. SCHMOHR: No. COMMISSIONER SEAMOUNT: Okay. What's a typical size? MR. SCHMOHR: They varied a lot as we've gone through the learning curve. Anywhere from -- the initial wells were about 20,000 pounds range. We've done some recent ones that are as high as -- over 100,000 pounds. So there's quite a range that we've gone through. COMMISSIONER SEAMOUNT: What's the propint (ph) type? MR. SCHMOHR: It's a 1620, and it's resin -- we've used both resin and non-resin coded carbolite. It's a polar 11 (Pages 38 to 41) 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e ., Page 42 prop designed for low temperature. We try and tail in with the resin coated propint (Ph) to help us for sand production. COMMISSIONER SEAMOUNT: What's the canying fluid? MR. SCHMOHR: We use a -- it's a cross-link gel. All wells have -- were using a water based cross-link gel, and it's a borate (Ph) system. The last well we fracked, which was W -211, we were trying to get tip screen out sand. We went to a straight HEC (Ph) system to try and increase our leak off rate so we could initiate a tip screen out. So that's the only one that wasn't a cross-linked system. COMMISSIONER SEAMOUNT: Do you have any feel for how much of that gel that you get back? MR. SCHMOHR: We pretty much get back most of our load, although I can't really n we haven't really gone in and looked at our -- compared our total load pumped versus what we get back to see if we're actually leaving some. In almost -- in wells like this, almost any time you frac you won't get, you know, 100 percent of your fluids back. You know, there-- a lot of times there is some minor remedial fluids that are left. COMMISSIONER SEAMOUNT: Okay. And finally, do you feel that fracture height is contained within the -- I mean, is it contained where you want it to be contained? MR. SCHMOHR: Yes. Of course, the size of the job is -- one of the reasons the sizes have varied so much is that we 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 43 I are trying to stay within zone during the fracs, as well as 2 optimize the frac itself. We use several different modeling 3 techniques, one is produced by Nolty Smith (ph), NSI, which is 4 stirn (ph) planned, and we also use one of the vendor models to 5 do our modeling work as a backup to each other. So yeah -- 6 yes, I think we do stay fairly much within zone. We also do a 7 post-analysis where we look at the net pressures during the 8 job to see, you know, if they're following a PKN type frac or 9 if they're radial. The majority of them seem to be PKN, or 10 rectangular, which means they're constrained. 11 COMMISSIONER SEAMOUNT: Okay. Thank you, Mr. Schmohr. 12 I have no further questions. 13 CHAIR TAYLOR: CommissionerBi11? 14 COMMISSIONER BILL: I have a number of questions, and 15 they're not very well organized, so bear with me. But they 16 could switch around between various people. The first 17 question, the injection pressure seems rather high to me, and 18 so could you comment on why you would need that level of 19 pressure? I believe you said something -- a maximum of 2,800 20 pounds surface? 21 MR SCHMOHR: Yeah, the 2,800 pound figure comes from 22 -- that's what the actual manifold pressure will be at a 23 maximum. I think we had 2,300 in there as an expected 24 average. Right now we don't know exactly what our injectivity 25 will be. Most of our producers we frac, so we get binear (ph) It AOGCC December 9,2002 Page 44 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 wellbore damage. We don't know exactly what kind of damage we'll have, what pressure requirements there will be. We have done step rate tests on our producers pre-frac, which indicate that we initiate a frac at about one and a half to two barrels per minute. So in the 2,500 to 3,000 barrel per day range at a wellhead pressure of approximately 1,000 psi. So that's, I think, where we'll initiate, you know, fractures when we're injecting. And I think that, you know, somewhere in the 1,000 to, oh, 1,500 is the average range that will be on a wellhead pressure. COMMISSIONER BILL: So you anticipate that the numbers that you've quoted are high side? MR. SCHMOHR: Yes. COMMISSIONER BILL: How many individual well injection rates do you anticipate? MR. SCHMOHR: Anywhere from 1,000 to 5,000 barrels per day. COMMISSIONER BILL: Okay. So the 20 n 25,000 number that you quoted was n that's for the project n the initial portion of the project? MR. SCHMOHR: Yes. COMMISSIONER BILL: Okay. There -- the area to the north ofW Pad, that polygon area, seems rather large, and it doesn't appear that you n my guess is that you couldn't reach the entire area from the current pads. How do you intend to Page 45 1 develop that area? I believe it's the W -- TW-C area. 2 MR. REINTS: As you can see S Pad sits right here, W 3 Pad sits down here, and this Term Well C area in the middle, 4 which is about in between those two pads. From existing 5 facilities, this area could be a significant challenge to 6 drill just due to the departure we're dealing with, 12 to 7 14,000 for the departure. So right now our primary 8 development does not cover this area, it's considered a Phase 9 III type development where we have to get understanding of 10 what our technicallimits in drilling are, as well as 11 understanding of what type n or well types are going to be. 12 Obviously, if you're drilling vertical fracked wells, this is 13 not an opportunity for those types of wells where it may lend 14 itself to horizontal well deve10pmentjust due to the sheer 15 departure. The other issue we face is the rock quality 16 deteriorates as you get into this area. And at this stage of 17 the game, we're not real sure which sands are going to be 18 productive and which aren't. The Term WeIl C has some 19 interesting things that happened that makes you question 20 whether it's reaIly a pay target in a couple of intervals. 21 COMMISSIONER BILL: Okay. AIl right, thank you. 22 You've provided information on the variation in permeability 23 and porosity with the individual sands. It appears that 24 profile control, vertical profile control, might be a problem. 25 Can you address how you might go about achieving good 12 (Pages 42 to 45) 907.276.3876 METRO COURT REPORTING, INC. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e .] Page 46 injection into all of the individual sands? Or sufficient injection, I should say. MR. SCHMOHR: As I mentioned in my testimony, we'll be doing frequent spinner surveys to monitor the control. On the conventional well design that we have, it lends itself to coil tubing squeezes. And, you know, if we have thief zones -- we use a similar technique as what's used -- was used at Prudhoe Bay, the Prudhoe Bay unit. And we can minimize perforating in thief zones, squeeze it and re-perforate control. That's going to be probably the primary methodology. Do you have anything to add? MR. REINTS: I think based on past experience in both Weisak and Milne that the flood is controlled on the injection side, not on the producer side, just because of the interventions in a rracked well is very difficult. And at this stage of the game, we don't really know what to inspect for -- expect from injection confonnance, but it is a very difficult issue when you're dealing with four or five sands with the perfonnance -- you know, getting confonnance in all of those sands. COMMISSIONER BILL: Now on your multi-zone injectors, you may not have access to all of those sands to do profile control, remedial work. Is that true? MR. SCHMOHR: Yes. Yeah, that is a concern on-- well, on wells like S-l 04 for example, we did run multiple 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 47 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . packers there. So we do have some control within the -- the top three packers were installed to give us zonal control in the Schrader Bluff for these three sets of perforations. So we will be able to control the split between those. And then this is the, of course, Kuparuk down here. So we can run spinners down and find out what fluids are going where in this particular well. And we'll control rate by changing the orifice in the injection mandrel, the orifice size. So in a well like this, we do have quite a bit of control that can be mechanically done rather than cement squeezing. So -- now it's always a tough decision on how many packers to put in. Naturally the more packers you have, the more control you have. But likewise, the more chance of a packer failure and, you know, problems with integrity there. MR. REINTS: And I'd like to make an additional comment, too. The simulation work that's been done captures that variability in penneability, and basically shows that the variation really isn't that bad. I mean, if you're looking at the OA sand, for example, or the OBa where you have really good rock as opposed to, say, the OBc or the OBb which has fairly poor rock, the injection is mimicked by the production. Those low quality sands are usually low quality producers. So it really hasn't been observed to be really a problem in the model with..... COMMISSIONER BILL: Okay. You're talking in tenns of e AOGCC December 9, 2002 Page 48 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 voidage replacement? MR. REINTS: Right, yeah. COMMISSIONER BILL: I'd like to speak for a moment about W -17 and your proposal to run temperature logs. Could you explain how you would see an upward movement rrom the temperature logs? What sort of temperature contrast do you expect and what you might see? MR. SCHMOHR: Okay. Like I mentioned, W-17 has been shut in for a considerable amount of time. So what we propose to do is prior to injection we'll run a baseline temperature survey, which I'd expect to follow very closely to the geothennal gradient. And what we'd be looking for in the subsequent surveillance would be deviations from that baseline. My experience in Prudhoe, where you see a channel or a swept zone, a lot of times you can see swept zones. In Prudhoe's case, it'll be a cooling. And typically we can see one to two degree variation Fahrenheit. It's fairly accurate, especially if you have a baseline that you're going from. In W-17's case, if we had a channel going up, for example, we're injecting fluids at about 120 degrees Fahrenheit. Of course there's -- the reservoir temperature is at about 100 degrees. So we're working with about a 20 degree delta T. There -- if there's considerable movement behind pipe, you can see the -- usually it'll diverge from the geothennal gradient and usually it's a straight line temperature profile up to where it either Page 49 I departs into another zone or, you know, where it ends. 2 COMMISSIONER BILL: So rrom the native fluids, that 3 would be the first indication. You believe that there's 4 enough temperature contrast vertically to be able to detect a 5 problem within a few months? 6 MR. SCHMOHR: I think we can see a temperature 7 deviation within a degree or two. The -- probably the -- 8 whether we would see it within two months, you know, depends 9 on how that zone is taking fluids. I guess we expect to have 10 fluids at that well within three months. 11 MR. REINTS: Three to six months. 12 MR. SCHMOHR: Three to six month range is where we'd 13 expect to see it. And that's why I kind of picked the two-- 14 the rrequency of monitoring that I did. 15 COMMISSIONER BILL: Okay. The plan for a downhole 16 safety valve that -- the nipple that was going to be installed 17 into the tubing string, was that just for injectors or was 18 that for producers also? 19 MR. SCHMOHR: We installed it in producers also. 20 Every well has a nipple just below the pennarrost. 21 COMMISSIONER BILL: And could you speak to what valves 22 that -- should it be necessary, what sort of -- what type of 23 valves that you would be placing in that nipple? 24 MR. SCHMOHR: Well, for injectors they're a check 25 valve type injection valve, K valves. Ifwe need to do it. 13 (Pages 46 to 49) 907.276.3876 METRO COURT REPORTING, INC. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e tÞ\ Page 50 Of course, for MI we would install an injection valve. But this application isn't requesting MI. So it'd be a through tubing safety valve that we would run. COMMISSIONER BILL: Well spacing on the pad, distance between wells? MR. SCHMOHR: Fifteen feet. COMMISSIONER BILL: Okay. And..... (Indiscernible - away from microphone) COMMISSIONER BILL: Okay. Kind of a nominal producer to injector ratio, it appeared like it'd be a little over one? Is that just taking the gross numbers or..... MR. REINTS: Yeah, it ranges between one and a half to one, to two to one. And it will be dependent upon which types of wells we actually drill in Phase II and Phase III, whether they're horizontal wells or vertical wells. As you move towards a horizontal well development, you're minimizing the number of producers and increasing the number of injectors. Whereas in a vertical well development, to get the through- puts, you need more producers. So..... COMMISSIONER BILL: Now from reading the application, I'd understood that you were looking at initial development primarily using vertical wells and stimulation treatments. Is that still the plan? MR. REINTS: Yes. But like I said in my testimony, we have drilled the one triple lateral well, and we're evaluating 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . Page 51 I 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . drilling another one here in the next few months. COMMISSIONER BILL: You mentioned that water was coming -- your injected water was coming from the existing infrastructure. Is there sufficient water to provide for Polaris's needs and also for the other developments? MR. REINTS: Yes. COMMISSIONER BILL: Okay. You don't see that you're starved for water by adding another development? MR. REINTS: No more starved than we are for water. COMMISSIONER BILL: Already. MR. REINTS: Polaris actually -- as we ramp up, the· injection rates could get up to 25,000 barrels a day. But initially we're dealing with four to 5,000 barrels a day probably. So pretty small volumes. COMMISSIONER BILL: Okay. I believe that's all my questions for now. CHAIR TAYLOR: Any other questions? COMMISSIONER SEAMOUNT: No. CHAIR TAYLOR: Mr. Beuhler, I guess my only question was with -- following up with respect to those two exhibits, Exhibit 1-6 and 1-7. MR. BEUHLER: Yes. And if it pleases the Commission, what I would suggest is that the operator provide -- we would suggest providing a written response documenting our reasons for declaring those confidential. And that's specifically e AOGCC December 9,2002 Page 52 I 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Exhibits 1-6 and 1-7. CHAIR TAYLOR: That's correct. And how much time should we leave the record open for that? MR. BEUHLER: My desire would be as short as possible, so this week? Would that be appropriate? CHAIR TAYLOR: You can pick the time and..... MR. BEUHLER: Okay, let's make it this week. CHAIR TAYLOR: By Friday? MR. BEUHLER: By Friday. CHAIR TAYLOR: By Friday, 4:30. So we'll leave the record open until Friday at 4:30. Do either of you want to take a break before closing? COMMISSIONER BILL: Have no need to. CHAIR TAYLOR: Okay. Thank you very much, we appreciate the testimony and everybody's participation this morning. We'll keep the record open until Friday at 4:30 for a response to the confidentiality of Exhibit 1-6 and 1-7. We'll close the hearing, thank you. (END OF PROCEEDINGS) ****** Page 53 1 CER TIFICA TE 2 SUPERIOR COURT ) )ss. 3 STATE OF ALASKA ) 4 I, Cari-Ann Ketterling, Notary Public in and for the State of Alaska, do hereby certify: 5 THAT the foregoing pages numbered 02 through 52 6 contain a full, true and correct transcript of the Public Hearing before the Alaska Oil and Gas Conservation Commission, 7 taken by and transcribed by Julie O. Gonzales; 8 THAT the Transcript has been prepared at the request of the Alaska Oil and Gas Conservation Commission, 333 West 9 Seventh A venue, Anchorage, Alaska. 10 DATED at Anchorage, Alaska this 12th day of December, 2002. II SIGNED AND CERTIFIED TO BY: 12 13 Notary Public in and for Alaska 14 My Commission Expires: 7/19/04 15 16 17 18 19 20 21 22 23 24 25 14 (Pages 50 to 53) 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e e AOGCC December 9,2002 Page 54 . A 16:18,2223:2,6,9 approach 20:22 average 18:14 34:18 37:2138:10,13 40:13 AAC 2:1832:7 26:14,1831:1,137:2 appropriate 28:20 52:5 43:2444:9 51:19,2252:4,7,9 able 38:247:449:4 37:10 53:3,4,6,8,9,10 appropriately 36:6 away 34: 13 50:8 bill 1:11 2:94:17,19 about 3:2,1539:5,24 53:13 approval 30:4,5 a.m 1:9 38:16,17 6:10,1216:3,517:3,5 40:1841:2044:4 Alaskan 6:2 37:6 approved 33:18 23:14,1626:1,3,25 45:4,2548:4,20,21,22 Alaska's 6:19 approximately 2:5 B 27:235:18,2137:14 above 32:14,16,19 allocation 30:3,11,13 18:1720:1,1834:4 Bachelor 3:225:23 37:1639:2043:13,14 39:2541:12 30:15 35:338:14,1944:6 16:1526:1537:3 44:11,14,18,22 45:21 accept 17:8 allow 22: 11 28:25 30:8 April 16:25 24:15 Bachelors 23:3 46:21 47:2548:3 access 21 :24 46:22 allowing 24:13 27:25 30:13 back 35:25 38:4,11,18 49:2,15,2150:4,7,9 accommodate 24: 14 almost 42:16,17 aquifer 7:18 42:12,13,16,18 50:2051:2,7,10,15 25:22 along8:1412:2313:6 ARCO 16:1823:6,6 background 36:9 52:13 accommodating 24:22 13: 12 34: 15 area 1:5 2:8 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10:6,18 B-e-u-h-I-e-r 3:20 again 38:19 apply 32:4 automated 25: 16,18 12:4 14:634:2,3,6 against 14:20 applying 40: 12 automatically 25:21 43:1645:447:450:5 C 3:256:16 appraisal 6:6 7:8 27:9 available 32:1633:6 50:12 C 2:1 12:9,9,1513:15 1:1,83:214:9,9 37:11 36:1 beuhler 3:18,19,244:2 45:3,1853:1,1 4:13 5:23 6:6 16:14 appreciate 52: 15 Avenue 53:9 4:5,7,255:636:10 calculated 33:4 METRO COURT REPORTING, INe. 907.276.3876 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e e AOGCC December 9,2002 Page 55 ealculations 32: 13 closing 52:12 28:829:4,2230:7 contour 11:1015:8,11 datum 18:1729:17 call 2:3 35:2440:3 closure 7:1712:20,21 32:11 15:14 day 34: 18 44:5,17 cammy 1:102:10 coal 40:7 completing 21:21 contours 15: 17 51:12,13 53:10 capable 24:21 coated 42:2 completion 33:2 contrast 14:9 48:6 49:4 Dead 26: 19 capacity 35:6 coded 41 :25 completions 28:3,6 control 13:21,22 19:4 dealing 45:646:18 capture 18: 1 coil 46:5 29:7 29:9,1530:10 40:24 51:13 captures 47:16 coincide 7: 14 complex 22: 1 40:2545:24,2446:4,9 December 1:8 2:4 6:5 carbolite 41 :25 College 16:17 complexly 11 :20 46:2347:1,2,4,7,9,12 53:10 career 16:21 Colombia 26:20 composite 15:5,10,12 controlled 46: 13 decide 36:6 Cari-Ann 53:4 column 14:5,7 conceptual 32:25 conventional 11:5 28:2 decision 47: 11 carrying 42:3 Colville 9:11,12,13 concern 46:24 28:5,12,13 46:5 declaring 51 :25 case 14:5,7,18,2415:3 combination 20:228:5 concludes 15:2425:25 conversation 36:9 deemed 30:5 40:14,1448:16,19 combined 15:5,10,13 35:9 converting 21:5 deep 6:6 cased 31 :2232:9 15:20 conclusions 33: 15 cooling 48:16 deeper 27:10 casing 27:19,24 28:1,4 come 38:11 conditions 28:25 copies 35:13 deepest 9:24 10:8,20 29:233:4,7,24 comes 3:13 43:21 conduct 2:16 copy 2:13 8:1131:5 defined 13:6,20,22 cement 32:14,15,16,16 coming 51:3,3 conducted 18:18 core 11:517:2118:8 14:16,23 33:4,5,7,16,2347:10 commencing 33:14 confidential 8:7,10,13 Cornell 37:4 degree 3:225:23,24 cemented 28: 1,529:6 comment 8:5 43:18 13:5,1715:1,4,9,12 correct 52:253:6 11:416:1623:3 32:9 47:16 15: 15,18,21,22,23 correctly 2:23 26:1637:348:17,22 cementing 27:19 commingled 21:9 24:3 17:2218:1119:1 costs 20: 1424:6 49:7 center 24:225:23 30:2,4,5 37:2538:851:25 couple 40:2345:20 degrees 11:1218:17 certainly 38:3,10 40:8 commission 1: 1 3 :2, 1 0 confidentiality 38:5 course 8:8 41: 11 42:24 37:448:20,21 CERTIFIED 53: 11 3:144:12,145:3,5,8 52:17 47:548:2050:1 delta 48:22 certify 53:4 32:433:1935:738:1 configuration 17: 13 court 2:11,13 16:10 demonstrated 38:19 CHAIR 2:3 3:24 4:3,6 38:451:2253:6,8,14 confinement 32: 11,12 22:23 26: 11 53:2 density 28:24 . 4:17,20,235:5,10,13 commissioner 2:9,9 confining 9: 15,20 cover 45:8 departs 49: 1 5:17,206:10,13,15 4:17,19,20,216:10,12 34:22 crestaI12:2,321:8,9 departure 45:6,7,15 15 :25 16:3,6,9 17:3,6 6:13,1415:2516:2,3 confirmed 32:25 crests 7:2120:22 dependent 12:2150:13 17:822:19,2223:11 16:517:3,5,6,723:14 conformance 46: 17,19 cross 8:15 depends 49:8 23:14,17,2026:1,4,6 23:16,17,1826:1,3,4 connecting 8:15 cross-link 42:4,5 depletion 17:1719:23 26:10,2527:3,635:11 26:5,25 27:2,3,4 conservation 1: 1 4: 13 cross-linked 42: 10 19:2535:5 35:14,17,2236:1,4,12 35:18,18,21,2436:3 53:6,8 crude 11:4 depth 8:1814:4 27:24 36:15,19,2237:14,17 37:14,16,17,1838:22 consider 6:1523:20 current 8:1919:3,5 29:8 40:8 37:1938:12,14,18 38:2439:14,19,20 27:637:19,23 44:25 depths 8:1813:17 39:2440:143:13 40:10,1741:5,14,17 considerable 48:9,23 currently 20: 16,20 derived 18:24 19:3 51:17,1952:2,6,8,10 41:2342:3,11,21 considered 32:6,8,12 23:226:1427:19 derives 38:7 52:14 43:11,13,1444:11,14 45:8 31:2132:23 described 30: 13 32:5 Chairperson 1: 1 0 44:18,2245:2146:21 consist 11:3 currently-planned design 46:5 challenge 45:5 47:2548:349:2,15,21 consistent 22: 16 31:17 designed 21:2428:19 chance 47: 13 50:4,7,9,2051:2,7,10 consists 10:9,2211:19 curve 18:9,10,12 41:19 42:1 changing 47:7 51:15,1852:13 21:11,13 curves 18:630:14,20 designs 27: 18 channel 48: 14, 19 commissioners 1: 10 constrained 43: 10 desire 52:4 character 8 :22 11: 15 8: 11 constructed 19:20 D detect 49:4 13:8 common 29: 17 contact 8:189:1012:15 D2:1 deteriorates 45: 16 characterized 9: 7 , 16 Company 6: 1 13:1014:4,1418:3 daily 2:1630:14 determination 3:2,15 17:25 compared 42: 15 contacts 8: 17 13: 18,20 damage 29:1441:1 determine 29:2530:14 check 49:24 compartment 13:6,9 13:21,23 14:10,10,12 44:1,1 33:7 chemical 23:4 compartmentalization 14:25 18:3 dan 1:10 2:9 determined 24:25 chosen 24: 10 22:11 contain 53:6 data 7:10,1111:15 develop 45: 1 clay 12:23 13: 11 compartments 13:1,3,4 contained 42:22,23,23 12:1513:1019:19 developed 17:10 20:1,9 clean 10:2,23 13:8 contains 8:6 31:2 20:2322:625:20,21 developing 20:24 22:2 clear 38:1 competent 11:2 contemplated 24: 16 date 5:2 11:6 29: 13 22:12 ,ose22'9 33,552,18 complete 30:4 33:22 continue 22: 18 39:11 development 6:77:8 losely 48: 11 completed 24: 15 27: 14 continuous 9: 17 dated 30:13 53:10 9:2211:312:713:3 METRO COURT REPORTING, INC. 907.276.3876 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e e AOGCC December 9,2002 Page 56 . 16:1517:1619:20,22 31:22 32: 1 39: 11 40:11 48:14 few 38:2449:551: 1 20:5,6,12,14,21,24,24 41:350:25 equipped 29:7 experiments 18:8 field 3:35:186:616:19 21: 1 ,2,3,4,1 0, 13 ,20 drilling 21: 14,2422:4 especially 48: 18 expert 2:25 3:3 4:11,15 17:1220:622:16,18 21:21,22,2222:2 27:1828:2340:11,12 established 19:14,16 4:245:11,176:8,15 27:737:7,10 26:15,22 27:9,17 40:1645:10,1251:1 establishing 20:25 17:1,823:9,2126:23 fields 16:2427:20 37:1045:8,9,1450:16 dual 31:23 estimate 19:5 34:1 27:736:2037:13,19 Fifteen 50:6 50:18,2151:8 due 13:2222:8,10 45:6 estimated 18:1419:11 Expires 53:14 figure 43:21 developments 51: 5 45:14 31:1834:17,19 explain 48:5 file 35: 18 deviation 49:7 during 8:829:1030:18 estimates 17:1719:2 exploration 1:4 3 :21 final 35 : 12 deviations 48: 13 37:2343:1,7 evaluate 19:20 5:23 23:226:1427:9 finally 42:21 device 29:9 evaluated 17:1119:22 31:135:637:2,11 find 47:6 differences 8: 16 E 20:1621:1922:18 extending 25: 1 finding 38:5 different 11:1714:3,14 E 2:1,153:1,1 evaluating 50:25 extension 24:23 fining 9: 17 43:2 each 2:21 8:11 9:6 10:2 evaluation 32:16 33:6 extensive 9:710:11,12 first 2:19 5:8 7:5 30:18 difficult 46: 15, 18 13:1,614:1,15 18:2 34:8 10:15,2433:2 35:2038:23 43:16 dip 7: 17,23,24 12:20 20:1929:19,20,21 evaluations 17:14 30:1 extent 8:25 12:21 13:4 49:3 dips 11:11,12 30:1531:17,1934:14 even 11:1 15:624:11 five 15:11 20:1 33:11 direct 3:7 34:2235:18,2443:5 ever 41:8 extracted 11:5 34:6 46:18 directed 3:9 21:21 east 7:18,2412:20 Every 49:20 five-eighths 33:4 direction ally 27: 17 14:22 everybody's 52:15 F flank 12:3 directly 2:13 3:7 eastward 11: 11 evidence 33:13,14,23 F 53:1 flare 24:9 discrete 8: 1 east-west 7 :25 11: 18,21 exactly 43 :24 44: 1 face45:15 flexibility22:1128:15 discussion 25:25 12:23 example 29:25 46:25 facilitate 27:25 28:18 display 8:9 economic 38:7 47:1948:19 facilities 23:12 24:1,7 flood 19:23 20:4,7,10 disposal 24:9 effective 34:25 40:24 except 41:2 24:14,1725:15,25 20:25 24:25 25:8 dissipated 34:9 efforts 20: 12 excerpts 5:7 31:945:5 46:13 eissiPates 34: 1 eight 33:11 excuse 7:208:1840:5 facility 20:1523:2 flooding 17:1619:24 istance 34:7,13 50:4 either 25:5,1633:15 40:13 24:21 flow 29:9 30:3 distinct 7: 1 11: 14 41:448:2552:11 execute 33:18 factor 30:16 fluid 8:13 12:1413:10 diverge 48:24 electric 28:22 exhibit 6:20 7:12,13,20 Fahrenheit 18:1748:17 14:918:18,21,23 19:5 divert 25: 16, 18,18 Elements 13:1 8:13,22,25 11:8 13:6 48:20 25:731:10,1133:21 diverter 40: 11 elevation 29: 17 15 :4,9,12,21,22,23 failure 47:13 33:2234:16,2542:3 divided 7: 1 eliminate 33:19,22 17:2218:11,2219:1 fairly 43:647:21 48: 17 fluids 11:5 24:1,3,3 Division 4: 13 employed 5:2537:5 19:1720:1124:17 far 2:10 32:17 41:9 31:732:13 33:19 document 8:6 25:17 enable 28:19 27:1528:13,1431:14 fashion 8: 12 42:18,1947:648:20 documenting 51 :24 encompassed 7: 1 34:335:1238:25 fault 8:2,1911:14,17 49:2,9,10 doing 46:4 END 52:19 40:1951:2152:17 11:21,2412:1,2,3,8 fluvial 9:19 dominated 11:17,22 ends 49: 1 exhibits 8:7,7,10 13:17 12: 12, 12, 13,15, 16, 18 focuses 20:24 done 30: 11 40: 14 41:1 engineer 16:14,14,19 15:1,15,1824:20 12:19,23 13:2,614:17 follow 48: 11 41:2044:347:10,16 16:21,2223:1,2,12 28:1237:2351:20 15:322:3,13 39:8,9 following 32:2 43:8 Donn 26: 12 26:13,14 52:1 faulted 11 :20 12:24 51:20 Doug 36:10,25 engineered 33:22 exist 8: 10 faulting 7:24 12: 11 follows 19:6 down 3:87:23 12:11 engineering 3:22 16: 16 existing 13:2121:11,15 22:8 foot 9:1814:17 13:2218:1845:3 17:2,922:1623:4 23:24,2524:5,13,14 faults 7:16,258:3 11:23 forecasts 20: 11 47:5,6 26:16,2427:7 24:19,2325:1,10,14 12:4,1413:8,9,12 foregoing 53:5 down dip 12:10,20 England 26:20 27:1631:1745:4 14:19 form 9:1410:13 33:15 14:17,2321:16 enhance 20: 13 30:23 51:3 fault-bounded 12:6 formation 6:22 11:8 downhole 11:7 29:9 enhanced 31: 10,10 expanded 25:22 features 8:14 14:2127:11,2428:9 49:15 enough 32: 18 49:4 expansion 20:1524:14 feel 42: 11 ,22 29:3,1432:17 down-dip 21 :25 enter 5:3 expect 46:17 48:7,11 feet 7:229:9,14 10: 1,6 formations 6:247:1 drill 23 :24 24: 16 25 :22 entire 9:3 44:25 49:9,13 10:1811:1014:6,6,8 28:10,21 45:650:14 entirety 5:4 expected 14:5,7,18,24 14:815:9,12,1418:15 formed 12:17 drilled 7:4 20:20 21:17 entitled 5:938:5 15:322:824:11 18:1620:1927:21 forming 13:9,12 ~ 23,242""1,12,13,18 environmental 24:5 34:18,2043:23 29:1832:2334:8,8,24 forms 9:19,22 27:21,2328:229:3,13 equipment 24:825:23 experience 4:846: 12 40:4,6,9 50:6 forward 22:6 METRO COURT REPORTING, INC. 907.276.3876 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e e AOGCC December 9,2002 Page 57 .our 3:10 9:210:20 generally 10: 11 ,23 HEC 42:8 improved 22:3 injectivity 28:743:24 29:534:4 46:18 11:11 height 42:22 Inc 16:14 injector 21:12,1428:14 51:13 generate 19:21 heights 14:5,7 inch 25: 1 29:2,4,5,5 31:2332:1833:1 frac 40:2341:6,7,8 gentle 11:12 held 37:2438:8 include 19:23 24:7 34:2,7,9,13,1450:10 42: 1743:2,8,25 44:4 geological 37:4 help 29:24 42:2 included 24:19 injectors 20:621:18 fracked40:2341:9,11 geologist 5 :22,25 helpful 40: 19 includes 21 :4 28:9,1930:431:14,19 41:1442:645:12 geology 5:9,18,246:9 high 10:2211:2012:7 including 6:2 16:22 46:2149:17,2450:17 46:15 geophysicist 37:2,5 12:1013:1139:12 24:1628:2330:5 inlet 24:8 fracs 41:443:1 geoscience 37:13 41:2143:1744:12 37:7 inspect 46: 16 fracture 28:629: 12 geothermal 48: 12,24 higher 10: 1421:25,25 inclusive 20:8 install 29:9 50: 1 40:18,2041:342:22 gets 35:18 highest 11: 1 incorporated 21: 19 installed 28:17 47:2 fractures 34:22 44:7 getting41:146:19 high-standing 8: 1 37:2 49:16,19 free 13:24 39:16,17,22 Gil3:19 hold 23 :23 incorporating 20:23 Installing 30:9 40:2 give 3:938:339:647:2 hole 18:1927:21,23 increase 42:8 insufficient 25:3,12 frequency 49: 14 go 3:256: 1645:25 28:2229:4 increasing 50: 17 integrity 31: 13 32:2,6,9 frequent 46:4 going 35:2436:12 holes 32:25 incremental 35:2 33:1747:14 Friday 52:8,9,10,11,16 45: 11,1746:1047:6 hope 23 :23 independent 38:7 intend 8:8 44:25 from2:11,20 3:22 5:7 48:18,1949:16 horizon 7:23 indicate 14:15 19:25 intensely 12:24 5:247:10,108:20,21 gone41:18,2242:14 horizons 9:24 33:2035:2 38:644:3 interbedded 10: 10 8:249:4,11,16,18,24 Gonzales 2: 11 53:7 horizontal 17:23 20: 13 indicated 11: 14 39: 11 interesting 45: 19 10: 1,2,8, 14, 15,20 good 2:33:1822:16 20:15,1921:16,18 indication 39: 17,22 intermediate 29:2 11:512:5,10,11,13,14 38:2045:2547:20 28:2,329:1,4 45:14 40:2,7 49:3 interpret 39:6,9 12:1613:8,9,11,25 GOR 20:3 50:15,16 indiscernible 36:9 interpretation 19:4 14:2,816:1617:21 graben 12:4,713:14 horizontally 18:22 39:1850:8 interpreted 13: 18 18:19,20,2419:3,19 21:22 Horse 26:19 individual 10:25 36:5 interrupt 3:24 20:7,2223:4,2425:10 gradation 9:16 Horst 13:16 39:12 44:1445:2346:1 intersect 11: 24 31: 18 . 26:1628:130:15,23 gradational 9: 11 hydrates 40:8 industry 4:8 intersection 12: 18 31:8,1232:18,23 gradient 48: 12,24 hydraulically 13:7 inferred 12:14 13:9 14:23 33:16,2034:6,7,9,13 gravel 24:12 hydrocarbon 7:9,16 influenced 17: 18 interval 6:23 7:3,69:6 34:2335:337:4 gravity 11:4 10:25 19:220:9 information 31 :2438:7 9:16,2210:1,5,6,9,13 38:1140:1541:12,19 Great 38:12 hydrocarbons 7:5 11:3 45:22 10: 16,17,18,22,25 43:2144:16,2545:4 Greater 3:20 4:10 6:4 infrastructure 24:5 11:3,10,1114:1,7 46:1748:5,13,18,24 16:2423:726:21 I 25: 11 51:4 15:8,11,1418:233:17 49:250:8,2051:3 37:9 identical 18:10 initial 17:18 18:13,14 intervals 7:2,29:3 10:2 front 3:148:11 Greg 5:9,10,21 identified 17:1620:4 20:3,2129:1841:19 12:2213:2514:13,14 full 22:22 53:6 gross 8:4 9:8 11: 1 identify 2:23 16:9 44:1950:21 45:20 function 34:7 13:13 50:11 17:14 initially 51 : 13 interventions 46: 15 further 9:128:1843:12 guess 44:24 49:9 51:19 1121:2,21,2422:5 initiate 42:944:4,7 introduce 2:83:16 future 22:11 29: 11,14 Gulf 6:7 37: 12 50:14 initiating 33: 12 investigate 19:21 32:133:141:13 11121:322:2,645:9 injected 20:1031:11 investigation 34: 11 H 50:14 33:1951:3 invite 3:16 G half20:9 29:5,5 44:4 111-2 24: 17 injecting 33:10 44:8 involve 20:6 22:2 G2:1 50:12 111-3 24:20 48:20 IPA23:24,2524:3,5 game45:1746:16 hand 5:13 16:622:19 111-424:20 injection 1:5 2:8 5:1 irregular 22:9 gamma 7:11 28:23 26:736:15 II-I 17:22 20:1121:6,925:2,2,3 isobar 29:16 gas 1:113:24 17:18 handful 35:14 11-2 18: 11 25:6,11 28:13,20 isolated 13:7 14:2 19:5,11,2425:6,9 hands 3:12 11-3 18:22 29:1930:1,2,6,7,8,9 22:10 28:1639:16,18,22 happened 45:19 11-419:1 30:10,21,22,2431:6,7 isolates 9:18 40:3,7,8,1053:6,8 happy 35:10 11-5 20: 11 31:17,21,2532:6,13 isolation 30:732:21 gas/oil 13:23 hear 2:20 illustrated 6: 19 33:12,1434:5,12,16 33:3,7,13,1535:1 gathering 20:23 24:2 hearing 1:22:4,7,15 illustrates 8:24 34:18,20,2135:8 issue 40:14 45:1546:18 25:20,21 4:145:723:2152:18 impacts 24:5 43:1744:1446:1,2,13 it'd 50:2,10 GC-2 24:7 25:2330:15 53:6 impermeable 14:20 46:1747:8,2148:10 it'll 48: 16,24 ~eI4N'5' 12 hearings 23: 10 implemented 29: 12, 14 49:2550:151:12 Ivishak 6:3 7:727: 10 eneral1O:2 heavy 10:1511:3 important 10:13 injections 34:21 28:10,2132:2433:1 METRO COURT REPORTING, INe. 907.276.3876 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e e AOGCC December 9,2002 Page 58 eV-119:17 31:2347:5 location 7: 12 12:5,6 19:2122:14,17 37:12 IV-228:12 K22-11-12 21:23 13:415:231:16 manager 3:21 MI25:929:1150:1,2 IV-328:13 locations 17:1418:5 mandrel 47:8 microphone 50:8 IV-428:14 L 24:11 27:14 mandrels 28:1530:8,9 mid 7:22 i-s-h 37: 1 lack 13:22 log 7:5,10,118:22,24 manifold 24:23,24 middle 45:3 1-16:20 laminated 10:3,4 17:1533:6,17 43:22 Midland 26:20 1-1015:1,4,18 large 11:21 ,24 44:23 logged 7:713:23 14:10 manifolds 24:8 Midnight 16:23 37:7 1-1115:1,9 large-offset 12: 19 14:10,12,1427:11 manner 22: 15 might 40: 19 45 :24,25 1-1215:1,12,19 last 16:1022:23 26:11 logging 27:2528:23,23 manual 25:16,19 48:7 1-1315:15,21 36:23 40: 17 42:6 28:2433:16 manually 25:21 mike 1:112:9 1-1415:15,22 later 16:18 logs 28:2229:2430:1 many 44:14 47:11 mile 31:4,14,16,19 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14:6,11,13,14,17,24 mean 37:2141:642:22 moment 40:13 48:3 J-function 18: 1 38:2539:540:18 15:4,12,17,19,2221:4 47:18 monitor 31: 11 46:4 42:1746:2547:9,15 21:10 23:24 24:10,19 means 43: 10 monitoring 49: 14 K 48:3,850: 10,24 24:2425:10,1534:23 measured 17:20 18:25 Montana 16:16,17 K 13:15 49:25 likewise 47: 13 41:8 29:19 month 30:18,19 49:12 Kansas 3:23 limit 14:22 ma9:1710:2114:11 mechanic 31: 13 months 30:1833:11,13 keep 52:16 limited 10:1013:10 15:13 31:15,18,20 mechanical 26: 16 32:2 49:5,8,10,11 51:1 keeping 38:20 limits 8:1414:16,17 32:1439:25 32:6,8 more 41:647:12,12,13 Ketterling 53:4 15:3,1620:2245:10 mainly 10:9 mechanically 47: 10 50:1951:9 key 22:6 line 8:1525:248:25 maintained 29: 17 members 3: 10 morning 2:33:1837:21 kind 44:149:13 50:9 liner 21:528:4 29:6 maintenance 29: 1 0 mentioned 46:3 48:8 52:16 know 39:1,341:2,7 lines 40: 12 31:9 51:2 most 36:640:2041:4 42:18,1843:8,2444:1 lithologies 8:4 major 12:1,2,1813:1 Metering 30:12 42:13 43:25 44:7,846:6,16,19 little 50: 10 majority 43:9 methane 40:7 move 50:15 47:1449:1,8 load 42:14,15 make 3:2,4,13,148:5 method 40:25 movement 33:21,23 known 39:16 locally 9:7 25:4,13 35:1747:1552:7 methodology 46: 1 0 48:5,23 ~uparuk 6,22 H,8 located 6:1812:4,9 makes 45:19 Metro 2:11,13 moving 22:633:20 21:1027:1028:10,20 27:1632:23 management 17: 10 Mexico 4: 12, 13 6:7 much 38:1242:12,13 METRO COURT REPORTING, INe. 907.27 6.3876 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net · 42:2543:6 52:2,14 muddy 9:13 10:3 muds 10:9 mudstone 9:18,19 10:24 mudstones 9: 12,13 10:12,2414:2134:25 multi 28: 1,9 multiple 28: 11 46:25 multi-formation 28:20 multi-lateral 28:3 29: 1 multi-zone 28:1430:8 46:21 M-a-t-t-i-s-o-n 23: 1 N N 2:1 7:2 8:20,23 9:1,2 9:310:5,7,9,12,15,17 11:2213:18,21 14:1,5 14:9,13,17,2415:4,10 15:16,19,21 19:8 34:2341:9 name 2:10,223:8,19 5:21 16:10,10,12 22:22,23,25 26: 11,11 26:1236:22,23,25 earrowed 18:920:17 ative 49:2 Naturally 47: 12 Nb 10:8 Nc 10:814:715:11 near 11:2232:134:9 41:13 nearest 40:2 nearly 18:9 Nebraska 26: 17 necessary 20:23 28:7 28:11 29:649:22 need 29:839:2043:18 49:2550:1952:13 needed 25:9 needs 32:22 51:5 net8:49:811:113:12 14:1815:4,5,7,10,11 15:13,13,1819:343:7 neutron 28:24 new 4:12,13 24:12 30:17 News 2:16 next 51:1 nine 33:4 nipple 29:749: 16,20,23 Nolty 43:3 ~:::::~~~;' 1313 ~0.mn~ ~ P$4'"'! e non 34:24 non-reservoir 10:3,9 10:24 non-resin 41 :25 north 6:197:4,18,23 12:2013:1414:22 21:4,2225:1827:20 44:23 northeast 12:20 northeast-dipping 12:2 northern 24:18 39:10 northward 11:12 northwest 11:1714:19 northwest-southeast 7:25 11:23,25 12:4,18 14:19 north-northeast 9:5 north-south 7 :24 11: 18 11:24 12: 12, 19 Notary 53:4,13 notice 2: 15 November 2:16 NSI43:3 number 8:610:1014:9 27:828:1537:23 43:1444:1850:17,17 numbered 53:5 numbers 44: 11 50: 11 numerous 14: 11 o 02:1 7:2,28:20,239:1 9:2,2,10,21,25 10:2,5 10:1413:19,21 14:1,5 14:9,13,18,2415:4,5 15:16,19,21 19:8 34:2341:10 53:7 OA 7:239:25 11:914:8 15:618:1941:10 47:19 oath 4:4 5:1516:7 22:2026:8 36:2,17 OB 8:21 OBa9:25 18:1920:17 47:19 OBb 9:25 18:1947:20 OBc 9:25 14:8 20: 17 47:20 OBd 9:25 18:1920:18 OBd/OBe 18:20 OBe 9:25 OBf9:24 14:6 15:6 objections 4:18,19,22 6: 12, 14 17:4,5,7 23:15,16,1927:1,2,5 37:15,16,18 objective 22:14 observed 34:3 47:23 obtained 25: 1 Obviously 45:12 occurs 34:4 October 5:3 OECHSLI 1:10 off38:16 40:15 42:8 offer 5:7 offices 2:6 offset 12:14 21:18 40:15 oh 39:5 44:9 oil 1:1 4:7,13 10:14,15 11:713:2514:5,7,11 14:13 15:17,19,20 17:18,1919:3,5,7 20:1,3,1022:1631:7 35:453:6,8 oil-water 8:1713:20,21 14:4,10,24 oil/water 13:1818:3 Okay 4:25 23: 14,20 26:12 27:835:17,22 36:3,8,1538:10,24 39:14,1940:1741:5 41:14,1742:2143:11 44:18,2245:2147:25 48:849: 15 50:7,9 51:7,1552:7,14 once21:1838:19 one 3:1020:921:14 24:1829:20,2230:19 31:1935:1837:22 39:340:13,17,2441:2 42:10,2543:3,444:4 48:1750:10,12,13,13 50:2551:1 ones 41 :20 one-eighth 29:4 one-quarter 31:4 34: 10 only 8:2127:12 38:24 42:10 51:19 onsite 24:9 OOIP 20:8 open 28:22 52:3,11,16 open-hole 8:22 operate 22:15 operated 29: 10 operations 16:1920:25 25:1,929:10 30:21,24 32:4 operator 31:135:6,7 51:23 e operators 31:3 opportunity 45: 13 opposed 47:20 optimize 43:2 option 17: 1720:5 options 19:20,22 order 1:5 2:4,8 5:135:8 organized 43: 15 oriented 12:18 orifice 30:9 47:8,8 original 19:11 32:19 35:4 Orion 6:3 16:23 37:8 other 21:627:2028:24 43:545:1551:5,17 others 2:19 41:6 out 23:23 24:13 33:20 33:2142:7,947:6 outer 20:22 outline 30:25 over 4:8 34:14 41:21 50:10 overall 20:6 overhead 8:9 overlies 6:20,21 10:5 10:17 overlying9:1914:2,22 34:24 OWCs 13:18 owners 31:3 o'clock 1:9 o-n 37:1 P P 2:1 package 9:4 packer 47:13 packers 28: 11 30:7 47:1,2,11,12 pad 6:237:218:15,20 8:2111:19,19,22,22 12: 1 ,5,6, 10, 12, 16, 17 12:24,2513:14,14,14 13:15,1914:6,7,11 18:15,16,2520:16 21 :4, 1 0, 13, 16,23,23 23:25,25,25,2524:10 24: 1 0, 1 0, 14, 16, 18, 19 24:23,24,25 25:2,10 25:10,18,2033:25 41:1044:2345:2,3 50:4 pads 6:2124:4,19 25:1544:2545:4 pages 53:5 AOGCC December 9,2002 Page 59 pair 11 :23,25 paper 3: 10 partial 17: 12 participating 7:15 15:8 30:24 31 :2,5 participation 52:15 particular 32:5 37:25 40:1647:7 passed 3: 13 past46:12 paths 41:1 pattern 17:11,13 patterns 22:8 pay 14:18 15:4,5,10,11 15:13,14,1839:11,13 45:20 pays 15:7 PBU 6:19,20,21,237:7 30:12 penetrate 7:5 penetrated 39: 13 penetration 32: 11,17 32:22,23 penetrations 7:731:15 31:20 people3:1136:543:16 per 30: 18,19 34: 1741:4 44:5,5,16 percent 20: 1,8 35:4 42:18 perforated 28:4,6 29:6 perforating 46:8 perforations 47:3 perform 33:9,10 performance 21: 19 22:629:2530:14,20 30:2031:11 46:19 performed 17:13 25:5 25:20 periodically 29:24 permafrost 27:2229:8 49:20 permeability 9: 13 17:20,2318:2,6,7,12 45:2247: 17 permits 40: 12 person 2:25 persons 2:213:4,6 petroleum 3:22 5: 18 6:1 16:1626:14,23 27:737:5 ph 40:23 41:23 42:2,6,8 43:3,4,25 Phase 20:2421: 1,2,13 21:21,2422:2,5,6 'T%'il'tUU:i" An3fu~~"p",S¡¡¡mim¡.vg:;ili=. ":::::Tt1:{t(%bjbfG00;'Wt.'KYR~H'"" 907.276.3876 METRO COURT REPORTING, INe. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net e e AOGCC December 9,2002 Page 60 . 45:850:14,14 35:637:839:7,18,23 32:19,2034:1,3,5,9 progress 19:24 question 3:8,9,13,15 pick 52:6 40:3,6 51: 11 34:10,18,20,21 43:17 project 16:15 23:3 36:639:143:17 picked 49: 13 Polaris's 51:5 43:19,2244:2,6,10 26:1534:1944:19,20 45:1951:19 piece 3:9 polygon 13:5,13,15,15 pressures 25:329:16 projector 8:9 questions 3:6,7 4:18,19 pipe 48:23 13:1621:17,23,24 34:1443:7 projects 6:2,7 16:22 4:216:11,12,1416:1 pipeline 25: 11 29:21 44:23 pretty 42:13 51:14 23:726:1937:6,11,12 16:4 17:4,5,723:15 pipelines 24: 1 polygons 21:2329:23 prevalent 8:4 prop 42: 1 23:16,1826:2,527:1 piping 24:9 pool 1:5 2:74:145:1 previous 23:9 propagate 34:22 27:2,435:10,19,25 pitcher 23:22 6: 18,20,22,24,257:6 pre-frac 44:3 properties 18:21,23,24 36:5,13,1437:15,16 PKN 43:8,9 7:6,9,9,10,12,14,16 primarily 50:22 19:5 37:18,2038:22,23,25 place 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post-analysis 43:7 producers 20:721:9,11 published 2: 15 Re 1:3 7:20,218:2,6,10,13 potential 8:16 20:13,16 28:13 29:13 43:25 Pump 24:2 reach 22:524:11 44:24 8:19,20,259:1,3,5,14 21:739:7,1040:7 44:347:2249:18,19 pumped 32:15 42:15 reading 50:20 9:15,20,21,23 10:1,5 potentially 39: 13 50:17,19 pumps 25:628:18 real 45: 17 10:7,7,17,19,1911:2 pound 43:21 producing 41:2 purposes 5:6 13:3 really 42:14,14 45:20 11:10,1613:2,10,12 pounds 41:20,2143:20 production 8:20 11:6 23:2131:9,11 37:20 46:1647:18,19,23,23 13:19,24,24,25 14:1,9 power 25:7 19:14,1620:10,20 put25:15 38:25 40:19 reasonable 32:1834:11 14: 12,13, 16, 18,22 practices 19:21 22:16 21:824:7,2125:23,24 47:11 34:11 15:2,3,5,6,9,12,16 predicted 8:3 13:25 27:10,23,2528:16 puts 50:19 reasons 40:2442:25 16:15,2317:11,15,15 prefer 35:21 29:4,22,2530:11,12 PVT 14:1 18:18,20,23 51:24 18:6,23 19:2,10,18,19 Preliminary 19:23 30:15,16,1831:932:8 18:25 received 3:215:23 19:2220:5,1022:2,12 prepared 4:2535:9 39:7,10 41:1142:2 16:1523:326:15 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since 4:9,10 6:2,57:6 16:2519:1523:7,8 26:19,2233:337:7,9 single 18:928:8,9,11 site 24:1625:22 sites 23:24 sits 45:2,3 sitting 3: 11 situated 12:8 six 29:4,2149:11,12 size 24:23 41: 1742:24 47:8 sizes 42:25 slash 13: 15 18: 19 slight 25: 17 slightly 9:4 Slope 6:19 27:20 slotted 28:429:5 small 12:14,23 51:14 smear 13: 12 smearing 12:23 Smith 43:3 Sohio 6:126:1737:5,12 solid 29:6 solution 17:18 33:22 907.276.3876 METRO COURT REPORTING, INC. 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net .ome 12:14 20:14 35:12 38:4,22 40:6 41:20 42:16,1945:1847:1 something 38:343:19 somewhat 18: 13 somewhere 44:8 sorry 11 :22 sort 48:649:22 source 31: 12 south 7: 17 12:5,6,7,11 13:1514:1921:10,23 39:9 southeast 11: 18,21 12:21 southern 12:11,16 southwest 7:21 9:4 south-southwest 9:5 space 24: 1737: 1 spaced 9:9 spacing 17:13 22:12,13 50:4 speak 31:13 48:3 49:21 specifically 51 :25 spell 2:22 16: 10 22:23 26: 11 36:23 spelled 3:205:2216:12 . 16:13 23:126:13 37:1 spill 8:16 spinner 46:4 spinners 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Tech 16:17 technical 45:10 technique 46:7 techniques 22:543:3 Technology 16:17 temperature 18:16 33:9,11,16,2042: 1 48:4,6,6,10,21,25 49:4,6 term 12:9,9,1513:15 19:1445:3,18 terms 47:25 test 14:1 19:1725:14 25:1530:19 tested 19:13 25:14 30:17 testified4:1123:8 testify 2:21 testimony 2:18,19,25 3:54:1,236:168:8 15:2435:936:12 46:350:2452:15 tests 44: 3 Texas 4: 12 26:20 thank 3:18,18 4:6,7,25 5:6,86:1716:626:6 26:10 27:8 35:11,17 37:1938:12,13 39:14 39:1943:1145:21 52:14,18 their 2:22 3: 1728:25 themselves 3: 17 theoretical 30:15 thick9:14,181O:6,11 10:1834:24 thickness 9:8 10:1 15:6 15:11,14,17,19,20 thief 46:6,9 thin 9:4 10: 1 0,23 thing 37:22 39:21 things 45: 19 think3:11 35:1638:21 43:6,2344:7,846:12 AOGCC December 9, 2002 Page 62 49:6 thin-bedded 10:4 third 12:8 three 9:2 10:8 11: 17 12:1,120:17,1921:1 29:530:1831:21 41:447:2,349:10,11 49:12 three-eighths 33:24 through 2:13 7:2415:6 15:10,13,1921:933:6 34:2241:18,2250:2 50:1853:5 throughout 22: 18 thrown 12: 11 tie-in 24:24 tighter 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2:6 7:1712:12 31:2232:2233:10,14 49:7,8,13 50:13 51:20 validate 21:2 42:23 52: 11 14:1939:4,853:8 33:21 34:2 TW-C 12:9,13 45:1 value 38:7 wants 39:1,3 western 11:12 30:12 type 8:24 24:24 39:7 values 17:20,22 18:25 wasn't 42: 10 west-dipping 11 :24 y 41:2343:845:9,11 valve 49:16,25,25 50:1 water 6:614:12,14 wet 10:15 41:10 yeah 35:1636:1043:5 49:22,25 50:3 17:16,2518:119:23 we'll 2:20 3:4 6: 15 8: 12 43:2146:2448:2 types 45:11,13 50:13 valves 25:16,18,18 20:4,7,10,10,2521:25 17:823:2027:6 50:12 Typi 40:22 29:10 49:21,23,25 23:2224:9,25,2525:2 35:1437:1938:14,21 year 16:18 29:20 typical 28: 1241:7,17 variability 47: 17 25:2,6,8,8 30:5,8,22 44:2,746:347:7 years 4:86:134:437:6 typically 29: 1 40:20 variable 18:13 31:8,1233:12,1434:5 48:10 52:10,16,18 . 41:648:16 variation 45:2247: 18 34:11,17,1842:551:2 we're 2:5 38: 18,20 Z 48:17 51 :3,4,8,9 40:1642:1644:7 zero 14:1734:12 U variations9:818:1,2 waterflooding 35:3 45:6,1748:19,22 zonal 32:21 33:3,7,13 Ugnu 6:24,257:3 8:23 18:21 water-bearing 11: 1 50:2551:13 33:1547:2 9:15,1914:22 varied 18:441:18 water-cut 28: 17 we've 35: 12 38: 19 zone 17:23 28:8,10 Ug440:5,7 42:25 week 52:5,7 40:1541:1,3,9,18,20 33:2041:543:1,6 unconsolidated 10: 11 variety 4:86:2 16:22 Weisak 46: 13 41 :22,24 48:1549:1,9 10:23 23:637:6 well 7:4,5 8:24 12:9,9 while 20:14 24:12 zones 39:24 46:6,9 under 36:2 38:6 various 8:1718:4 26:18 12:1513:15,20,21,22 whistle 23:23 48:15 underlying 9: 11 14:3 34:543:16 13:2214:1217:12,14 wide 39:5 34:24 vary 8:18,18 18:2019:3,17,17 willing 39:3 0 understanding 22:3 varying 28:16 20:15,1821:6,7,15,16 wireline 8:22 o 11:12 45:9,11 vendor 43:4 21:18,2522:12,13 wish 5:10,1723:11 0253:5 understood 50:21 verify 30:20 24:4,13,18,2425:14 36:19 unit 6:198:189:15,21 versus 42: 15 25:2027:14,1828:3,7 wishing 2:12,19,21,25 1 11:13 14:15 18:11 vertical 8:24 10:13 28:12,13,16,2329:7 3:3,4 124:3 27:2031:835:746:8 29:1340:2245:12,24 29:19,2230:6,7,15,19 witness 2:21 4: 12,16,24 1,00034:844:6,8,16 units7:18:179:610:4 50:15,18,22 31:1732:6,833:1 5:11 6:8,15 17:1,8 1,20040:5 10:8,20,2411:1,2 vertically 10:25 14:2 36:2240:2241:4 23:9,21 26:23 36:20 1,50034:840:444:9 University 3:23 5:24 18:2249:4 42:643:1,1544:14 37:13 102:59:1715:9,14 23:526:1737:4 very 2:1010:2222:9 45:3,10,11,14,1846:5 witnesses 3:735:25 20:134:2435:3,16 unsteady 18:7 33:538:12,2043:15 46:15,2547:7,949:10 work43:5 46:23 47:16 10:0038:15 unsworn 3:4 46:15,1748:1152:14 49:20,2450:4,16,18 worked 4:7 6:1,616:19 10:13 38:16 until 33:21 52: 11,16 via 23:5 50:25 16:21 23:626:18 10:4538:17,19 updated 29:16 viable 17:1620:4 wellbore 28:2541:1 37:6,10 1002:6 10:642:18 updip7:1714:16 vicinity 6:21,23 11:16 44:1 working 6:4 16: 14,24 48:21 upper 9:19,2014:21 Victor 37:1 wellhead 44:6,9 20:2223:226:14,21 100,00041:21 ~pp"most 40,5 VIII-134:3 wells 7:8,10 9:9 12:7 37:848:22 1000 9:9 pward 9: 16,17 10:2 VII-231:14 14:11 19:13,1820:13 write 3:8 11009: 14 METRO COURT REPORTING, INe. 907.276.3876 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net .25:211:433:13 38:15 40:4 45:6 12th 53:10 120 19:648:20 13 33:24 147:111:4 14,00045:7 1520:6,735:2238:21 160 10:6 162041:24 176:133:2 18010:18 194:837:6 19697:5,6 197726:16 198026:18,19 1981 23:7 19833:23 198816:18 19936:2 199437:7 19974:9 19984:10,11 6:516:25 37:9 199926:22 .24:2 2 2,00040:9 2,18018:14 2,24018:15 2,30034:1943:23 2,50044:5 2,80034:2043:19,21 202:1711:10 22:13 24:2232:7,935:3 44:1848:22 20,00034: 1741:20 200 18:20 200i 32:1 200023:524:15 200123:8 20021:82:4,165:2,3 30:13 53:10 210 14:6 212i 34:4 213 12:819:15 22-11-12 13:15 23rd 30: 13 259:18 19:6,820:6,7 25,00034: 1744: 18 51:12 25.412 32:7 .5.5402:18 ~50 10:1819:11 1f'á.0';-"-"ni''''C''''''''''''·';'''''''''''''''''''k'<;ZZei'''''~,;,;,;,; 907.276.3876 e 255 32:23 26-12-127:4 290 14:6,8 3 3D 11:14 3,00040:944:5 3,50020: 19 3020:7 300 10: 1 19:9 31st 5:3 3332:653:8 34010:1 35 14:8 20:7 35019:10 4 4 11: 12 4:3052:10,11,16 484:9 48007:22 5 5,00018:1529:17 44:1651:13 50027:21 500018:16 52 53:5 55019:9 597: 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Distance W..200/W..212i Well Pair Model Time = 2385 da s 4 ears of In"ection 500 1000 1500 2000 2500 3000 Distance from Injector (feet) #5 e . STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION POLARIS POOL RULES AND AREA INJECTION HEARING DECEMBER 9, 2002 at 9:00 am NAME - AFFILIATION (PLEASE PRINT) Kýde.i / í?e.l~fs 5rn7/M47ÍÍ;9U (-;>/:1 ,(5elA~r-(.r- 71t/f/<t5 ~-J7/~( ~ Ú&"~K.'- 'D ¿n·.) ¡r/ _ç c ¡, j11f () A v ; '-¡;.~e, ê·" r ~ V"u ~ S' f-,/\,r -\ '\ ADDRESS/PHONE NUMBER TESTIFY (Yes or No) BP ¡Bp 8,0 ß? RP I3fJ Bf r...> ¡-. ,.~ I~' BP " 5ftJl/- S7l.{ I ~4 ~tf 3C.;¿ S6 </~ 5") <./.J f)b'f-~/S? 5h'l- 616t/ 5 6 "I ~ j',-/9 0/' ..:::;7P t./ ~ S;I 9 çc, L{ SaC¡.3 SlfI -/";;)'304- Vc) )k5 Y-<J jes. ¡j~'S f,.,I '" ç"' I è .,;I IJ 1\/0 IVo lVeJ {Vo Æ Ah No 0' A R.,,\ G ùST~ (==.5 () I\.J k'ý~steh Ne 0 n (V)AllbAP<e1 VJod~ f:'IYaJM[)PM. ...--:--f Y \ :JC ··f ~r/" &Y¿H/I~./ :5/-c--v e... ...»~ '" I~ A DC?CL VJ.~ÞM Ji¡\¡\~4~_ ::s ~é .s~CX;;'02-J' 5,,4'317~ S b '7 -J'6c:.fc,1 7CJ3-/224 It?, I 1~3'-1 Zðlp ÚJÑCU ~fttLt P J Z b.f" -C. 2'1 ., ¡J,o NO . . STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION POLARIS POOL RULES AND AREA INJECTION HEARING DECEMBER 9, 2002 at 9:00 am NAME - AFFILIATION ADDRESS/PHONE NUMBER TESTIFY (Yes or No) (PLEASE PRINT) fV, ~ .!.<~ i< Ií) +0"'"' S ~f P l? ~/J)Ô 616 c:J6f. 8&;/ ~ Vo .. - ALASKA OIL AND GAS CONSERVATION COMMISSION NAME - AFFILIATION (pLEASE PRINT) Date: /2-4-0-z.-- Time (?X)r~, MEETING - Subiect fö(o..fA::; I " , ¡ I' vI e ~!C' I {/..( ¡"'l,{ S' (.ì '·1 ]? q/fJ III Sc.- 4 HfJ h r'~ 1 'jØuqja5 thn1í&h ~d:~'\ Ber~_~/' Kyðt!J I ¡¿~~ iJ'ïfs ~tlf1- k~d¡~ - ¿!~n SC:,e> II IJ. ~A--nJ5 ~ - -<;¡~ v-<- f") Q. Vl..è $ J;M 1<~1 TELEPHONE <1 ~pr! 6f ßf 13? .ßp 6f> 5~-tj3~? -.... Tlæ-;;Lc- Að~Cc. + #4 STATE OF ALASKA ADVERTISING ORDER . NOTICE TO PUBLISHER . INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-02314021 F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF 'A.O. Jody Colombie PHONE November 7.2002 PCN ¿ Anchorage Daily News POBox 149001 Anchorage, AK 99514 (907) 793 -1 ?? 1 DATES ADVERTISEMENT REQUIRED: November 8, 2002 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal o Display Account #STOF0330 Advertisement to be published was e-mailed o Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING REF TYPE 1 VEN 2 ARD 3 4 FIN AMOUNT 2 3 NUMBER AOGCC, 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 AMOUNT DATE I I TOTAL OF PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS 02910 SY CC PGM LC ACCT FY NMR DIST LlO 03 02140100 73540 R;~NED BY:Q\ J' 0.. \ --- (?'\)C'~ ~ J U ') DI;aISION APPROVAL: . '. Air! l Æ1'Y\hÓ fJuJv~ _~~ ~_ 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM 'ChOrage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 . PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 632788 11 /08/2002 02314021 STOF0330 $101.38 $101.38 $0.00 $0.00 $0.00 $0.00 $0.00 $101.38 STATE OF ALASKA THIRD JUDICIAL DISTRICT Amy Heath, 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 said tini.e 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 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. Signed 01111 ¡~ â Subscribed and sworn to me before this date: If If (02 Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska } l MY COMMIS ION EXPIRES &/z'1¡'O:5-., ~£; W \\l( (({ff \.\\\þ-~\E s. 0." r~ ~O~ .. ;.:.:.-.. 4tb , ........".. $~:~O'TA",.:.. -.;. '- . ~ ....- . ~ ª : PuB\..\C : ê ~'.~ _..- ,;:N~ ~~~~OF~·~ct~ :¿/;S·~~,'\'\ :/JJJJJJ)J))')' Notic:e of Public: Høinll < STATEOFAtASJ(Å' ...</ ". AlaSka 0' CUIII.~<:ønlieJ'VatIotfcornrni$si'" Re:PolarisOIlI"'oQI, Prudhoè Bay Field Pool Rules cmdAreQfniectionOrder BP E¡cploration (Alaska),lnc Alaska, Inc. by ap- plication dated OCtober 31, 2002' has applied for .an area iniectionorder and pool rUles Iinder20 AAC 25.460 and 20AAC 25,520. respectively, toeovern ~T:I~;g::'tt~~~:rÍles'jg~~r::.2l~~~~I",prlidhoe Bay The CQlTI.mission.t)as· $lit a public Marine on this application for DeCf,ll'\"lber .9, 2002 at9:00am at tt)f,I Alaska 011 and Gas ConservationCOmminion at 333 West 7th AVenuII/Slifte 100, Anchorage, Alaska 99501. . .... .. , :::1I~rsd~~~~fn~t'fi~:k'W~a\ro~n:~t.:tI¡'~k~081; arid Gas C"onservotran' Commissfon~t 333 West 7th Ayenlle, Sliite 100, AnchotOlle, Alaska 99501. Writ. ten comments mllst be received no Iater than 4.: 30 pm on December 9, 2002. Hvou are åperson with a disability who moy need a speclatmodlfìcation in Qrderto comment or to attend thi! public heating, please contact Jodv Co- lombiè at 79J.l.221 be!<,re r:>ecember 4. 2002. !s/ C'arnmY OechsH Tóylot', Chair PUbHsh: Nov.ember" '2002 . , ' RECEIVED NOY 20 2002 ";.Iaska Oil & GaG Cons. CommlsSIO! Anchorage · e Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Polaris Oil Pool, Prudhoe Bay Field Pool Rules and Area Injection Order BP Exploration (Alaska), Inc Alaska, Inc. by application dated October 31, 2002, has applied for an area injection order and pool rules under 20 AAC 25.460 and 20 AAC 25.520, respectively, to govern development of the Polaris Oil Pool, Prudhoe Bay Field, on the North Slope of Alaska. The Commission has set a public hearing on this application for December 9, 2002 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on December 9,2002. 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 December 4, 2002. ~~~~~~ Cammy êechsli TaylotJ Chair Published Date: November 8, 2002 ADN AO 02314021 Re: Ad Order . Subject: Re: Ad Order Date: 07 Nov 2002 10:39:44 -0900 From: Amy Heath <aheath@adn.com> To: Jody Colombie <jody_colombie@admin.state.ak.us> Account Number: STOF0330 Legal Ad Number: 632788 (Public Notice) Run Dates: November 8, 2002 Total Amount: $101.38 Thanks Jody! :) Amy L. Heath Legal Customer Service Representative Phone: (907) 257-4296 Fax: (907) 279-8170 Office Hours 8:00am - 5:00pm legalads@adn.com 1 of 1 . 1117/2002 1 :45 PM STATE OF ALASKA ADVERTISING ORDER e NOTICE TO PUBLISHER . INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-02314021 F AOGCC 333 West 7th Avenue, Suite 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF A.O. lod)' C010mbie November 7, ?OO? PHONE PCN (907) 793 -12?1 DATES ADVERTISEMENT REQUIRED: November 8, 2002 R ¿ Anchorage Daily News POBox 149001 Anchorage, AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account #STOF0330 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 swom, 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 2002, and thereafter for _ consecutive days, the last publication appearing on the _ day of . 2002, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and swom to before me This _ day of 2002, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER Re: Legals . . Subject: Re: Legals Date: Thu, 07 Nov 2002 17:25:54 -0900 From: Jody Colombie <jody _ colombie@admin.state.ak.us> To: Amy Piland <classifieds@gci.net> Amy, Please publish the attached. Thank you. Jody Amy Piland wrote: > Hi Jody- > Do you have any new legals for me to list in the paper? I have not > heard from you in awhile, just wanted to touch base with you. Looking > forward to hearing from you! > > Amy- > > -- > Amy Piland, Classifieds dept. > Petroleum News Alaska -- Alaska's weekly oil & gas newspaper > ph: (907) 644-4444, fax: (907)522-9583 > email: classifieds@gci.net > http://www.PetroleumNewsAlaska.com ~Notice _Polaris.doc Name: Notice Polaris.doc Type: WINWORD File (applicationlmsword) base64 1 of 1 11/7/20025:26 PM Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Mir Yousufuddin US Department of Energy Energy Information Administration 1999 Bryan Street, Ste 1110 Dallas, TX 75201-6801 Michael Nelson Purvin Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 T.E. Alford ExxonMobilExploration Company PO Box 4778 Houston, TX 77210-4778 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 e SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 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 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 Texico Exploration & Production PO Box 36366 Houston, TX 77236 W. Allen Huckabay Phillips Petroleum Company Exploration Department PO Box 1967 Houston, TX 77251 Shelia McNulty Financial Times PO Box 25089 Houston, TX 77265-5089 James White Intrepid Prod. Co./Alaskan Crude 4614 Bohill SanAntonio, TX 78217 e John Katz State of Alaska Alaska Governor's Office 444 North Capitol St., NW, Ste 336 Washington, DC 20001 Alfred James 107 North Market Street, Ste 1000 Wichita, KS 67202-1822 Conoco Inc. PO Box 1267 Ponca City, OK 74602-1267 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 G. Scott Pfoff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 William Holton, Jr. Marathon Oil Company Law Department 5555 San Fecipe St. Houston, TX 77056-2799 Corry Woolington ChevronTexaco Land-Alaska PO Box 36366 Houston, TX 77236 Donna Williams World Oil Statistics Editor PO Box 2608 Houston, TX 77252 Shawn Sutherland Unocal Revenue Accounting 14141 Southwest Freeway Sugar Land, TX 77478 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Tim Ryherd State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Jim Arlington Forest Oil 310 K Street, Ste 700 Anchorage, AK 99501 Ed Jones Aurora Gas, LLC Vice President 1029 West 3rd Ave., Ste 220 Anchorage, AK 99501 Susan Hill State of Alaska, ADEC EH 555 Cordova Street Anchorage, AK 99501 John Harris NI Energy Development Tubular 3301 C Street, Ste 208 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Mark Hanley Anadarko 3201 C Street, Ste 603 Anchorage, AK 99503 e George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Cammy Taylor 1333 West 11th Ave. Anchorage, AK 99501 Duane Vaagen Fairweather 715 L Street, Ste 7 Anchorage, AK 99501 Julie Houle State of Alaskan DNR Div of Oil & Gas, Resource Eva!. 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Trustees for Alaska 1026 West 4th Ave., Ste 201 Anchorage, AK 99501-1980 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Rob Crotty C/O CH2M HILL 301 West Nothern Lights Blvd Anchorage, AK 99503 Mark Dalton HDR Alaska 2525 C Street, Ste 305 Anchorage, AK 99503 e Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Richard Mount State of Alaska Department of Revenue 500 West 7th Ave., Ste 500 Anchorage, AK 99501 Williams VanDyke State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Robert Mintz State of Alaska Department of Law 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Jack Laasch Natchiq Vice President Government Affairs 3900 C Street, Ste 701 Anchorage, AK 99503 Judy Brady Alaska Oil & Gas Associates 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503-2035 Arlen Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,lnc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 BP Exploration (Alaska), Inc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Bob Shavelson Cook Inlet Keeper PO Box 3269 Homer, AK 99603 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 e Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw - MS 575 Anchorage, AK 99515 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Peter McKay 55441 Chinook Rd Kenai, AK 99611 Penny Vadla Box 467 Ninilchik, AK 99639 e Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Jim Ruud Phillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 Dudley Platt D.A. Platt & Associates 9852 Little Diomede Cr. Eagle River, AK 99577 Shannon Donnelly Phillips Alaska, Inc. HEST -Enviromental PO Box 66 Kenai, AK 99611 Claire Caldes US Fish & Wildlife Service Kenai Refuge PO Box 2139 Soldotna, AK 99669 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Senator Loren Leman State Capitol Rm 113 Juneau, AK 99801-1182 . Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 - John Tanigawa Evergreen Well Service Company PO Box 871845 Wasilla, AK 99687 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 #3 bp . e o BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 November 1,2002 BY FAX AND U.S. MAIL Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RECEIVED RE: Polaris Pool Rules and Area Injection Order Application Confidentiality of Certain Exhibits NOV 0 6 2002 Alaska Oif·& Gas Gons. Commission Anchorage Dear Commissioners: The letter confirms and explains the basis for our request for confidentiality for certain Exhibits to the Polaris Pool Rules and Area Injection Order Application ("Application"). Our initial request for confidentiality was made in the cover letter to the Application dated September 12, 2002. Each of the confidential exhibits and documents that we have provided contain trade secrets. AS 45.50.940(3) provides that information qualifies as a trade secret if it "derives independent economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from its disclosure or use, and (B) is the subject of efforts that are reasonable under the circumstances to maintain its secrecy." These exhibits include interpretations of geological and geophysical data or computer modeling methodologies. This information is used by the Polaris Owners to make development, exploration and leasing decisions, and is maintained as confidential. It cost substantial amounts of money to develop this information, and it has commercial value. Thus, under the applicable constitutional, statutory and common law doctrines that protect trade secrets, we request confidentiality of this information be maintained by the Commission. In addition, in the interest of providing the Commission with a full view of Polaris development, the Polaris Owners have voluntarily provided a wide scope of information that is not required to be filed with the Commission under AS 31.05.035(a).1 Accordingly, we also request confidentiality as to the marked exhibits pursuant to AS 31.05.035(d) and 20 AAC 25.537(b). These exhibits have been voluntarily submitted to the Commission, and are independently to be held confidential pursuant to AS 31.05.035(d) and 20 AAC 25.537(b). 1 The period of confidentiality applicable to the information in the Application that was required to be filed under AS 31.05.035(a) - i.e. certain well and flow test information - has expired. The exhibits containing that information is not marked "Confidential." · e We request that confidentiality be maintained indefinitely. To the extent any question is raised at the hearing for a limited need to disclose any of the confidential information, we assume that the Commission will follow the procedures specified in 20 AAC 25.540(c)(10). Please consider this letter as part of the Application and issue the notice of hearing without delay. If you would like more dialogue on these issues prior to issuing the notice, please contact Rosy Jacobsen (564-4151) as soon as possible so that we can schedule a meeting with you. Thank you. Sincerely, .-~~ Gil Beuhler GPB Satellites Team Leader Cc: R. Smith (BP) M.M. Vela (ExxonIMobil) J.P. Johnson (ConocoPhillips) S. Wright (Chevron Texaco) P. White (Forest Oil) e . ALASKA OIL AND GAS CONSERVATION COMMISSION .. 333 WEST 7TH AVENUE, SUITE 100 ANCHORAGE ALASKA 99501-3539 FACSIMILE TRANSMITTAL SHEET TO: Rob Mintz Assistant Attorney General FROM: oct~ DATE: \ \1 Y OJ . Total No. Of Pages Including Cover: 0 Re: NOTES/COMMENTS Phone No. (907) 793-1221 Fax No. (907) 276-7542 11/04/2002 17:58 FAX GPB RESOURCE DEV \4]001 e -- BP EXPLORATION BP Exploration (Alaska) Inc. PO Box 196612 Anchorage, Alaska 99519-6612 Date: 1/ ~ 4. ?1rIL TO: Name: TELECOPY COMMUNICATIONS CENTER (1 A-r1rAn--( ~.o ~ MA7) FROM: Fax # ólll" -7<5 t/'L Confirm # C51P4Æ579 7 Name & Ext.: ~. · &II~ Company: Location: NOTES: PAGES TO FOLLOW d- (Does Not Include Cover Sheet) ·S.ÊC'Ü"Rí"TY'·'êLAsšl·F"íêÃTíO"Ñ"·'·c.~=;"·'"·" ',."'-"""""'''''"'''''''''''''",.,~..,...",.~>,,,.,,,.,....···.·,·"""·,·,·····,'·""';"F'''·'''·,···",,,',·,·,,,·,,,·,.,.,...., ·""':~';·;;;_:,,";,:..,:(·:;,;,?T·':'·;.', .",.". PRIVATE SECRET ~ONFIDENTIAl , ". ..:.,...:.~'0õ.'::~.::.:~.:,::;:. ":: .:".n .....;u:_" '-_ ~ , '.:. .'.:. '~,:':'~1';Þ.::'...:b:±-~:~:~·:·3:'-:c':/:;·.;':<:-\!':F.,,~~~·· :.: "'::;'Ì;'::~.,: ~ 'ff:'..,. . ":' ."::~~~'. :,:::£";·:.:::,.i;':~·;;¡""~:':-·?:'¡';';':· ·.C. . .,........~..... .... . .. '~T'!";"'.:.,_>:,,··_'~.. , . .... ,.... _..~ .. Confi011 # 564-5095 For Communfcations Center Use Only Time In Time Sent Time Confirmed Confinned By RE(~EI\j[D Telecopy # 564-5016 1.i AIa&ka t1I &. Gis Coos. (.¡{jmmI5Slon Anc;'!io~e #2 bp . . o BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 October 31, 2002 Commissioners Alaska Oil and Gas Conservation Commission 333 West th Avenue, Suite 100 Anchorage, AK 99501 RECEIVED OCT 3 1 2002 AlaSRaOi~Bt Gas Qons. ÐmnmtssJøn Anclìarage RE: Polaris Pool Rules and Area Injection Order Application Dear Commissioners: This letter responds to your October 1, 2002 Email, which is attached to this letter and marked as Exhibit VII-1 to the Polaris Pool Rules and Area Injection Order Application ("Application"), requesting additional information. Please consider this letter and attachments as part of the Application and issue the notice of hearing without further delay. Miscible injection (Mf): The Application includes a request for approval of injection of miscible injectant ("MI") to implement an Enhanced Oil Recovery ("EOR") project. By this letter, we withdraw that at this time. If the Polaris Owners decide to institute an MI-based EOR project in the future, an amendment of the Area Injection Order and Pool Rules will be sought, as appropriate. Wells within the %-mile Area of Review (AOR) Your October 1,2002 Email stated, "The Area of Review ("AOR") for the Polaris waterflood project extends a radius of % mile from the base of the confining layer for each proposed injection well. Mechanical integrity must be demonstrated for each well within the AOR. Please provide a listing of every well within each AOR." After receiving this Email we clarified with Jane Williamson that the "confining layer" for each injection well would be defined as the top of the Ma sand. Exhibit VII-2 shows all Schrader Bluff penetrations at the Ma sand, and a % mile radius is shown around the location of the point at which each existing and currently-planned injection well is estimated to intersect the top of the Ma sand. Currently, there are 3 Polaris injection wells that have been drilled and cased, W- 212i, S-215i and S-104i (dual Kuparuk and Schrader Bluff injector). This Application also provides information on the AOR for two additional proposed injection wells, W-207i and S-200i, which are planned to be drilled in the near . . future. Well bore diagrams forW-212i, S-215i and S-104i are attached as Exhibits VII-3, VII-4 and VII-5. Since W-207i and S-200i have not been drilled the well bore diagrams are not included, but will be provided with the AOGCC 10- 403 Form for each well. For any additional future injection well, information on the AOR and the well bore diagram will be provided with the AOGCC 10-403 Form. The following wells are within the AOR of these injection well locations: W-212i W-17 S-215i None W-207i Kuparuk State 22-11-12 Kuparuk State 24-11-12 S-20Oi S-03 S-24A S-31 A S-200 PB 1 S-1 04i None The Application as originally filed indicated the W-15 well was within the AOR of the W-212i well. Because of the clarification that the AOR should be determined by reference to the top of the Ma sands, this well is no longer within the AOR, while the Kuparuk State 22-11-12 is now within the AOR. Accordingly, attached as Exhibit VII-6 is a well bore diagram for Kuparuk State 22-11-12. Mechanicallnteqritv Exhibit VII-7 provides references to the mechanical integrity standards used in the preparation of the Application. Exhibits VII-8 to VII-14 are data sheets constituting the "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, " by 20 AAC 25.402(c)(15). In addition, a summary of the AOR Schrader Bluff penetrations is shown as Exhibit VII-15 as well as a comment on each penetration regarding confinement of fluids within the Schrader Bluff formation. Fracture Pressure Your October 1,2002 Email includes the following statement: "It is our understanding that fracture conditions discussed in the application were the result of injecting highly viscous fluids at high rates (15 barrels per minute) for the purpose of stimulating the well. During our discussion, you stated that these conditions represented a worst-case scenario, which did not result in net pressures, sufficient to frac through the confining layer. Conditions for planned waterflood will be at lower rates (about 2 bpm) and result in lower net pressures, and are unlikely to cause fracturing through the confining layer. Should fracturing occur, fluids will remain within the Polaris Pool. In the unlikely event that the Mb2 mudstones above the planned injection interval is fractured, the water will preferentially enter the highly permeable Mb sands, which you are requesting as part of the Polaris pool. Please verify if we understood correctly." . . Your understanding is accurate. The following provides some additional technical information. The fracture conditions discussed in the Application were the results of data fracs, which were pumped prior to well stimulation treatments with a high viscosity (non-newtonian, cross-linked polymer) fluid at approximately 15 barrels per minute (bpm). Net Pressure, which is defined as the pressure above the closure pressure, is Pn-(E3/4/H)(uQL) 1/4 where E=Young's Modulus, H= Frac height, u=viscosity, Q= Rate and L=frac length. Since we will be injecting water with a viscosity near 1 and at rates of approximately 2 bpm, it is unlikely that we can develop net pressures that approach what was measured during the data fracs. The net pressures developed during the data frac were below the confining stress barriers, measured during a stress test and validated with a DiPole Sonic Log. Even if fracturing did break through the Mb2 mudstones the water will enter the highly permeable Mb sands, which we have requested to be included in the Polaris Pool, where the pressure would dissipate. Other Information (from an earlier data request) Also enclosed are Exhibits VII-16, 17 and 18, three poro-perm crossplot figures (poro-perm from core data) - one each for the M, N, and 0 sands. Please contact me at 564-5143, or Donn Schmohr at 564-5494 with any questions or comments regarding this response. Sincerely, ~~ Gil Beuhler GPB Satellites Team Leader Attachments cc: R. Smith (BP) M.M. Vela (Exxon/Mobil) J.P. Johnson (CPAI) S. Wright (Chevron Texaco) P. White (Forest Oil) . . Exhibit VII-1, 1 of 2 -----Original Message----- From: Jane Williamson (mailto:Jane_Williamson@admin.state.ak.us] Sent: Tuesday, October 01, 2002 9:35 AM To: Schmohr, Donn R Cc: Beuhler, Gil G; James B Regg; Stephen F Davies; John D Hartz Subject: Polaris Application - Outstanding Items within Area Injection Order Don, We would like to thank you for meeting with us yesterday to discuss outstanding issues concerning the Polaris Pool Rules and Area Injection Order. While your application submitted on September 12, 2002 was very well constructed, the Commission needs additional information within the Area Injection Order application before we can deem it complete. We recommend that BP make separate application for an MI-based Enhanced Oil Recovery project to prevent delay of the current Polaris project. Miscible injection ("MI") presents numerous technical and regulatory challenges that have not been fully addressed in this application. Assuming that MI is excluded from this application, the following are clarifications and items we need within the Area Injection Order application. As noted in Jack Hartz's e-mail to GiI Buehler (September 17, 2002), confidentiality of exhibits will also need to be sorted out prior to deeming the application complete. Area of Review The Area of Review ("AOR") for the Polaris waterflood project extends a radius of 14 mile from the base of the confining layer for each proposed injection well. Mechanical integrity must be demonstrated for each well within the AOA. Please provide a listing of every well within each AOA. Future injection wells not identified in the current application, will require submittal of a 10-401 (new well permit) or 10-403 (conversion to injection) form, establishment of an 14-mile AOR, and investigation of the mechanical integrity of each well within that AOA. Mechanicallnteqritv This issue is important at Polaris because of the presence of many older wells that may not have cement across the Schrader Bluff interval. You presented in spreadsheet that provides basic data on casing and cementing for wells within the AOA. This is an excellent starting point. For each well within the 14 mile AOR, please provide a copy of this spreadsheet, supplemented with following additional information: 1) A conclusion stating whether mechanical integrity has been established for the subject well. 2) The basis for that conclusion, which includes BP's definition of integrity. 3) If integrity cannot be demonstrated, a plan for repair or proposed surveillance must be provided. This plan must discuss limitations due to well construction and any integrity concerns that would trigger additional surveillance or repair. . . Exhibit VII-1, 2 of 2 A copy of the most recent schematic diagram for the subject well is required. Directional survey information and daily operations reports need not be included within the application. Fracture Pressure It is our understanding that fracture conditions discussed in the application were the result of injecting highly viscous fluids at high rates (15 barrels per minute) for the purpose of stimulating the well. During our discussion, you stated that these conditions represented a worst-case scenario, which did not result in net pressures which would be sufficient to frac through the confining layer. Conditions for planned waterflood will be at lower rates (about 2 bpm) and result in lower net pressures, and are unlikely to cause fracturing through the confining layer. Should fracturing occur, fluids will remain within the Polaris Pool. In the unlikely event that the Mb2 mudstones above the planned injection interval is fractured, the water will preferentially enter the highly permeable Mb sands, which you are requesting as part of the Polaris pool. Please verify if we understood correctly. Jane Williamson - Reservoir Engineer Steve Davies - Petroleum Geologist Jim Regg - Petroleum Engineer Alaska Oil and Gas Conservation Commission laris Pool/Injection a Exhibit VII-2 Schrader Bluff Top Ma Sand Well Penetration Locations ¡¡as.B00 6j'L&øe 618.ß\HJ fin.eoa 6Z'Lf1Bø &28.&80 20 13 18 17 19 20 9 ?" Polaris Particinatim! Area Polaris Well Penetration altop !\IIa Sand Polaris Á Injection Well EB 1/4 Mile Radius Circle around existing or Proposed Polaris Injection wells . . Exhibit VII-3 TREE = FMC WELLHEAD = 11" FMC ACTUATOR = KB.ElEV= 84.1' BF. ElEV = 50' KOP = 700' Max Angle = 39 @ 275if Datum IvÐ = 5878' -----~~,~-~- DatumTVD= 5025'SS W-212 I SAFETY NOTES 19-5/8" CSG, 40#,l-80,ID= 8.835" l-i ~ I 3411' I----- " 1014' H9-5/8" TAM PORT COllAR I 2196' H4-1/2"HESXr-.lP,ID=3.813" I Minimum 10 =3.725" @ 5114'1 4-112" HES XN NIPPLE L GAS LIFT MAfo.DRElS ST MD TVD ŒV TYÆ VlV lATCH FDRT DATE 1 4982 4388 40 MvlG RP BK 04/13/02 - -I 5049' H4-1/2" HESXNIP, ID= 3813" 1 14-112" TBG, 126#, l-80, Tal, H 0.0152 bpf, ID= 3.958" I :8: ~ 5070' H4-1/2"X7-5J8"BKRS-3A<R,ID=3875" I - ---1 5093' H4-112" I-ESXNIP, ID= 3813" I ----1 5114' H4-1/2"HESXN NIP,ID= 3725" I 5126' 1- ~ I 5127' H 4-1/2" WlEG I H Eltv() TT NOT lOGGED I ÆRFORA TION SUMMA RY R8' lOG: A NGlE AT TOP PffiF: Note: Refer to Production œ for historical perf data SIZE SF!' INTERVAL Opn/Sqz DATE H 5733' H7"RJPJTW/RA TAG 1 I PBTD H 17" CSG, 26#, l-80, ID = 6.276" H 6320' ~ 6212' DATE REV BY COMvlENTS 04/13102 .LMlKK ORIGINAL COMR.ETlON DA TE REV BY COMtvENTS FRUDHOE BA Y UNIT WElL: W-212 ÆRMT No: 2020660 AR No: 50-029-23078 SEe 21. T11 N, R12E. 906' SNl, 1185' WEL BP Exploration (Alaska) . TREE = ON 4-1/16" 5M WELLHEAD = FM:GEN5 A CTUA TOR= m·......·..........···.·....__._..·_........._.._...._...mm._._..... KB. ELEV = 72' BF ELEV = 41' KOP = ···------2238' Max Angle = 50 @ 3723' ÖãiUïiï·M');;·--·---···-··--····-····· Datu m TV D= 19-518" CSG, 40#, L-80, 10 = 8.835" H 2946' I Minimum ID = 3.725" @ 5648" I 4-1/2" HES XN NIPPLE 4-1/2" TBG, 12.75#, 13-CR-80, .0153 bpf, 10 = 3.958", 4-1/2",126#, L-80 PUPS ABOVE & BELOW ALL JE'NEL RY FffiFORA TION SUM'v1ARY REF LOG: ____ ANGLE A T TOP ÆRF: Note: Refer to A"oduction DB for historical perf data 9ZE SFF INTERV AL Opn/Sqz OA TE I FBTD H 7" CSG, 26#, L-80, 10= 6276" H DA TE REV BY COM'v1ENTS 08116/02 OAV/KK ORIGINALCOMR...ETION 5-215 .. ~ = ~ I I- L I I :8: . Exhibit VII-4 SAFETY NOTES: 4·112- CHROMETBG. I 114' H 20"X34"215.5Ib/ft,A53ERWINSULATED 976' H TAM FDRT COLLAR I 2224' H 4-1/2"HESXNIP,10=3.813" I t ST 1 GAS LIFT MANDRELS M) TVO ŒV TYÆ VLV LATCH FDRT OATE 3476 3203 50 KBG-2 RP BK 08/16102 5535' H 4-1/2" BKR CCM SLlDNG SL V, I I W/4-1/2" X NIFf'LE, 10 = 3.813" :8: --- 5599' H 7" x 4-1/2" BKR FRM R<R, 10 = 3.875" I 5626' H 4-1/2" HES X NIP, 10 = 3.813" I 5648' H 4-1/2" HES XN NIP, 10 = 3725" I 5660' H 4-1/2"WLEG, 10= 3.958'" H ELM TT - NOT LOGGED I 5659' r --¡ ---------1 5741' H T' MARKER JOINT I ---1 6204' H T' MARKER JOINT I 6834' ~ 6915' OATE REV BY CD M'v1ENTS FDLA RlS UNIT WELL: S-215 FÐ,MT No 2021540 AA No 50-029-23107-00 SEC. 35, T1~N, R12E, 3276' NSL, 4563' WEL BP Exploration (Alaska) . TREE = WEUHEAO = ACTUATOR = KB. ELEV = BF. ELEV = KÒp;- Max Angle = Datum MO = DatumTVO = 4-1116" OW FMC NA 64.S0' 38.22' 7S0' S7 @ 3230' 9100' 7000' SS . Exhibit VII-5 5-1 04 I SAFETY NOTES: = =---1 I 1008' H 9-S/8"TAMFORTCOLLAR I 2403' H 4-1/2" HES X NIP, 10 = 3813" 1 '9-S/8" CSG, 40#, L-80, 10 = 8.83S" H 3736' r--- ¡Minimum ID = 3.725" @ 8724' ---.!: 4-112" HES XN NIPPLE 17" MARKER Jf (20') WI RA TAG H 6499' ~.- 14-1/2" TBG JT#40W/RA TAG H 6681' I GAS LIFT MANCRELS ~ I ~TI4~91 ~~ I~I KB~~T/LI~·VjLA:~I~:TI0~~~~11 4 6731 4883 31 KBG-2- T/L S/~l BK 20 03/12/01 FROŒJCTlON MANrnELS ST M) TVO ŒV TYÆ VLV LATa-I PORT DATE 3 6920 S046 29 KBG-2- T/L [My' BK 0 02/07/01 2 7117 S218 30 KBG-2- T/L [My' BK 0 02/07/01 1 7266 S347 30 KBG-2- TlL [My' BK 0 02/07/01 PERFORA TION SUIvMARY REF LOG: SWS A..ATFORM EXFRESS GRlRES01/27/01 ANGLEA TTOPÆRF 29 @6920' Note: Reterto Production DB tor historical perf data SIZE SFF INTERVAL Opn/Sqz DATE 4-S/8" 6 6920 - 6980 0 02/04/01 4-S/8" 6 7018 - 70S0 0 02/04/01 4-S/8" 6 7070 - 7094 0 02/04/01 4-518" 6 7114-7124 0 02/04/01 4-S/8" 6 7162 - 7182 0 02/04/01 4-S/8" 6 7216 - 7266 0 02/04/01 4-S/8" 6 7280 - 7302 0 02/04/01 4- 518" 6 732S - 7346 0 02/04/01 3-318" 6 8810 - 8840 0 03126/01 14-1/2"TBG, 126#, L-80, 01S2bpf ,10=3.9S8" H 8736' 1 PBTD H 9100' 7" CSG, 26#, L-80, M-BTC, 10 = 6.276" H 9186' DATE REV BY COIvMB\lTS 02/09/01 ORIGINAL COM'LEfION 02/10/01 Cismoski CORRECTIONS 06/11/01 GROtlh PERFCORREC1l0N 09/03/0 1 KSB/tlh NIFPLE 10 CORRECTION 04/09/02 RNlCHlTP CORRECTIONS -~ g ~ g ..!....!... l-J, ..!....!... 1 i g-i I 6842' l-i 4-1/2"HESXNP,10=3813" I 6853' H 7"X4-1/2"BKRSABL-3PKR.10=387S" I 7035' H 4-1/2" BKR CM.! SLlDNG SLV, OTIS FROF, 10 = 3.812"1 7061' H 7" X4-1I2" BKR SABL-3 PKR. 10 = 3.87S" I 7175' H 4-1/2" BKR CJv1U SLIDING SLY, OTIS FROF, 10= 3812" I 7201' H 7" X4-1I2" BKR SABL-3 PKR. 10= 387S" I 7333' H 4-1/2" BKRCMU SLIDING SLV, OTIS FROF,IO= 3812" g ..!....!... :8: J z-I 8679' l-i 7" X4-1/2" BKR SABL-3 PKR,IO = 3.87S" ----1 8703' H 4-1/2" HES X NP,IO = 3.813" I -----1 8724' H 4-1/2" HES XNNIP, 10 = 3.725" '------1 8736' H 4-1/2"WLEG, 10= 4.00" 1 ~ I H ELMOTT NOTLOGGED I ~ ~ DATE REV BY COMMENTS FRUDl-iOE BA Y UNIT I AURORA RELO WELL 3-104 PERMT No: 200-1960 AR No: SO-029-22988-00 SEC 35, T12N, R12E. 4646' NSL & 4494' WEL BP 8cploration (Alaska) . . Exhibit VII-6 Well K221112 Observation Well Arctic Pack to surface in 7"x13- 3/8" annulus 30", 156 ppf 71' Downsqueeze of 13-3/8" x 20" 240' annulus 20", 94 ppf 735' Unknown TOe. Calculated to ? surface, but lost returns 1991' X Profile 2257' Halliburton Fa Collar 13-3/8", 72 ppf 2,723' 1496'? 260 sx Permafrost cmt (used 0.97 yield) 2925' Halliburton Fa Collar 2869'? 218 sx Permafrost cmt (used 0.97 yield, 30% excess) 4051' Halliburton Fa Collar 4198' 227 sx class G cmt (Calc TOe w/30% excess) 5749' Halliburton Fa Collar Top Kuparuk 6236' ? 6633' Calculated TOe w/30% excess taken into account. Packer 9579' Z 4-1/2" 12.75 ppf 9657' 9621' XN 9832' Top Perforations 9935' Base Perforations 7", 29 ppf 10,172' . . Exhibit VII-7 Standards of Mechanicallnteqritv The following Application assumes that the standards in the Commission's regulations apply to the operations described in the Application. In particular, a Polaris Pool injection well is considered to have mechanical integrity if it satisfies the requirements provided in 20 AAC 25.412, and a Polaris Pool production well is considered to have mechanical integrity if it is cased and cemented in accordance with 20 AAC 25.030 and complies with the requirements of 20 AAC 25.200. Standards of Confinement A penetration not completed within the Polaris Pool is considered to provide confinement of injection fluids within the Polaris Pool if calculations show the top of cement is above the top of the Ma sand and the cement job appears to have been pumped successfully, or if cement evaluation logs are available that show cement above the lower Ugnu and below the Schrader Bluff Formations, or if the penetration is far enough from the injector that it is reasonable to assume the reservoir pressure at that point will not rise above original reservoir pressure. Participating Area(s) Covered [!]Polaris PA [!]Aurora PA Nearest Polaris Injection Well: Distance from Polaris Injector: Hole angle at Ma: Top Ma Sand: MD at Top Ma Sand: Intermediate Casina Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess· Calculated TOC, gauge hole· . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? Well: Status: 15-03 GL-O Schrader: Kuparuk: X 617495 615468 617349 2200 psi Pri 3400 psi Pri Y 5981327 5983163 5981856 S-20Oi 549 Feet 55.06 Degrees 4644 TVDSS 5580 MDBKB Schrader Kuparuk S-200i: S-104i 617425 5985037 NO nla 7302 feet 12.25 inches 9.625 inches 154 BBL 5264 MDBKB 4653 MDBKB 47ppf, L-80 8.681inches ID 862.5 CF 1.15 750 sacks (Yield) 2,649 linear feet cement Yes ? ? Yes (revised) Tag Cement 7178 feet CMT type Class G Wt Slurry ppg 3000 psi 3000/PS~ pSI 15minutes minutes no no see note no no no Comments This well had an extra string of pipe run after 9-5/8" wouldn't go down. Has 7" across Kuparuk. at Datum depth of: at Datum depth of: Nearest Aurora Injection Well: Distance from Aurora Injector: Hole angle at Kuparuk: 6700' TVDSS Datum: Suñace Casina Data Bond Log? TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess· Calculated TOC, gauge hole· . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? nla nla nla Comments IAlOA Pressures . lOA rises above 600 psi, but bleeds quickly. pSI min psi psi nla ft Conclusions: OA has been down squeezed ft and IA is on gas lift, so normal monitoring program might not work. Based on TOC calculations, cement should be above the Schrader Bluff. Recommend sidetracking S- 200i further away from this well prior to injection in Schrader Bluff nearby. Yes No No 2000 1500 . .TBG 1000 .IA .OA Exhibit VII-S, 1 of 2 5000 TVDSS Completed:1982 6700 TVDSS S-104i 2,710 Feet 8 Degrees 8797 MDBKB INo 2694 feet 17.5 inches 13.375 inches 663 BBL -1352 MDBKB -2566 MDBKB Yes ? Yes 2000 psi 3000PSi 875 psi . 47ppf, L-80 12.375/inches ID 3720.25 CF 1.15 I 3235 sacks (Yield) 5,260 linear feet cement Tag Cement 2638 feet CMT type Arcticset II Wt Slurry 15.2 ppg 15/minutes 30 minutes no no no see note see note no 13-3/8" x 9-518" was downsqueezed with 280 CF Arcticset I followed by 120 bbls Arctic Pack. . 18 QA WHT Comments Date TBG 5-03 Pressures .. · 11II Á .. 500 . t ** · ~ .. 0 · 12/7/92 12/7/93 12/7/94 12/7/95 12/6/96 12/6/97 12/6/98 12/6/99 12/5/00 12/5101 Exhibit VII-8, 2 of 2 Participating Area(s) Covered Well: IS-03 [!]Polaris PA Status: GL-O [!:IAurora PA S-03 was drilled in 1982. The 9-5/8" casing did not go to bottom and once it was cemented in place, a 7" liner was run to Intermediate hole TD. The OA was down squeezed with 280 CF cement in order to ensure the Arctic Pac held. The well is currently flowing on gas lift. Intermediate Liner Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess' Calculated TOC, gauge hole' . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT In/a I This well had an extra string of pipe run after 9-5/8" wouldn't go down. Has 7" across Kuparuk. . 11840 feet Top of liner I 67891 feet 9.625 inches 7 inches 26 ppf, L-80 410 BBL 2300 CF 4462 MDBKB*** sacks 2249 MDBKB'" 9,591 linear feet cement "Calculates to above top of liner, so number invalid '" These depths don't include 200 sx liner lap squeeze. No (revised) Tag Cement 6708 feet ' See Notes ? CMT type Class G ? Wt Slurry ppg Yes 3000 psi 30001ps~ pSI 151minutes minutes , See Notes Other Issues Sidetracked above Injection Zone? no P&A Well? no Multiple Stages? see note Downsqueeze / Top Job? no Rig Squeeze? see note RWO to repair csg (cut & pull)? no Comments This well had an extra string of pipe run after 9-5/8" wouldn't go down. Has 7" across Kuparuk. 'Initially did not tag cement and liner lap broke down, so squeezed liner lap with 200 sks Class G. After that, pressure tested to 3000 psi and tagged cement as noted. . Distance from this well to planned injectors Planned / Actual Injectors ~ y TVDSS MDBKB Incline Distance Kuparuk S-101i HAW 614,153 5,979,739 -6619 8,516 65 3,668 feet S-104i 617,425 5,985,037 -6700 8,797 8 2,710 feet S-107i (HAW) 612,115 5,986,558 -6564 11 ,707 59 4,772 feet S-112i (HAW) 619,614 5,980,537 -6559 6,766 48 4,908 feet S-114i 607,096 5,986,083 -6700 15,503 26 8,866 feet Schrader Top Ma S-104i(S) 618235 5984886 -4743 6,941 29 3,635 feet Existing S-200 617349 5981856 -4629 5,889 20 549 feet S-215i 617648 5977425 -4655 6,256 46 3,905 feet W-207i 619324 5957278 -4638 24,118 feet W-212i 614095 5959817 -4520 5,852 30 21,777 feet Participating Area(s) Covered Œ]Polaris PA 0Aurora PA Nearest Polaris Injection Well: Distance from Polaris Injector: Hole angle at Schrader: Top Ma Sand: MD at Top Ma Sand: Intermediate Casino Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess' Calculated TOC, gauge hole' "Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? Yes P&A Well? No Multiple Stages? Downsqueeze /Top Job? No Rig Squeeze? No RWO to repair csg (cut & pull)? No Annulus Information Last MITfA, Date Pressure Time Tbg pressure OA pressure Recommendations/Restrictions Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor INOA Pressures? Well intervention required? Okay for water injection? Well: Status: S-24A INJ-MI Schrader: Kuparuk: X 618260 617111 617349 2200 psi Pri 3400 psi Pri y 5980947 5982221 5981856 S-20Oi 1,287 Feet 39.86 Degrees 4689 TVDSS 5257 MDBKB Schrader Kuparuk S-200i: S-104i: 617420 5985036 (New S-24A wellbore) INO I 10180 feet 9.875 inches 7 inches 250 BBL 6099 MDBKB 4875 MDBKB 1403 CF 11.15 sacks (Yield) 5,305 linear feet cement Yes ? 'ves Yes 3000 psi 4000PS~ pSI Tag Cement CMT type Wt Slurry I 10100 feet ppg 30minutes minutes Comments S-24 was sidetracked above Schrader. 9- 5/8" csg was cut and pulled to 13-3/8" shoe and cemented off prior to kick-off. -3/15/2002 3000 psi min 1325 psi 1050 psi Comments 3/15/02, MITOA failed, OA shoe not competent (seals passed). LLR = 4 bpm @775 psi. Plan is to MITIA and re-MITOA. nla nla No See Note No Yes Conclusions: S-24A is an Ivishak WAG injector, and therefore is monitored on a ft regular basis. No additional monitoring ft program is recommended. Gauge hole calcs show that cmt would be above the Schrader Bluff, but 30% excess cales do not. The well is considerable distance from the planned injector so no problems are expected. at Datum depth of: at Datum depth of: 5000 TVDSS 6700 TVDSS Nearest Aurora Injection Well: S-104i Distance from Aurora Injector: 2,832 Feet Hole angle at Kuparuk: 34.31 Degrees 6700' TVDSS Datum: .Suñace Casino Data Bond Log? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess' Calculated TOC, gauge hole' "Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IAlOA Pressures 4000 3500 .TBG 3000-.IA 2500 - ~OA 2000 1500 1000 500 o 12/6/98 . 12/6/99 7902 MDBKB Exhibit VII-9, 1 of 2 comPleted:1999 1990 (original S-24 completion in 1990) INo I 2694 feet 17.5 inches 13.375 inches 588 BBL -959 MDBKB -2055 MDBKB Yes Yes Yes Yes 2000 psi \yes 3000PS~ pSI . 47ppf, L-80 3299 CF sacks (Yield) 4,749 linear feet cement Tag Cement I feet I CMT type Arcticset 1/ & III Wt Slurry 12.1 to 15.2ppg I minutes minutes See Note See Note No No No No Comments S-24 was sidetracked above Schrader. 9· 5/8" csg was cut and pulled to 13-3/8" shoe and cemented off prior to kick-off. Date TBG $-24A Pressures . . . .f 12/5/00 . IA OA WHT . . .- ... . - . . . I . ~. ~ ÂÂ . 12/5/01 12/5/02 Exhibit VII-9, 2 of 2 Participating Area(s) Covered Well: S-24A æpolaris PA Status: INJ-MI x Aurora PA S-24 was drilled in 1990 as a producer and sidetracked above the Schrader Bluff interval in 1999 as a WAG injector. The original hole was completely abandoned below the surface casing shoe. Intermediate CasinCl Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size esg Size Volume Pumped Calculated TOC, 30% excess' Calculated TOC, gauge hole' . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? Yes P&A Well? Yes Multiple Stages? No Downsqueeze / Top Job? No Rig Squeeze? No RWO to repair csg (cut & pull)? No This is for the original 9-5/8" casing in S-24. It was abandoned in 1999. 9843 feet 12.25 inches 9.625 inches 363 BBL 4832 MDBKB 3329 MDBKB Ifeet . Top of liner 26 ppf, L-80 2040 CF 11.15 sacks (Yield) 6,514 linear feet cement Yes Tag Cement eMT type Wt Slurry I 9766 feet ppg Yes 3000 psi 3000PS! pSI Iminutes minutes Comments This is for the original 9-5/8" casing in S-24. An EZSV was set at 3020' and the 9-5/8" csg was cut and pulled above 2669'. . Distance from this well to planned injectors Planned / Actual Injectors ~ ï TVDSS MDBKB Incline Distance Kuparuk S-101i HAW 614,153 5,979,739 -6619 8,516 65 3,861 feet S-104i 617,425 5,985,037 -6700 8,797 8 2,834 feet S-107i (HAW) 612,115 5,986,558 -6564 11,707 59 6,616 feet S-112i (HAW) 619,614 5,980,537 -6559 6,766 48 3,017 feet S-114i 607,096 5,986,083 -6700 15,503 26 10,734 feet Schrader Top Ma S-104i(S) 618235 5984886 -4743 6,941 29 3,939 feet Existing S-200 617349 5981856 -4629 5,889 20 1,287 feet S-215i 617648 5977425 -4655 6,256 46 3,575 feet W -207i 619324 5957278 -4638 23,693 feet W-212i 614095 5959817 -4520 5,852 30 21,537 feet Participating Area(s) Covered ~Polaris PA [!]Aurora PA Nearest Polaris Injection Well: Distance from Polaris Injector: Hole angle at Schrader: Top Ma Sand: MD at Top Ma Sand: Intermediate Casina Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* * Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? No P&A Well? No Multiple Stages? No Downsqueeze I Top Job? No Rig Squeeze? No RWO to repair csg (cut & pull)? No Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? Well: Status: S-31A SI-W S-20Oi 1,285 Feet 42.75 Degrees 4674 TVDSS 5364 MDBKB NO No 10783 feet 12.25 inches 9.625 inches 417 BBL 5028 MDBKB 3302 MDBKB Yes ? No ? 3000\PS~ pSI 6/1/2002 3500 psi 30 min 2375 psi 380 psi nla nla No See Note No Yes Schrader Kuparuk S-20Oi Schrader: Kuparuk: X 618395 617038 617349 2200 psi Pri 3400 psi Pri Y 5981109 5982428 5981856 S-104i 617425 5985037 47ppf, NT-80 2343 CF sacks (Yield) 7,481 linear feet cement Tag Cement· 10609 feet CMT type Class G Lead Cmt 13.5 ppg ITail Cmt 15.8 ppg \minutes minutes Comments Comments Slow TxlA communication (below failing rate). Currently being monitored for low OA fluid level (120', 7 bbls on 6/24/02). Will be H20 only due to Sag not taking MI. Conclusions ft ft Should monitor IA and OA on a regular basis once S-200Ai is put on injection (-1100' away). Probably has cement above the Schrader Bluff, based on TOC cales. at Datum depth of: at Datum depth of: Nearest Aurora Injection Welf: Distance from Aurora Injector: Hole angle at Kuparuk: 6700' TVDSS Datum: Surface Casina Data Bond Log? TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IAlOA Pressures Exhibit VII-10, 1 of 2 5000 TVDSS Completed: 12002 6700 TVDSS (original) 1990 S-104i 2,638 Feet 40 Degrees 8138 MDBKB INo 2694 feet 17.5 inches 13.375 inches 663 BBL -1429 MDBKB -2666 MDBKB . 47ppf, L-80 3723 CF sacks (Yield) 5,360 linear feet cement Yes ? ? ? Tag Cement 2664? feet ICMT type Arcticset II Wt Slurry 15.2 ppg I 3000\PSi 15.2 EMW \minutes minutes Comments No No No No No No . Date TBG OA IA WHT 5-31 A Pressures 3000 . 2500 . 2000 . .TBG 1500 . .fA . I;.OA . 1000 I I;. ~ 500 . . . I;. I;. . . 0 12/7/95 12/6/96 12/6/97 12/6/98 12/6/99 12/5/00 12/5/01 12/5/02 Exhibit VII~1 0, 2 of 2 Participating Area(s) Covered Well: S-31A [!]Polaris PA Status: SI-W 0Aurora PA The original S-31 well was drilled in 1990 as a producer. In 2002, it was coiled tubing sidetracked below the 9-5/8' casing as a Sag River WAG injector. Although the well passed its original MITIA for MI, the Sag would not take MI. In future, well will inject water only. Also, there is a slow leak between tbg and IA - below fail rate. Intermediate Liner Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess' Calculated TOC, gauge hole' . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? nla No intermediate liner feet 9.625 inches 7 inches o BBL o MDBKB o MDBKB Top of liner I Ifeet 26 ppf, L-80 CF sacks (Yield) o linear feet cement . (revised) Tag Cement feet CMT type Wt Slurry ppg I IPs! pSI /minutes minutes Comments . Distance from this well to planned injectors Planned / Actual Injectors ~ .Y. TVDSS MDBKB Incline Distance Kuparuk S-101i HAW 614,153 5,979,739 -6619 8,516 65 3,944 feet S-104i 617,425 5,985,037 -6700 8,797 8 2,638 feet S-107i (HAW) 612,115 5,986,558 -6564 11,707 59 6,426 feet S-112i (HAW) 619,614 5,980,537 -6559 6,766 48 3,196 feet S-114i 607,096 5,986,083 -6700 15,503 26 10,592 feet Schrader Top Ma S-104i(S) 618235 5984886 -4743 6,941 29 3,780 feet Existing S-200 617349 5981856 -4629 5,889 20 1,285 feet S-215i 617648 5977425 -4655 6,256 46 3,759 feet W-207i 619324 5957278 -4638 23,849 feet W-212i 614095 5959817 -4520 5,852 30 21,722 feet Participating Area(s) Covered [!]Polaris PA DAurora PA Nearest Polaris Injection Well: Distance from Polaris Injector: Hole angle at Schrader: Top Ma Sand: MD at Top Ma Sand: Intermediate Casina Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* "Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? Yes P&A Well? Yes Multiple Stages? Yes Downsqueeze I Top Job? No Rig Squeeze? No RWO to repair csg (cut & pull)? No Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor INOA Pressures? Well intervention required? Okay for water injection? Well: Status: S-200PB1 P&A S-200 SI-P schrader: Kuparuk: X 617566 2200 psi Pri 3400 psi Pri Y 5981681 at Datum depth of: at Datum depth of: S-200i 279 Feet 0.76 Degrees 4652 TVDSS 5394 MDBKB Schrader Kuparuk S-200i 617349 5981856 Inla nla 4476 feet 8.5 inches 7 inches 48 BBL 2945 MDBKB 2486 MDBKB 6.276inches ID CF 1.15 sacks (Yield) 1,990 linear feet cement 26 ppf, L-80 Yes Yes 3500 psi Tag Cement CMT type Wt Slurry I 4412? feet Class G 15.8 ppg 35001 psi I 12.5 ppg EMW 30/minutes minutes Comments Drilled and cored original well to 6150' MD. Plugged back to 4471' with two stages of cmt (each 83 bbls 17ppg Class G) and dressed off to 4488' (Wt test 15k). Ran and cemented 7" csg. Then drilled final hole to TD. Comments 1/26/2002 3500 psi min psi psi nla nla No nla No Yes ft Conclusions: Original open hole plugback ft appears acceptable for injection nearby. Surface casing looks okay and intermediate cement job seems adequate for injection near this well. Recommend good plug back of S- 200 liner prior to sidetrack to new injector location, to confine fluids. Nearest Aurora Injection Well: Distance from Aurora Injector: Hole angle at Kuparuk: 6700' TVDSS Datum: Surface Casina Data Bond Log? TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* "Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IAlOA Pressures Exhibit VII-11, 1 of 2 5000 TVDSS 6700 TVDSS Completed: 11998 nla o Feet Degrees MDBKB INo 3158 feet 12.25 inches 9.625 inches 584 BBL -4815 MDBKB -7207 MDBKB . 8.681linches ID CF 1.15 I sacks (Yield) 10,365 linear feet cement 47 ppf, L-80 Yes Yes Yes Tag Cement 3040 1 feet ICMT type Cold Set 11I1 Class G Lead Cmt 12.2PP9 1500 psi !Tail Cmt 15.8 ppg 35001ps~ pSI Comments 3°lminutes minutes Yes Yes Yes No No No 2 stage cement job thru HES ES Cementer (-2172'). 1st stage 100 bbls cmt, circulated . out above the ES and saw 61 bbls cmt return. 2nd stage put red dye in and saw at surface. Date TBG IA OA WHT $-200 Pressures 2000 " 1500 . .TBG 1000 .IA . AOA I . 500 . . t 0 . A ,A A 12/6/99 3/15/00 6/23/00 10/1/00 1/9/01 4/19/01 7/28/01 11/5/01 2/13/02 Exhibit VII-11, 2 of 2 LS-200PB1 rp&A Participating Area(s) Covered [!]Polaris PA DAurora PA This well was originally named SB-01. It was drilled as an S-Pad data gathering and pilot produciton well. The well was cored in the S-200PB1 leg, open hole plugged back with cement and then sidetracked to the current S-200 bottom hole location which now has a collapsed liner which was milled through during remedial attempts. S-200 is being considered for sidetrack as an injector. Liner Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess', .. Calculated TOC, gauge hole', ** . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? No Multiple Stages? No Downsqueeze 1 Top Job? nla Rig Squeeze? No RWO to repair csg (cut & pull)? No Well: Status: [Yes rn/a S-200 SI-P 11/21/19981 13-112" production liner is across the Schrader Bluff formation. . 6310 feet Top of liner 43271feet 6 inches 3.5 inches 9.3 ppf, L-80 69 BBL CF 4032 MDBKB sacks 3349 MDBKB 2,961 linear feet cement "Calculates to above top of liner, so number invalid Ves Yes Yes Tag Cement CMT type Wt Slurry 4000 psi I feet ppg IPs! pSI Iminutes minutes Comments Possible collapsed liner at 5746' MD. While trying to mill through restriction, went out the liner with mill assembly. Considering sidetrack to injector location. . Distance from this well to planned injectors Planned 1 Actual Injectors ~ ï TVDSS MDBKB Incline Distance Kuparuk S-101i HAW 614,153 5,979,739 -6619 8,516 65 6,011,195 feet S-104i 617,425 5,985,037 -6700 8,797 8 6,016,800 feet S-107i (HAW) 612,115 5,986,558 -6564 11 ,707 59 6,017,771 feet S-112i (HAW) 619,614 5,980,537 -6559 6,766 48 6,012,549 feet S-114i 607,096 5,986,083 -6700 15,503 26 6,016,789 feet Schrader Top Ma S-104i(S) 618235 5984886 -4743 6,941 29 3,274 feet Existing S-200 617349 5981856 -4629 5,889 20 279 feet S-215i 617648 5977425 -4655 6,256 46 4,257 feet W-207i 619324 5957278 -4638 24,466 feet W-212i 614095 5959817 -4520 5,852 30 22,138 feet Participating Area(s) Covered [!]Polaris PA DAurora PA Nearest Polaris Injection Well: Distance from Polaris Injector: Hole angle at Schrader: . TopMa Sand: MD at Top Ma Sand: Intermediate Casino Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess' Calculated TOC, gauge hole' 'Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus I",formation Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IAlOA Pressures? Well intervention required? Okay for water injection? Well: Status: INO Yes Yes No See Note No Yes No 5/4/1980 1500 psi min psi psi nla nla No See Note No Yes /K221112 I Observation W-207i proposed 771 Feet 39.1 Degrees 4580 TVDSS 4813 MDBKB Schrader Kuparuk W-207i Schrader: Kuparuk: X 618629 2200 psi Pri 3400 psi Pri y 5956944 at Datum depth of: at Datum depth of: 619324 5957278 ICBL from TD to 8700' 10172 feet 8.5 inches 7 inches 107 BBL 6633 MDBKB 5572 MDBKB Ips~ pSI 29 ppf S-95 6.182inches ID 600 CF 1.2 500 sacks (Yield) 4,600 linear feet cement Tag Cement feet CMT type Class G Wt Slurry 16-17 ppg 1 Iminutes minutes Comments: Left fish in hole and ST around it (cemented back from 4831-5575'). Original cement job did not cover Schrader, but when well was suspended, cemented behind 7" csg through FO collars at 5749' (227 sx class G), 4051' (218 sx Permafrost), and 2925' (260 sx Permafrost). Comments: Tested without tubing, before running 4-1/2" to complete as an observation well. Conclusions ft ft Well appears to have cement isolation around Schrader. Visually inspect location and record pressures prior to injection start-up. Check again 6 months after start-up and yearly afterwards until well is suspended or abandoned. Nearest Aurora Injection Well: nla Distance from Aurora Injector: Hole angle at Kuparuk: 6700' TVDSS Datum: Surface Casino Data Bond Log? TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess' Calculated TOC, gauge hole' . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IAJOA Pressures n/'3J"t.n ....,,..+ h^r^ 5000 TVDSS 6700 TVDSS o Feet 24.47 Degrees 7264 MDBKB INo 2723 feet 17.5 inches 13.375 inches 1069 BBL -3847 MDBKB -5818 MDBKB See Note 3000PS~ pSI ¡ Exhibit VII-12, 1 of 2 Completed: f1976/80 P&A: . 12.375inches ID 6000 CF L1.2 I 5000 sacks (Yield) 8,541 linear feet cement Tag Cement feet ICMT type Arcticset II Wt Slurry ppg I minutes minutes No No Yes No No Comments Lost returns when 4800 sx in, observed S1i9,t traces of cement with return. Ran 2-3/8" tbg in 13-3/8"><20" annulus to 240' and cement to surface with 150 sx Permafrost cement. Return good cmt to surface. TBG IA OA WHT Date No Pressures Available for K221112 2000 1500 1000 +TBG .fA ÁOA 500 o 1/0/00 1/0/00 1/0/00 1/0/00 1/0/00 1/1/00 1/1/00 Well: Status: IK221112 I Observation Participating Area(s) Covered GJPolaris PA DAurora PA This exploration well was drilled and suspended in 1976. Suspension placed cement above and below Schrader Bluff (see diagram). Well was recompleted as an Observation Well in 1980, when cement plugs were drilled out, perforations were squeezed in order to get a good test on the 7" casing, the well was reperforated and 4-1/2" tubing was run. Initial Surface CasinCl Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess*, ** Calculated TOC, gauge hole*, ** . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? INO No I In this well, an extra string of surface casing was run initially, to only 735 feet. Have summary data only. 735 feet Top of liner I feet 26 inches 20 inches 691 BBL -1166 MDBKB -1736 MDBKB Exhibit VII-12, 2 of 2 1976 Suspension: The well was suspended with cement plug at 9936' (27 sx cmt, tagged at 9810'). Set another plug at 8575' (18 sx cmt, tagged at 8460'). Cemented behind 7" casing through FO collar at 5749' w/227 sx class G (16.2 ppg) and closed and tested to 1000 psi. Cemented behind 7" csg through FO collar at 4051' wI 218 sx Permafrost. Tested closed FO collar to 1000 psi. Set EZ drill bridge plug on wireline at 3420' with 40 sx Permafrost, tagged at 3312', Cemented behind 7" casing through FO collar at 2925' wI 260 sx Permafrost. Tested closed FO collar to 800 psi. Set BP at 2429', cmt w/40 sx Permafrost and tagged at 2406'. Displaced 7" x 13-3/8" annulus wI 260 bbls Arctic Pac through FO collar at 2257'. Displaced 7" from 2203' to surface w/120 bbls Arctic Pack. 1980 Recompletion: In 1980, drilled thru cement plugs, squeezed and reperforated. Ran 4-1/2" tubing to 9657', with packer at 9579'. Recompleted as Observation Well. . . ? ? ? ? Tag Cement Ifeet CMT type Permafrost Wt Slurry Ippg I Distance from this well to planned injectors Planned I Actual Injectors ! y. TVDSS MDBKB Incline Distance Kuparuk S-101i HAW 614,153 5,979,739 -6619 8,516 65 6,011,195 feet S-104i 617,425 5,985,037 -6700 8,797 8 6,016,800 feet S-107i (HAW) 612,115 5,986,558 ·6564 11,707 59 6,017,771 feet S-112i (HAW) 619,614 5,980,537 -6559 6,766 48 6,012,549 feet S-114i 607,096 5,986,083 -6700 15,503 26 6,016,789 feet Schrader Top Ma S-104i(S) 618235 5984886 -4743 6,941 29 27,945 feet Existing S-200 617349 5981856 -4629 5,889 20 24,945 feet S-215i 617648 5977425 -4655 6,256 46 20,504 feet W-207i 619324 5957278 -4638 771 feet W-212i 614095 5959817 -4520 5,852 30 5,368 feet IPs! pSI minutes minutes Comments Participating Area(s) Covered ~Polaris PA DAurora PA Nearest Polaris Injection Well: Distance from Polaris Injector: Hole angle at Schrader: Top Ma Sand: MD at Top Ma Sand: Intermediate Casina Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* "Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze /Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? Well: Status: IK241112 I P&A Schrader: Kuparuk: X 619,852 623,614 619324 2200 psi Pri 3400 psi Pri Y 5,957,413 5,958,138 5957278 W-207i proposed 545 Feet 51.89 Degrees 4639 TVDSS 4988 MDBKB Schrader Kuparuk W-207i NO No 11713 feet 12.5 inches 9.625 inches 107 BBL 10457 MDBKB 10080 MDBKB 43.5 ppf, RS- 8.755inches tD 600 CF 1.2 500 sacks (Yield) 1,633 linear feet cement No see note see note see note Tag Cement feet CMT type Class G Wt Slurry 16 ppg I IPs! pSI minutes minutes Comments: The initial job was meant only to No seal off Sag and Ivishak. Could not break Yes circulation with 4000 psi. Drilled out float collar, No still couldn't circulated. Drilled out shoe at No 11,695 and established circulation. Ran retainer Yes to 11,600 and cemented 9-5/8" casing with 500 No sx Class G w/18% salt. Casing later P&A'd adequately (see other notes). 6/??/76 1000 psi 15 min ps! comments: This well was P&A'd in 1976. pSI Conclusions nla nla nla nla nla Yes ft ft This well was P&A'd in 1976, with cement placed behind pipe between the Sag River and Kuparuk, the Kuparuk and Schrader Bluff, and above the Schrader. No monitoring possible. 9-5/8" casing appears to have good cement post P&A. at Datum depth of: at Datum depth of: 5000 TVDSS 6700 TVDSS Nearest Aurora Injection Well: nla Distance from Aurora Injector: 5,990,685 Feet Hole angle at Kuparuk: 64.26 Degrees 6700' TVDSS Datum: Surface C~sina Data Bond Log? TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess" Calculated TOC, gauge hole* "Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze I Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IAJOA Pressures ,.,,1.0,..0. nl,...* hnY'n 2000 1500 1000 .TBG .fA J/¡.OA 500 o 1/0/00 1/0/00 Ips~ pSI Comments This cement job was probably pumped above frac gradient 9402 MDBKB INo 2496 feet 17.5 inches inches 315 BBL -215 MDBKB -1028 MDBKB No Yes Date No Pressures Available for K241112 1/0/00 1/0/00 Exhibit VII-13, 1 of 2 Completed: 11970 P&A: 1976 ThiS was a tapered string with . 1742'13-3/8" and 747' 16" casing. linches ID 1768.5 CF 11.31 I 1350 sacks (Yield) linear feet cement Tag Cement feet ICMT type Arcticset II Wt Slurry ppg I Iminutes minutes . TBG IA OA WHT 1/0/00 1/1/00 1/1/00 Exhibit VII-13, 2 of 2 Participating Area(s) Covered Well: IK241112 I Œ]Polaris PA Status: P&A DAurora PA This exploration well was drilled in 1976 and P&A'd in 1976. Actual daily drilling reports no longer available, just summaries. During the P&A of this well, BP set at 11,412, Retainer at 9414 and 9243'. 37 sacks of cement were squeezed at 9600' MD (below Kuparuk) and 50 sx were squeezed at 9300' MD (above Kuparuk). Set retainer at 2700', shot at 2750 & circulated out 9- 5/8" x 16", 16" x 20". Retainers set at 2400' and 2058' with cemented perfs at 2503' and 2100'. Initial Surface CasinQ Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess', " Calculated TOC, gauge hole', .. . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Yes Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? NO No Iln this well, an extra string of surface casing was run initially, to only 750 feet. 750 feet Top of liner I Ifeet 24 inches 20 inches 140 BBL 248 MDBKB 97 MDBKB . Tag Cement feet CMT type Wt Slurry ppg I IPs! pSI Iminutes minutes Comments Could not break circulation with 700 psi, 20" csg pumped out of hole. Conditioned hole and re-ran 20" csg. Cemented as planned after that. . Distance from this well to planned injectors Planned I Actual Injectors X r TVDSS MDBKB Incline Distance Kuparuk S-101i HAW 614,153 5,979,739 -6619 8,516 65 23,582 feet S-104i 617,425 5,985,037 -6700 8,797 8 27,602 feet S-107i (HAW) 612,115 5,986,558 -6564 11 ,707 59 30,658 feet S-112i (HAW) 619,614 5,980,537 -6559 6,766 48 22,753 feet S-114i 607,096 5,986,083 -6700 15,503 26 32,461 feet Schrader Top Ma S-104i(S) 618235 5984886 -4743 6,941 29 27,521 feet Existing 5-200 617349 5981856 -4629 5,889 20 24,571 feet S-215i 617648 5977425 -4655 6,256 46 20,133 feet W-207i 619324 5957278 -4638 545 feet W-212i 614095 5959817 -4520 5,852 30 6,239 feet Participating Area{s) Covered ~Polaris PA DAurora PA Nearest Polaris Injection Well: Distance from Polaris Injector: Hole angle at Schrader: Top Ma Sand: MD at Top Ma Sand: Intermediate Casina Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* 'Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? Well: Status: W-17 SI-O W-212i 255 Feet 45.01 Degrees 4520 TVDSS 5375 MDBKB NO 11417 feet 12.25 inches 9.625 inches 439 BBL 5,443 MDBKB 3,651 MDBKB yes yes yes 3000 psi 30001ps~ pSI Schrader Kuparuk W-212i Schrader: Kuparuk: X 614326 616,539 614095 2200 psi Pri 3400 psi Pri Y 5959710 5,959,760 5959817 47ppf, L-80 8.681inches ID 2465 CF sacks (Yield) 7,766 linear feet cement Tag Cement feet CMT type Class G Wt Slurry ppg I I minutes minutes Comments: 1000 sx 13.5 ppg lead, 500 sx 15.8 ppg tail. RWO in 1990 cut and pulled -2100' of9· 5/8" csg. Found cmt as high as 411'. Either primary cmt went up that high, well was downsqueezed after original 9/88 drill but before 9/90 RWO (no record except a well bore diagram was revised on 7/31/91 to show downsqueeze but was later dropped), or CTU squeeze somehow got cmt down OA. ·2/11/1994 1500 psi min psi psi No No No Maybe? No Yes Comments: 1994 MITIA passed, showed OA fluid packed. OA pressured up to 1200 psi during test (bled 3 bbl diesel). Probably just due to thermal expansion while pumping down IA. ft Conclusions: Need a baseline temp log ft prior to injection, then again after injection reaches producer. If logs show poor Yes confinement, use best engineering practices Yes to come up with a solution. Monitor IA/OA No pressures after injection start-up. at Datum depth of: at Datum depth of: Nearest Aurora Injection Well: Distance from Aurora Injector: Hole angle at Kuparuk: 6700' TVDSS Datum: Surface Casina Data Bond Log? TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess' Calculated TOC, gauge hole* 'Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IA/OA Pressures 2000 · ~ , · 1500 ;:l- . . .., . 1000 iï · 500 * . . O.&. ..' t ~ 12/23/88 12/23/90 . 12/22/92 Exhibit VII-14, 1 of 2 Completed: 1988 RWO: 1990 5000 TVDSS 6700 TVDSS n/a 5,991,566 Feet 39 Degrees 8486.78 MDBKB No . 2854 feet 17.5 inches 13.375 inches 47ppf, L-80 12.375inches ID 735 BBL 4128 CF I -1,643 MDBKB 4438 sacks (Yield) -2,993 MDBKB 5,847 linear feet cement (If negative number, excess cmt to above surtace, so depth invalid) Yes Tag Cement 2815 feet ICMTtype Arcticset II Wt Slurry ppg Yes 2000 psi I 2000PSi 600 psi minutes minutes 13.9 EMW Comments No End of well noted could not pump down No 13-3/8" x 9-5/8" annulus - held 2000 psi. No Would not have been able to ? downsqueeze with rig then. But during No RWO, rig was able to pump 125 bbl 9-518" dead crude down OA. . Date TBG IA OA WHT .. i .TBG ~ .fA .OA . .. . t, 12/20/00 12/20/02 W-17 Pressures -. . . I '"-p....~ .... .. ··....1. · d~ ~.. · ,¡: t · :"H~' 12/22/94 12/21/96 . .. . 12/21/98 Participating Area(s) Covered [iPolaris PA DAurora PA Intermediate Liner Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* . Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Well: Status: W-17 SI-O Exhibit VII-14, 2 of 2 (n/a) ~ feet Top of liner I Ifeet inches inches 26 ppf, L-80 6.276inches I~ o BBL CF #DIV/O! MDBKB*** sacks (Yield) #DIV/O! MDBKB*** #DIV/O! linear feet cement "Calculates to above top 01 liner, so number invalid . (revised) Tag Cement feet CMT type Wt Slurry ppg I Ips~ pSI ¡minutes minutes Comments . Distance from this well to planned injectors Planned / Actual Injectors ~ y TVDSS MDBKB Incline Distance Kuparuk S-101i HAW 614,153 5,979,739 -6619 8,516 65 20,121 feet S-104i 617,425 5,985,037 -6700 8,797 8 25,293 feet S-107i (HAW) 612,115 5,986,558 -6564 11 ,707 59 27,161 feet S-112i (HAW) 619,614 5,980,537 -6559 6,766 48 21,003 feet S-114i 607,096 5,986,083 -6700 15,503 26 27,965 feet Schrader Top Ma S-104i(S) 618235 5984886 -4743 6,941 29 25,478 feet Existing 5-200 617349 5981856 -4629 5,889 20 22,351 feet S-215i 617648 5977425 -4655 6,256 46 18,024 feet W -207i 619324 5957278 -4638 5,558 feet W-212i 614095 5959817 -4520 5,852 30 255 feet Injector S-104i no penetrations within 1/4 mile .Iniector S-200Ai (distances based on existing S-200 location, no XY for planned S-200Aisidetrack chosen yet) S-03 Ivishak GL-O 549 4,644 5,580 5,264 N Yes Yes OA downsqueezed, so normal monitoring might not work. Based on . TOC calculations, cement should be above the Schrader Bluff. Sidetrack S-200Ai further away from this penetration. 6,099 Y Yes No Gauge hole cales show that cmt would be above the Schrader Bluff, but 30% excess cales do not. The well is considerable distance from the planned injector so no problems are expected. Monitor IAlOA after H20 start-up. 5,028 Y Yes No Monitor IA and OA after injection start-up. Probably has cement above the Schrader Bluff, based on TOC cales. 2,945 Q No Yes Will Sidetrack to injector location. Make sure good cement across Schrader when P&A for sidetrack. 2,945 Y No No Well had good P&A across Schrader. S-200 Schrader Bluff S-200PB1 Schrader Bluff For S-200Ai, would recommend choosing bottom hole location as far from existing penetrations as possible, without compromising reservoir performance. Polaris PA Area Injection Order Application () I: o N S-24A Ivishak S-31 A Sag River ¡Note: Injector S-215i no penetrations within 1/4 mile Exhibit VII-15 Penetrations within 1/4 mile of proposed injectors 0 I: "ä!~ 0 ('II ('. ('. :;:: () ~ 0 :E: I: I: (,) ca(/) calXl ca°U) ... .2 ... U) I: :iE~ -(')U) 0 () :::J ca :iE(/) :::J _ () o~ .'!: > ~IXI - (,) ... ~ ~ ~o ~o(,) ~.!!!. I: () ca U) 0> 00 caO>< 0 .š ('. Comments ~ is 0.5 :iE (/) 1-1- 1-:iE Ol-W INJ·MI 1,287 4,689 5,257 SI-W 1,285 4,674 5,364 SI-O o 4,629 5,889 P&A 279 4,652 5,394 Y Q N ~ = No action required prior to injection start-up. Okay for injection in area, with some qualifications or restrictions. Not okay for injection as is. Needs action prior to start-up. All pre-injection action requirements in bold, in Comments. = = Injector W-207i K221112 Ivishak Observation 771 4,580 4,813 See Note Q Yes No Suspension placed cement across Schrader behind 7". Need a visual check of this well prior to injection (record pressures). Check again 6 months from start of injection, then yearly until abandoned. K241112 Ivishak P&A 545 4,639 4,988 See Note Y No No Adequate cement placed across Schrader during P&A procedure, via riq squeezes. Injector W-212i W-17 Ivishak SI-O 255 4,520 5,375 5,443 N Yes ? Need a baseline temp log prior to injection, then again after injection reaches producer. If logs show poor confinement, use best engineering practices to come up with a solution. Monitor IAlOA after injection start- up. [Fwd: Polaris Application - Outstanding Items withiliea Injection Order] '. Subject: [Fwd: Polaris Application - Outstanding Items within Area Injection Order] Date: Tue, 01 Oct 200209:57:42 -0800 From: Jane Williamson <Jane _ Williamson@admin.state.ak.us> To: Jody J Colombie <jody_colombie@admin.state.ak.us> Jody, Please put this in the Polaris Pool Rules file (when you put it together). Don't notice yet till we get their revisions back. Thanks Jane =,,~,~~"'~~~ ' Subject: Polaris Application - Outstanding Items within Area Injection Order Date: Tue, 01 Oct 200209:34:59 -0800 From: Jane Williamson <Jane_ Williamson@admin.state.ak.us> To: "Schmohr, Donn R" <SchmohDR@BP.com> CC: "Beuhler, Gil G" <BeuhleGG@BP.com>, James B Regg <jim_regg@admin.state.ak.us>, Stephen F Davies <steve _ davies@admin.state.ak.us>, John D Hartz <jack_hartz@admin.state.ak.us> Don, We would like to thank you for meeting with us yesterday to discuss outstanding issues concerning the Polaris Pool Rules and Area Injection Order. While your application submitted on September 12,2002 was very well constructed, the Commission needs additional information within the Area Injection Order application before we can deem it complete. We recommend that BP make separate application for an MI-based Enhanced Oil Recovery project to prevent delay of the current Polaris project. Miscible injection ("MI") presents numerous technical and regulatory challenges that have not been fully addressed in this application. Assuming that MI is excluded from this application, the following are clarifications and items we need within the Area Injection Order application. As noted in Jack Hartz's e-mail to Gil Buehler (September 17, 2002), confidentiality of exhibits will also need to be sorted out prior to deeming the application complete. Area of Review The Area of Review ("AOR") for the Polaris waterflood project extends a radius of V4 mile from the base of the confining layer for each proposed injection well. Mechanical integrity must be demonstrated for each well within the AOR. Please provide a listing of every well within each AOR. Future injection wells not identified in the current application, will require submittal of a 10-401 (new well permit) or 10-403 (conversion to injection) form, establishment of an V4-mile AOR, and investigation of the mechanical integrity of each well within that AOR. Mechanical Inte!!ritv This issue is important at Polaris because of the presence of many older wells that may not have cement across the Schrader Bluff interval. You presented in spreadsheet that provides basic data on casing and cementing for wells within the AOR. This is an excellent starting point. For each well within the V4 mile AOR, please provide a copy of this spreadsheet, supplemented with following additional information: 1) A conclusion stating whether mechanical integrity has been established for the subject well. 2) The basis for that conclusion, which includes BP's definition of integrity. 3) If integrity cannot be demonstrated, a plan for repair or proposed surveillance must be provided. This plan must discuss limitations due to well construction and any integrity concerns that would trigger lof2 10/1/2002 II :29 AM [Fwd: Polaris Application - Outstanding Items within Area Injection Order] - 'e additional surveillance or repair. A copy of the most recent schematic diagram for the subject well is required. Directional survey information and daily operations reports need not be included within the application. Fracture Pressure It is our understanding that fracture conditions discussed in the application were the result of injecting highly viscous fluids at high rates (15 barrels per minute) for the purpose of stimulating the well. During our discussion, you stated that these conditions represented a worst-case scenario, which did not result in net pressures which would be sufficient to frac through the confining layer. Conditions for planned waterflood will be at lower rates (about 2 bpm) and result in lower net pressures, and are unlikely to cause fracturing through the confining layer. Should fracturing occur, fluids will remain within the Polaris Pool. In the unlikely event that the Mb2 mudstones above the planned injection interval is fractured, the water will preferentially enter the highly permeable Mb sands, which you are requesting as part of the Polaris pool. Please verify if we understood correctly. Jane Williamson - Reservoir Engineer Steve Davies - Petroleum Geologist Jim Regg - Petroleum Engineer Alaska Oil and Gas Conservation Commission 20f2 10/1/200211:29 AM #1 I I I I I I I I I I I I I I I I I I I BP Exploration (Alaska), Inc.. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 . ObP September 12, 2002 DELIVERED BY HAND Commissioners Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 :,r RE: Polaris Pool Rules And Area Injection Order Application Dear Commissioners: Enclosed is the submission of Pool Rules and Area Injection Order Application for the Polaris Oil Pool. We look forward to discussing this with you further. BP Exploration (Alaska) Inc., in its capacity as Polaris Operator and Unit Operator, respectfully requests that a hearing commence as early as possible in order to gain approval of an Area Injection Order. BP requests, as operator, that those certain exhibits labeled "CONFIDENTIAL" be treated as confidential in accordance with the provisions of AS 31.05.035 and 20 MC 25.537. Please contact me (564-5143) or Donn Schmohr (564-5494) if you have any questions or comments regarding this request. Sincerely, ~~ Gil Beuhler GPB Satellites Team leader Attachments CC: R. Smith (BP) J. P. Johnson (PAl) S. Wright (ChevronTexaco) M. M. Vela (ExxonMobil) P. White (Forest Oil) 11 I I I I I I' I I I I I I I I I I I I Polaris Pool Rules and Area Injectio"er Application . September 12, 2002 Polaris Pool Rules and Area Injection Order Application September 12, 2002 1/60 b;;~ Polaris Pool Rules and Area Injectiot__der Application ;~ September 12, 2002 Table of Contents -="'-......- I. Oeo logy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 3 - Introduction..................................................................................................................... 3 Stratigraphy ..................................................................................................................... 5 Schrader Bluff Formation Structure.............................................................................. 15 Fluid Contacts................ ........... ....................................... ...... .................... ........ ........... 18 Net Pay and Pool Limits.. ......................... ......... ....... ........ .... ...... ........ ........... ..... ........... 21 II. Reservoir Description and Development Planning .....23 Rock and Fluid Properties ............... ................... ............. ........ ............. ......... ..... ...........23 Hydrocarbons in Place ....................... ........ ............ ............. ........... ... ......... ........... ........25 Reservoir Performance.............. ......... ................... ...... ............ ........... ...... ............. ........ 26 Development Planning............... ...... ......................... ...... .......... .................... ................28 Development Options................................................ ............................... .... ....... ..........28 Development Plan...........:' .,..... ..................... ...... ............. ........... .............. ...... ............... 31 Reservoir Management Strategy....................... ......... .......................... ................ ......... 33 III. F acili ti es .................................................................... 35 General Overview.................................... ......... ............ ................................................ 35 Pad Facilities and Operations........................................................................................ 36 Gathering Center.......................................................................... .......................... ....... 37 IV . Well Operations......................................................... 38 Existing Wells............................................................................................................... 38 Drilling and Well Design...................................................... ............. ...... ...... ..... .......... 38 Reservoir Surveillance Program................................................. ...... ........ ..................... 42 V. Production Allocation................................................. 46 VI. Area Injection Operations .........................................47 Plat of Project Area..................................... ................. ...... ..... ........... ........... .......... ......47 Operators/Surface Owners ........................................... ........ .......................... ............... 47 Description of Operation.................................................................................... ........... 47 Geologic Information.......... ..................... ......................... ........... ....................... ..........47 Injection Well Casing Information................ ....................... .............. ..... ............ .......... 48 Injection Fluids................. ....................... ........................ .......... ............... ........... .......... 48 Mechanical Integrity of Wells...................................... ............................ ........... .......... 49 Injection Pressures............... ..................... ........................... ....... ......... ................... ....... 50 Fracture Information..................................................................................................... 50 VII. Proposed Polaris Pool Rules .................................... 52 VIII. Proposed Area Injection Order ............................... 56 IX. List of Exhibits ......................................................... 59 - ~... ~ 2/60 Polaris Pool Rules and Area Injt.vllOn Order Application September 12, 2002 I. Geology Introduction The area for which the Polaris Pool Rules are proposed is located within the Prudhoe Bay Unit (PBU) on Alaska's North Slope, as illustrated in Exhibit 1-1. The Polaris Pool overlies the PBU Sadlerochit Group reservoir in the vicinity of PBU S, M and W Pads and overlies the Aurora Pool Kuparuk River Formation reservoir in the vicinity of PBU S Pad. The reservoir interval for the Polaris Pool is the Schrader Bluff and lower U gnu Formations. Within the Polaris Pool, the Schrader Bluff and lower U gnu Formations are subdivided into fourteen distinct sand units encompassed by the 0 and N sand intervals (Schrader Bluff) and the M sand interval (lower Ugnu). Hereafter, this application will refer to the Polaris Pool as including all of the hydrocarbon bearing sands within the Schrader Bluff and Ugnu Formations M, N, and 0 sand intervals within the described area. The North Kuparuk State 26-12-12 well, drilled in 1969, was the first well to penetrate and log hydrocarbons in the Polaris Pool. Since 1969, the Polaris Pool interval has been logged in 64 Schrader Bluff penetrations in PBU Ivishak, Kuparuk, and Schrader Bluff development and appraisal wells in the Polaris Pool Rules area. Polaris Pool hydrocarbon presence is recognized from log data from 59 Polaris Pool wells which have at least Gamma Ray (GR) and Resistivity log data. Polaris Pool rock properties were derived using conventional core data from two Polaris wells, S-200PB 1 and W -200PB 1. Rock properties were distributed regionally across the Polaris Pool area using log model transforms on well log data from 27 regional wells which have full suite (GR, Resistivity, and Porosity) log data. Exhibit 1-2 shows the location of the Polaris Pool area. Exhibit 1-2 also shows that the boundaries of the Polaris Pool Rules area coincide with the boundaries of the Polaris Participating Area (PP A). The Polaris Pool hydrocarbon accumulation is bounded by faults on the updip west and south sides and by dip closure into the regional aquifer on the north and east sides. 3/60 - Polaris Pool Rules and Area Injectioì_der Application ''Y' September 12, 2002 ~ '"õ-" As shown on the Schrader Bluff structure map in Exhibit 1-3, the Polaris structure crests at W Pad in the southwest Polaris Pool region (-4800 feet TVDSS at the mid Schrader Bluff OA mapping horizon) and trends down dip to the north and east through faulting and regional dip. North-south, east-west, and northwest-southeast trending faults subdivide the Schrader Bluff reservoir into discrete high-standing and low-standing fault blocks within the Polaris Pool area. Fluid isolation between several fault blocks is indicated by log data from adjacent fault separated wells that show water lying structurally higher than oil in the same sands on opposites sides of faults. Sealing faults are predicted in the Schrader Bluff reservoir based on the prevalent low net to gross reservoir lithologies. Exhibit 1-4 shows the Polaris Pool fluid limits in relation to regional structural features along a cross section line connecting the Wand S Pad areas. '~ ~.~ Oil-Dawn-To (ODT) limits and Water-Up-To (WUT) limits in PBU M and N Pad wells constrain northern Polaris Pool Sand M Pad area oil column heights to between 200 and 320 vertical feet. Oil-Dawn-To limits and a structural spill point in the Polaris W Pad area constrain southern Polaris Pool oil column heights to between 210 and 360 vertical feet. A single OBd sand Oil-Water contact penetrated in well W-201 (-5226 feet TVDSS) represents the only 0 sand Oil-Water contact logged in a Polaris Pool well. Based on differences in rock quality and potential spill points for the various sand units, it is believed that Oil-Water contact depths vary by sand unit and by fault block within the Polaris Pool. - ~""'V" Polaris Pool commercial production was confirmed in 2000 following the fracture- stimulated completion and production of the Schrader Bluff 0 and N sands in well S-200 and the Schrader Bluff 0 sands in well W-200 in late 1999. Wells S-201, S-213, and S- 216 were drilled and completed as conventional fracture stimulated 0 sand production wells in December, 2000 and January, 2001. Well S-104 is an injection well drilled in 2001 which was completed to allow water injection in both the Polaris and Aurora Pools. Well W-201 was completed as the first Polaris high-angle development well at W Pad and began production from the 0 sand interval in July, 2001. Wells W-211 and W-212i, 4/60 - .......' Polaris Pool Rules and Area InjL ,on Order Application . September 12, 2002 an a sand conventional injector-producer well pair down dip of the W-200 production well, were drilled in March and April, 2002 and were completed in May, 2002. Well W- 203 was completed in June, 2002 as the first Polaris Pool high-angle trilateral well in the W Pad area aBa, OBc, and OBd sands. All current Polaris Pool production is from the Nand 0 sands at S Pad, and from the aB sands only at W Pad. There are currently no Polaris Pool producing wells on M Pad. The N sands at W Pad have not been targeted to date due to the presence of heavy oil (14 API gravity) based on core-derived fluid samples, as well as the presence of several thin wet intervals in close proximity to oil pay relatively high on structure. The M sands at both Sand W Pads contain heavy oil (12 to 14 API gravity) based on core-derived fluid samples and are not considered to be economic development targets due to production complications related to heavy oil and unconsolidated sands. The M sands may be a future development target at Polaris. Stratigraphy Exhibit 1-5 shows the open-hole wireline log character of the Schrader Bluff and lower Ugnu Formation M, N, and 0 sands in a type log from the S-200PBl well and illustrates the vertical stratigraphic extent of the Polaris Pool. In the S-200PB 1 well, the top of the Polaris Pool occurs at -4,651 feet TVDSS (5,393 feet MD) and the base occurs at -5,269 feet TVDSS (6,012 feet MD). As shown in Exhibit 1-5, the Polaris Pool M, N, and a sands are further subdivided into seven 0 sand, three N sand, and four M sand intervals. A general description of the thickness and character of each of the Polaris sands follows. A detailed description of the rock properties associated with individual sands is given in Section II. In general, the a, N, and M sand intervals are present across the entire Polaris Pool area and, as a package, thin slightly from south-southwest to north-northeast across the Polaris Pool area. Reservoir quality sand units within each interval are regionally extensive but can be locally characterized by substantial thickness and net to gross variations between wells spaced less than 1000 feet apart. 5/60 "..,.. Polaris Pool Rules and Area Injectio\-fder Application ""-'" September 12, 2002 ~ The Schrader Bluff Formation Nand 0 sand intervals were deposited between 65 and 72 million years ago during the Late Cretaceous geologic time period and are composed of a set of marine shoreface and shelf deposits that are transitional between the underlying open marine Late Cretaceous Colville mudstones, and the overlying deltaic and fluvial sands, silts, and mudstones of the Early Tertiary U gnu Formation M sands. The contact between the basal Schrader Bluff Formation 0 sands and the underlying upper Colville section is gradational from the Colville mudstones to the basal Schrader Bluff low permeability silty sands. Colville mudstones and muddy siltstones, ranging up to 1100 feet thick at Polaris, form the basal confining unit of the Polaris Pool. The contact between the upper Schrader Bluff Formation N sands and the overlying Ugnu M sand section is generally abrupt and lies at the base of a regionally continuous 10 to 30 foot thick muddy siltstone layer. The top of the Ugnu M sand interval is characterized by an upward gradation from silty fining upward Ma sands to a regionally continuous 10 to 25 foot thick silty mudstone which isolates the M sands from overlying fluvial U gnu sands, silts, and mudstones. This upper silty mudstone forms the upper confining layer of the Polaris Pool. ~~ 'i;:"-_ -4 '~ o Sands The lowermost Polaris Pool unit, the Schrader Bluff 0 sand interval, forms the primary development target in the Polaris Pool and is subdivided into seven separate reservoir horizons, from deepest to shallowest - the OBf, OBe, OBd, OBc, OBb, OBa, and OA. In general, each of the 0 sand intervals clean upward from basal non-reservoir laminated muddy siltstones to reservoir quality laminated to thin-bedded sand units at the top. Within the reservoir quality sand intervals, several 0 sand intervals show an abrupt transition from lower net to gross coarsening upward reservoir facies to high permeability blocky to fining upward facies above regionally extensive erosion or scour surfaces. The fining upward facies above the erosion surfaces comprise the highest quality reservoir section in the Polaris 0 sand interval. The upper limit of each 0 sand horizon is marked by an abrupt upward transition from reservoir quality sands to non-reservoir muddy siltstones at the base of the overlying 0 sand interval. Bioturbation disrupts layering throughout both the reservoir and non-reservoir sections, but is most prevalent in the lowest net to gross lithologies. 6/60 Polaris Pool Rules and Area InJ,~,lOn Order Application September 12,2002 OBe and OBf Sands The OBf and OBe intervals, each ranging in thickness from 30 to 50 feet, comprise the basal Polaris 0 reservoir units and exhibit the lowest net to gross sand facies in the 0 sand section. Both intervals are characterized by basal muddy siltstones that grade upward into thin very fine-grained and laminated sands. Abundant lithic feldspar grains are present in both the OBf and OBe intervals, which result in an abnormally high GR response in the highest net to gross sand layers. OBe and OBf sands also contain abundant pore-filling zeolites, which significantly reduce reservoir porosities and permeabilities. Zeolite-related porosity and permeability reduction is suspected as the main reason that the OBe and OBf sands do not appear to contribute significant production in hydraulically fractured and commingled completions in wells 5-200 (OBe) and W -200 (OBf). OBd Sands The OBd sand interval ranges between 50 and 70 feet thick and forms one of the primary Polaris reservoir target horizons in both the 5 Pad and W Pad areas. OBd sands are thickest in the W Pad area, ranging up to 47 feet net sand in well K 22-11-12, and thin gradually northward to between 10 and 30 feet net sand in the 5 and M Pad areas. The OBd interval grades upward from a basal muddy siltstone to a faintly laminated to cross- bedded upper sand unit. Lower quality laminated and bioturbated reservoir sands regionally overlie the basal mudstone and gradually clean upward to a regionally extensive erosion/scour surface. A 10 to 30 foot thick blocky to fining upward sand unit overlies the regional erosion surface and caps the OBd interval over most of the Polaris Pool area. This upper blocky to fining upward sand forms the highest quality OBd reservoir unit. Reservoir quality OBd sands are unconsolidated and almost entirely very fine to fine-grained. Production logs have shown that OBd sands contribute between 60 and 800/0 of the total well production in Polaris hydraulically fractured and commingled o sand completions at both Sand W Pads. OBc Sands The OBc sand interval, ranging between 40 and 50 feet thick, comprises a minor Polaris 7/60 "'-~ Polaris Pool Rules and Area Injectio,,_,jer Application ~y September 12, 2002 ~ reservoir unit with reservoir quality sands present mainly in the W Pad area. The OBc interval grades upward from basal muddy siltstones to a low net to gross silty sand around Sand M Pads, and a moderate net to gross laminated to layered very fine-grained sand around W Pad. The upper OBc interval at W Pad consists of two thin distinct sand lobes, each 5 to 10 feet thick, separated by a <5 to 10 foot thick low permeability sandy siltstone. Up to 20 net feet of OBc sand is mapped in the eastern W Pad area. S Pad area OBc net sand thicknesses are typically less than six feet. Polaris Pool OBc sands contribute minor production in a commingled hydraulically fractured completion in the W - 200 well, in a well W - 203 high angle trilateral completion, and have not been individually completed in recent S Pad wells due to limited net sand presence. OBb Sands .",..-" The OBb sand interval, also a minor Polaris Pool reservoir unit, has a thickness range of between 30 and 55 feet with between five and 20 feet of net sand present in both the S Pad and W Pad areas. Regionally, the OBb interval typically contains less than 15 net feet of sand. The OBb interval comprises a moderately coarsening upward section that exhibits a lower net to gross character than the overlying OBa and the underlying OBc intervals. Individual clean OBb sand layers in core samples are typically less than one foot thick and are separated by silts and muds of comparable or greater thickness than the sands. OBb sands in both the S-200 and W-200 wells were hydraulically fractured and produce commingled with the overlying OBa sands. -'"ic=' OBa Sands The OBa sand interval, with a 25 to 40 foot thickness range, cleans gradually upward from a basal siltstone into interbedded thin sands and mudstones to an upper cross- laminated sand unit. A IOta 15 foot thick, blocky to fining upward high permeability sand (1000 md. +) caps the OBa interval regionally from southern S Pad wells S-18 and S-216 southward across the W Pad area. This high permeability OBa sand interval thins from south to north across the Polaris region and comprises a primary development target in the middle and southern Polaris Pool area. OBa sand quality, in general, diminishes in the central and northern S Pad area. Hydraulically fractured OBa sands produced at initial rates of approximately 65 BOPD in well W-200 and 35 BOPD in well S-200. 8/60 -- ~y Polaris Po.ol Rules and Area InJl._tlOn Order Application September 12,2002 OBa sands have produced at rates of >1000 BOPD in the well W-203 high angle trilateral completion. OA Sands The OA sand interval is composed of a IOta 25 foot thick basal silty mudstone that coarsens upward, gradually to abruptly, into stacked set of cleaning and fining upward reservoir sand units. As a package, the middle to upper OA net sand interval ranges up to 30 feet thick. The OA sands at Sand M Pad consist of at least two cycles of alternating coarsening upward, then fining upper sand units. The thickest and highest quality OA sands at Sand M Pads generally occur at the base of the lower fining upward section. The middle coarsening upward section at Sand M Pad is generally poor to non-reservoir in quality and may form a vertical reservoir "baffle" between higher permeability units at the top and base of the OA sand. Upper OA sands at Sand M Pad generally exhibit a thin (~ 10 foot thick) moderately permeable sand unit near the top of the OA sand section. OA sands at W Pad show a dominantly coarsening upward log profile with the highest quality sands present in the upper third of the OA gross interval. The OA sand interval is typically capped at W Pad by a very thin «5 foot thick), high quality, fining upward sand which is truncated abruptly at the top OA sand contact. W Pad basal and middle OA sands are generally poor to non-reservoir in quality. Regionally, OA net sands thin slightly to the east and south from 18 net feet at S Pad to 10 to 15 net feet at W Pad and 7 to 12 net feet at M Pad. OA sands are very fine to fine- grained, faintly laminated to massive and moderately to strongly bioturbated, particularly in the upper fining upward sand section. OA sands are oil-bearing and productive in hydraulically fractured completions in S Pad area wells (12% of total production in S- 200). OA sands show high water saturation throughout nearly all of the W Pad area except for small attic oil accumulations localized in high standing fault block comer traps along the southern margin of the W Pad fault block. 9/60 Polaris Pool Rules and Area Injecti~rder Application <'-'" September 12, 2002 -..--= N Sands The Polaris Pool N sand interval overlies the Schrader Bluff 0 sand interval and ranges between 100 and 160 feet thick in the Polaris Pool area. Polaris Pool N sands are subdivided into three reservoir units, from deepest to shallowest - Nc, Nb, and Na. The N sand interval consists mainly of non-reservoir muds and siltstones .interbedded with a limited number of thin, but generally extensive, unconsolidated reservoir sands. Thick, regionally extensive silty mudstones in the lowermost N sand interval form an important regional vertical reservoir barrier which segregates lighter, higher quality, oil in the main development horizon 0 sands at Polaris and Milne Point (D, B, and A sands at West Sak) from heavy oil and extensive wet sands in the overlying Nand M sands (Lower Ugnu sands at West Sak). ~~ Nc Sands The Nc interval, ranging from 50 to 95 feet thick, is dominated by mudstone and muddy siltstone in the Polaris Pool area and contains thin interbedded reservoir quality sands only in the upper 10 to 20 feet of the interval. Up to 15 feet of Nc net sand is locally present at the top of the Nc interval in the western S Pad area. However, elsewhere in the Polaris Pool area, Nc net sand thicknesses typically total less than five feet. Individual sands are generally unconsolidated and interbedded with thicker non-rese~oir muddy siltstones. Nc sands are very fine grained, laminated and moderately to highly bioturbated. In the S-200 well, Nc sands are hydraulically fractured along with Nb sands and produce oil at low rates (50 BOPD). Nc sands have not been completed in the W Pad area due to thin sand development and minimal standoff from water in overlying Nb sands. -c:y Nb Sands The Nb sand interval ranges from 30 to 45 feet thick and comprises the primary N sand interval completion target. Nb net sand character is highly variable in the Sand M Pad areas with net sand thicknesses ranging from 6 to 31 feet. Most individual Nb sands around S Pad are less than 5 feet thick and are interbedded with similar or greater thicknesses of mud and silt. Nb sand thicknesses are greater around W Pad (15-21 feet) than S Pad, and individual Nb sands are typically higher net to gross in W Pad wells than 10/60 - Polaris Pool Rules and Area InJt.--:Üon Order Application September 12, 2002 in S Pad wells. Limited core-extracted oil fluid data from W Pad Nb sands suggests that W Pad Nb oil is relatively low quality compared with S Pad (14 API gravity at W Pad vs. 17-19 API gravity at S Pad). In addition, basal Nb sands in well W -200 appear to be wet in a relatively crestal reservoir position in the W Pad fault block. No Nb sand completions have been made to date in the W Pad area due to the apparent poor oil quality and the presence of water in the basal Nb section. Nb sands were hydraulically fractured along with Nc sands in the S-200 well and produced oil at commingled rates of 50 BOPD. Na Sands The Na sand interval is a thin, very low net-to-gross interval, which lies at the top of the Polaris Pool N sand section. The Na section thins from 25 feet around W Pad to 15 feet in the Sand M Pad areas. Na reservoir sands are generally very fine-grained, laminated, and bioturbated. Individual Na sands are two to four feet thick, exhibit a spiky log character, and are interbedded with thicker non-reservoir siltstones. Thicker Na sands are developed only in the down structure eastern W Pad area. No Na sand completions have been made to date due to poor sand development in recently drilled Polaris Pool wells. M Sands The Polaris Pool M sand interval overlies the N sand interval and ranges between 180 and 250 feet thick in the Polaris area. Polaris Pool M sands are subdivided into four reservoir units, from deepest to shallowest - Mc, Mb2, Mb 1, and Ma. Appearance of the clean and coarser grained U gnuM sands marks a north to northeast regional progradation of the Schrader Bluff shoreline and a regional shift in deposition from Schrader Bluff marine shelf and shoreface sediments to U gnu deltaic and fluvial deposits in the Polaris area. The M sand interval consists of very high quality unconsolidated clean sands separated by generally thin, but extensive, non-reservoir silty mudstone units. Mudstones within the M sand interval vertically separate individual hydrocarbon and water-bearing M sand 11/60 ~~ Polaris Pool Rules and Area InjecL~Jrder Application .........,,/ September 12, 2002 '- units, even in high net to gross sand units, and provide competent top seals to the Polaris Pool development interval. M sand hydrocarbons consist of heavy, biodegraded crude (12 to 14 degree API gravity) based on fluids extracted from sidewall and conventional core plug samples. To date, no M sand production has been attempted and, no M sand downhole oil sampling has been successful. '-- Me Sands The lower U gnu Mc sand interval, ranging in thickness from 50' to 70 feet, is the lowermost M sand interval and the uppermost reservoir interval included in the Polaris Participating Area. Mc sands are highly variable in log profile, > ranging from thick- bedded and blocky to very thin bedded and spiky. Conventional core samples in the Mc interval show that the sands are typically fine grained and highly unconsolidated. -- ~ Mc sands are thickest along a narrow north-south trend in the western Polaris Pool area extending from western S Pad to W Pad. Significant thinning occurs in the Mc sands eastward across S Pad and eastward between W Pad and well K 22-11-12, the nearest offset well to the east of W Pad. The elongate Mc isopach trend suggests channelized deposition in a north-south direction, possibly as incised valley fill, cut into the top of the underlying marine mudstone section. Mc sands are separated from the underlying Na sands by a 15 to 25 foot thick silty mudstone, which forms a regional seal separating the Polaris N sands from the M sand reservoirs. Evidence of the sealing capacity of the lower Mc mudstone is seen in the W Pad and TW-C areas where oil-bearing N sands are separated from overlying water- bearing Mc sands across the lower Mc mudstone interval (Exhibit 1-4). '''-~ The productive potential of the Mc sands is unknown due to the presence of heavy oil (13 to 14 API gravity from core samples), the unconsolidated sand character, and the lack of a Mc sand production test. Any future testing of Mc hydrocarbons would likely occur in the crestal S Pad area where Mc pay sands are thickest. Relatively low net to gross Mc sands are present over most of the downdip S, M, and W Pad areas. . - 12/60 Polaris Pool Rules and Area InJ ..on Order Application September 12, 2002 Mb2 Sands The Mb2 sand interval ranges in thickness from 35 to 70 feet, and together with the overlying Mb 1 sands, fonn the highest net to gross intervals in the Polaris Pool. The Mb2 section is thickest along a broad east-west trending band in the southern Polaris W Pad area, and along a narrow northwest-southeast trending graben in the northern Polaris central Sand M Pad area. The thicker Mb2 interval present in the S/M graben feature suggests that Mb2 deposition in the central Sand M Pad area may have been influenced by localized syndepositional faulting. Mb2 sands, generally cleaning upward to blocky in log profile, range in thickness from 20 to 55 feet above a 15 to 35 foot thick silty mudstone base. Similar to the Mc sands, Mb2 sands are typically fine-grained, highly unconsolidated, and very high penneability (up to 1200 md. in S-200PBl core plugs). The 15 to 35 foot thick basal Mb2 mudstone fonns a regionally continuous vertical reservoir barrier separating the high net to gross U gnu Mb and Ma sand units from the underlying lower net to gross Polaris 0, N, and Mc sand reservoirs. An isopach map showing the regional thickness and extent of the lower Mb2 mudstone is shown in Exhibit 1-6. In the crestal S Pad area, the basal Mb2 mudstone separates a 30 foot oil column in the underlying Mc sands from water in high net to gross Mb2 sands above the mudstone unit (Exhibit 1-4). In updip W Pad well penetrations, the lower Mb2 mudstone separates oil-bearing Mc and Mb2 sands, each with different owe levels Based on the evidence of regional continuity and sealing capacity, the lower Mb2 mudstone unit is expected to be a competent vertical barrier, along with the other M, N, and 0 interval mudstones, which will contain fluid movements resulting from Polaris reservoir development in the 0, N, and Mc intervals within the Polaris Pool. The mechanical properties of mudstone units as vertical reservoir barriers within the Polaris Pool are discussed in the Fracture Infonnation segment of the Area Injection Operations section. Mb2 sands are largely wet, or contain thin intervals of heavy residual oil based on core samples, in the central and northern Sand M Pad and in the downdip W Pad areas. Mb2 sands contain heavy oil in the southern S Pad fault block and in the crestal W Pad area. 13/60 Polaris Pool Rules and Area Injecti(J._der Application ~/ September 12, 2002 No Mb2 sand live oil fluid samples or production tests have been acquired in any Polaris area well. ...... Mbl Sands The Mb 1 sand interval ranges in thickness from 40 to 60 feet and is the highest individual net to gross sand unit in the Polaris Pool interval (.84 net to gross in cored well S- 200PB 1). The Mb 1 section thins gradually from southwest to northeast across the Polaris area, but demonstrates local thickness variations of up to 16 feet·between closely spaced wells in the northern Polaris M Pad area. Unlike the Mb2 interval, the Mb 1 section does not show any clear evidence of depositional thickening or thinning influenced by syndepositional faulting. - Mbl sands are mainly cleaning upward in log profile above a two to ten foot thick silty mudstone base. The Mb 1 sand section is generally layered in ·less than one foot to five foot thick sand units separated by thinner finer grained layers (down to silt size). Overall, Mb 1 sand layer thicknesses and grain size increases toward the top of the Mb 1 interval. The highest quality Mbl sands generally occur in the upper 10 to 15 feet of the section. Mb 1 sands are typically fine grained and highly unconsolidated. .~ The thin basal Mb 1 mudstone forms a vertical reservoir barrier at S Pad where downdip Mb 1 sands often contain oil at structural depths where Mb2 sands are wet in offset up dip wells. It is less clear at W Pad whether the thin Mb1 mudstone hydraulically separates the Mb 1 and Mb2 sands due both to the thin character of the mudstone at W Pad and due to an absence of closely spaced well data showing conflicting fluid levels in the Mb1 and Mb2 sands. In general, Mb 1 sands are oil bearing in many crestal Polaris fault block areas where the underlying Mb2 sands are wet. Mbl sands contain heavy oil (12 to 14 API gravity) in crestal wells S-200PB1 and W- 200PB 1 based on conventional core samples. Mb 1 oil quality in downdip areas is expected to be poorer than the crestal wells due to increased exposure to fresh(er) water and biodegradation near the M sand oil/water contact. I¿~pj" 14/60 Polaris Pool Rules and Area InJ~ _,1On Order Application September 12, 2002 Ma Sands The Ma sand interval ranges between 45 and 55 feet thick across the Polaris area and fonns the uppennost Polaris Pool reservoir interval. Ma sand log profiles show a basal 5 to 15 foot thick basal mudstone grading upward into 35 to 40 foot thick sand interval consisting of a lower cleaning upward and an upper fining upward sand unit. Ma sands are typically very fine to fine grained, unconsolidated, and exhibit a moderate net to gross appearance relative to the underlying high net to gross Mb sands. Unlike the underlying Mb sand intervals, Ma sands are thickest and cleanest in the northern Polaris area and thin significantly to the south toward the W Pad area. A 5 to 20 foot thick silty mudstone overlies the uppennost Ma sand and fonns the regional top seal to the Polaris Pool interval. Ma sands contain 12 degree API gravity oil based on core derived fluid samples in the Polaris S Pad area. No Ma sand live oil fluid samples or production tests have been acquired in any Polaris area well. Schrader Bluff Formation Structure Exhibit 1-3 is a structure map on the top of the Schrader Bluff OA Sand in the Polaris Pool area, with a contour interval of 20 feet. Although the Schrader Bluff interval generally dips eastward and northeastward at gentle dips of 0 to 4 degrees in the western portion of the Prudhoe Bay Unit, it is broken up into a series of distinct fault blocks, as indicated by 3D seismic data. The structural character at the Schrader Bluff level in the vicinity of the Polaris Pool is dominated by three different fault trends: Northwest- Southeast, North-South, and East-West. Northwest-Southeast Fault Trend The northwest -southeast striking fault trend, with throws of up to 200 feet dominates the southern part of the Polaris Pool. Faults with this orientation occur as antithetic pairs or triplets, forming elongate grabens such as the one along the southwestern margin of the proposed Polaris P A. Northwest-southeast trending faults with throws of 25 to 75 feet 15/60 Polaris Pool Rules and Area Injectic._,der Application 'V September 12. 2002 are found in the M and S Pad area. These faults occur in an antithetic pair; forming a crestal graben along the structural high running through S Pad to just south of M Pad. North-South Fault Trend" Apparent Horst Blocks North-South striking faults, generally downthrown to the west are the second most dominant fault system in the Polaris Pool. These faults have throws of up to 250 feet. Some of the north-south trending faults can be demonstrated to have relatively late movement, with offsets as shallow as 800 feet TVDSS in the permafrost. -... A number of the north-south trending faults appear in pairs apparently forming elongate horst blocks. These apparent horst blocks are seen in the areas west and southwest of the V-200 well, northwest of S Pad, and a very long, narrow horst appears west and north of W Pad. The east-dipping fault in the pair is invariably truncated by the larger offset west-dipping fault. -- East- West Fault Trend East-West striking faults that dip both north and south are common in the downdip (eastern and northeastern) areas of the Polaris Pool. These faults have throws of up to 100 feet. Most of these faults are located where the Schrader Bluff Formation is in the regional aquifer, with limited exceptions: An east-west trending, south-dipping fault forms the southern boundary of the Schrader Bluff accumulation just west of N Pad. This fault has a throw of up to 80 feet. An east west trending, south-dipping fault subdivides the reservoir in the area of the well K 22-11-12, east of W Pad. SPad-MPad Structure in the S Pad - M Pad area consists of a complexly-faulted structural high, which plunges towards the southeast, where it is truncated by a large east-west fault near N Pad. The structure is dominated by a northwest-southeast striking pair of antithetic faults which intersect a large offset, north-south trending, and west-dipping fault system. The northwest -southeast antithetic fault pair subdivides the S Pad - M Pad structure into three major fault sub-blocks: 1) A crestal area and northeast-dipping flank, with S-200 and S-201 in this fault block; if'"" 16/60 Polaris Pool Rules and Area InJ "on Order Application September 12, 2002 2) A crestal graben located between the two NW -SE faults, which runs from just south of the S Pad surface location, to just south of the M Pad surface location; 3) A fault-bounded structural high south of the graben, with development wells S-213 and S-216 situated in this fault block. Term Well C (TW-C) Area Term Well C (TW -C) is located in a saddle down dip from the structural high at W Pad to the south and downthrown by faulting from the southern S Pad/M Pad fault block. A long, north-south fault lies to the west. TW -C appears to be separated from the V -200 block by small offset faults, some of which may be inferred from fluid contact data. A fault system separates the TW -C block from the southern S Pad fault block. WPad The structural trap at W Pad is formed by the intersection of a major northwest-southeast oriented fault with a large-offset north-south trending fault system, with dip closure to the east and northeast. The downdip extent of structural closure to the southeast is dependent upon the juxtaposition of sand intervals across, and clay/shale smearing along, a small offset east-west trending fault. The W Pad trap appears less intensely faulted than the S Pad/M Pad areas. Reservoir Compartments Elements of each of the major area fault systems were used to subdivide the Polaris Pool into reservoir compartments for development planning purposes. The location and areal extent of these reservoir compartments is marked by the polygon boundaries shown in Exhibit 1-7. Each compartment was defined along mapped fault trends and was assumed to be hydraulically isolated by sealing faults from adjacent compartments. The sealing character of the faults forming the compartment boundaries is inferred from both limited fluid contact and pressure data at Polaris and from analog studies which show a high probability of clay smear seals forming along faults in the Polaris low net to gross reservoirs. Polygon nomenclature and boundary character is summarized below. 17/60 "../ Polaris Pool Rules and Area Injectiot.._..er Application Reservoir PO]V2on S/M Pad North S/M Pad Graben S/M Pad South W PadfTWC Polygon K 22-11-12 Polygon Horst Block Polygon Fluid Contacts September 12, 2002 Table 1 Boundarv Character Fault bounded on south and west; bounded by OillWater contacts on the north and east. Fault bounded on north, south, and west; bounded by Oil/W ater contacts on the èast. Downthrown from SIM Pad North and S/M Pad South polygons. Fault bounded on north, south, and west; bounded by Oil/W ater contacts on the east. Up-thrown to W PadrrwC and S/M Pad South polygons. Fault bounded on north, south, and west; bounded by Oil/W ater contacts on the east. Downthrown to S/M Pad South and Horst Block polygons. Fault bounded on north, south, and west; bounded by Oil/W ater contacts on the east. Downthrown to W PadffWC polygon. Fault bounded on all sides. Up-thrown to W PadfTWC polygon. Exhibits 1-8 and 1-9 show the depths of interpreted Oil/Water Contacts (OWCs) in the M, N, and 0 sands in the Polaris Pool in the SIM and W Pad areas. M sand OWCs are relatively well defined by existing well control. Nand 0 sand OWCs are less well defined due to the lack of well control in down structure areas. No Gas/Oil Contacts (GOCs) have been logged in any Polaris sand nor is the presence of free gas in Polaris Pool intervals predicted from oil PVT test results. Each sand in the Polaris N and 0 interval was assumed to be vertically isolated from overlying and underlying sands and was assumed to have a different associated OWC depth. 18/60 Polaris Pool Rules and Area In" ,cion Order Application September 12, 2002 Nand 0 Sands Most Polaris Nand 0 sand OWCs were interpreted 1. at the midpoint between the deepest Oil-Dawn-To (ODT) levels logged in upstructure wells and the downdip structural spill point for each sand 0V Pad), or 2. at the midpoint between the updip ODT levels and downdip Water-Up-To (WUT) levels in thedowndip N-13 well (S and M Pad). An open hole OWC of -5226' TVDSS was logged in the OBd sand in the W-201 well in the down structure W Pad area. A W Pad crestal area OA sand Oil-Dawn-To (ODT)/OWC level of -4834' TVDSS is interpreted between a 10 vertical foot range of Oil-Dawn-To and Water-Up-To levels in offset wells W-40 and W-200 PBl. A W Pad Nb sand OWC of -4756 feet TVDSS was logged in well W-203. Based on the described methodology, the Nand 0 sand expected case oil column heights at Sand M Pad range between 210 feet (OBf) and 290 feet (Nc). Sand M Pad area N and 0 sand OWC depth uncertainties average 100 vertical feet per sand between the minimum possible and maximum possible OWC cases. W Pad expected case oil column heights range from 35 feet (OA sands) and 68 feet (Nb sands) to 290 feet (OBc). The W Pad area OB sands average oil column height is 270 feet. W Pad area Nand 0 sand OWC depth uncertainties between the minimum possible and the maximum possible OWC cases average 150 vertical feet per sand. The presence of wet OA sands in the W Pad/TWC fault block structurally high to oil-filled OA sands in the S/M Pad North and South polygons indicates that the S/M Pad fault blocks are in fluid isolation from the W PadffWC area fault blocks. M Sands In contrast to the minimal number of Polaris Nand 0 sand fluid contacts logged, Mb and Mc Sand OWCs have been logged in numerous wells in the S, M, and W Pad areas. Ma sand OWCs have not been logged in any Polaris well. The improved definition of Mb and Mc sand OWCs results from: 1. M sand OWCs are more concentrated in crestal, rather than downdip, fault block areas beneath existing well pads and have been penetrated and logged by more PBU wells than have the N or 0 sand OWCs, and 19/60 Polaris Pool Rules and Area Injectio"_Jer Application ~y September 12, 2002 2. oil versus water contrast is more apparent in the relatively thick and clean M sand section than in the lower net-to-gross Nand 0 sands. Similar to the Polaris Nand 0 sand intervals, M sand OWC levels logged in different M sand intervals indicate that each M sand behaves as a separate reservoir unit. L=o" An Mc sand OWC was logged in well W -200 at -4635' TVDSS in the crestal W Pad area upstructure and fault separated from Mc oil in the Mobil exploration well K22-11-12 (Exhibit 1-9). This difference in Mc OWC levels between wells indicates structural and/or stratigraphic isolation between the W Pad and K22-11-12 fault blocks. Mc sand OWC depths in the Sand M Pad areas were interpreted at the midpoints between Oil- Down-To and Water-Dp-To depths logged in Sand M Pad wells. Based on the available fluid data, Sand M Pad area Mc OWCs were assumed to be different for each major fault block and may be stratigraphically as well as structurally controlled. Mb2 OWCs logged in the crestal S Pad area indicate reservoir compartmentalization between the well S-200 location (Mb2 OWC of -4730 feet TVDSS) and several adjacent wells (e.g. S-16 and S-31) which logged Mb2 OWCs at -4794 feet TVDSS. A W Pad area Mb2 OWC of --4595 feet TVDSS was constrained by water-up-to and oil-down-to levels in crestal wells W-200PBl (ODT of -4583 feet TVDSS) and W-203 (WDT of - 4604 feet TVDSS). No Mb2 OWCs were logged at M Pad where the Mb2 sands lie below the regional OWC levels logged at S Pad. Logged and interpreted OWC depths at Sand W Pads result in expected case oil column heights of 30 to 94 feet at S Pad, and 35 feet at W Pad. An Mbl sand OWC depth at --4770 feet TVDSS is well defined in the crestal S Pad area by multiple logged wells. An M Pad Mb 1 OWC of -4839 feet TVDSS was logged in well M-Ol. An Mb1 OWC of -4592 feet TVDSS logged in crestal W Pad well W-212 lies 178 and 247 feet, respectively, higher than the interpreted Sand M Pad Mb2 OWCs. Projected Mb1 oil column heights are 135 feet at S Pad, 79 feet at M Pad, and 112 feet at WPad. 20/60 Polaris Pool Rules and Area InJ .on Order Application September 12, 2002 Ma sand OWCs are interpreted at the midpoint between updip oil-dawn-to and down dip water-up-to levels at S and M Pad (-4810 feet TVDSS at S Pad, Exhibit 1-4; and -4832 feet TVDSS at M Pad), and between updip oil-down-to and the downdip structural spill point at W Pad (-4700 feet TVDSS) (Exhibit 1-9). Based on the interpreted OWC depth, the Ma sands contain oil column heights ranging between 130 feet and 280 feet at SIM Pad and W Pad, respectively. Net Pay and Pool Limits The limits of the Polaris Pool are defined by up dip fault barriers and downdip at the zero foot limits of M, N, and 0 sand expected case net pay. Polaris is bounded on the west and south by north-south and northwest-southeast faults where the reservoir is juxtaposed against impermeable silts and mudstones of the upper Schrader Bluff Formation and overlying U gnu Formation. To the east and north, the Polaris Pool limit is defined by the down-dip intersection of the top of the reservoir with the expected case 0, N, and M sand oil-water contacts. Polaris Pool net pay thicknesses were derived using a petrophysical log model developed for the Polaris Pool. Reservoir porosities were based on log bulk density readings. Grain densities were tied to conventional core grain density measurements from the S-200PB 1 and W-200PBl wells. Water saturations were calculated using the Archie water saturation equation. Porosity and permeability relationships were derived using core porosity versus core permeability crossplots. Log model cutoffs of 6 millidarcies permeability and .55 water saturation units were used to define Polaris net pay. Exhibits 1-10, 1-11, and 1-12 show the location of the proposed Polaris Pool Rules area in relation to the Polaris Pool fault boundaries and expected case limits of 0, N, and M sand net pay. Exhibit 1-10 is a Polaris Pool composite 0 sand net pay map showing the combined thickness and extent of the Polaris area OA through OBf sand net pays in relation to the proposed Pool Rules and Participating Area boundary. The map has a contour interval of 10 feet. Exhibit I-II is a Polaris Pool composite N sand net pay map showing the combined N a through N c sand net pay thickness, with a contour interval of 5 feet. Exhibit 1-12 is a Polaris Pool composite M sand net pay map showing the combined 21/60 Polaris Pool Rules and Area Injectio._jer Application '-."./ September 12, 2002 Ma through Mc sand net pay thickness, with a contour interval of 10 feet. Exhibits 1-13, 1-14, and 1-15 show the limits of the Polaris Pool Rules area in relation to 0, N, and M sand oil pore-foot thickness contours. Similar to the net pay maps in Exhibits 1-10 through 1-12, the 0, N, and M oil pore-foot thickness maps represent the combined oil pore-foot thickness for all of the 0 sands (Exhibit 1-13), all of the N sands (Exhibit 1-14), and all of the M sands (Exhibit 1-15). '-'t 22/60 Polaris Pool Rules and Area InJ .Jon Order Application September 12, 2002 II. Reservoir Description and Development Planning Reservoir management and development scenarios for Polaris have been evaluated using pattern and partial field reservoir simulation models. Analyses of well spacing and pattern configurations were performed with the simulation models to identify well locations. Evaluation of Polaris using the Polaris log model and reservoir simulation models has identified water flooding as a viable development option. Low recovery estimates for primary depletion are influenced by low gas oil ratio (GOR), low initial reservoir pressure and viscous oil. Polaris development will utilize the existing footprint ofIPA Pads S, M, and W, with minor modifications. Rock and Fluid Properties Porosity and Permeability Porosity and permeability values were measured by routine core analysis (air permeability with Klinkenberg correction) of core plugs from S-200PB 1 and W -200PB 1. A value of 0.1 was used for the ratio of vertical to horizontal permeability (kv/kh). Typical plug kvlkh values ranged from 0.001 to 1.0. Exhibit II-I shows values for porosity and horizontal permeability by zone that were used in the reservoir simulation. Porosity and permeability are areally constant in the model. No porosity or permeability cut-offs were utilized. Thick shale intervals were not included in the models but were captured as transmissibility barriers to improve simulation efficiency, while small shales were included. Water Saturation Water saturations were derived uSIng airlbrine capillary pressure analyses from S-200PB 1 and W-200PB 1 core. Distribution of the data was characterized using a Leverett I-function to capture variations in water saturation with variations in porosity and permeability. The I-function data were then used to initialize the Polaris reservoir model under capillary pressure equilibrium. Each interval was assumed to have a separate oiVwater contact; the contacts were varied in the model to represent various structural locations within the reservoir. 23/60 Polaris Pool Rules and Area Injectioi---,der Application '-" September 12,2002 Relative Permeability Relative permeability curves for the Polaris accumulation are based on unsteady state relative permeability experiments on S-200PBl and W-200PBl core. The experiments resulted in a wide range of curves that were considered of questionable validity because of problems in implementation of the unsteady state technique. The range of results was narrowed to a single curve that is nearly identical to the curves used to model the Schrader Bluff Pool within the Milne Point Unit. Exhibit ll-2 shows the relative permeability curves used in the reservoir simulation. Initial Pressure and Temperature RFf and PBV data from S-200 and W-200 indicate that initial reservoir pressure is somewhat variable, and that the reservoir is compartmentalized. A datum of 5000' tvdss has been chosen as the pressure datum for the Polaris Pool. Average initial reservoir pressure is estimated at 2180 psi at 5000' tvdss in the S Pad area and 2240 psi at 5000' tvdss in the W Pad area. Reservoir temperature is approximately 98 degrees Fahrenheit at this datum. Fluid PVT Data Two types of fluid data have been gathered at Polaris - fluids extracted from whole or sidewall core plugs and down-hole production samples. Data obtained from core plug samples are considered to have a large range of uncertainty. Samples from the same well in the same sand can show API gravity variations of up to 8-10° API units. It is unclear whether the crude variations are real or an artifact of the sample acquisition and processing procedures. The plugs are somewhat flushed during the drilling process and the residual crude may be different than the native-state crude. In addition, the small volumes, extraction techniques, and measurement techniques may contribute to the wide range of data observed to date. Reservoir fluid PVT studies were conducted on down-hole samples from the OBd, OBa/OBb and OA sands in S-200 and from the OBd/OBe sand from W -200. Though the data are limited in quantity and are subject to some uncertainty as noted, the PVT samples show significant variations in fluid properties both horizontally and vertically. 24/60 Polaris Pool Rules and Area It In Order Application September 12, 2002 These variations likely reflect varying levels of bio-degradation of the Polaris crude. In the OBd sand, API gravity ranges from 22.2 to 24.5° and solution gas oil ratio (GOR) ranged from 287 scf/stb to 326 scf/stb. In the OA sand, the API gravity was measured at 20° with a solution GOR of 250 scf/stb. The formation volume factor ranges from 1.18 to 1.11 RVB/STB in the OBd sand. The formation volume factor was measured at 1.11 RVB/STB in the OA sand. The OBd sand live oil viscosity ranges from 5.1 centipoise (cp) in S-200 to 14.22 cp in W-200. OA sand viscosity was measured at 16.1 cp at reservoir pressure and temperature. Polaris crude shows a wide range of bubble points, varying from 1994 psi in the S-200 OBd sample to 1633 psi in the S-200 OA sample. Exhibit II-3 shows a summary of the fluid properties for the Polaris accumulation. The PVT properties used in reservoir simulation were derived from measured values; the PVT tables used to represent the S Pad area are shown in Exhibit II-4. A similar set of tables was created to represent the W Pad area. Hydrocarbons in Place Estimates of hydrocarbons in place for Polaris are derived from net-oil-pore-feet maps and reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. The current estimate of oil and gas in place are as follows: Zone GOIP (mmstb) OGIP (bscf) Me 25-120 4-30 N 25-80 5-25 O-Sands 300-550 75-195 Total 350-750 84-250 The ranges in OOIP are detennined primarily by uncertainty in the oil-water contacts. The ranges in OGIP are determined by uncertainties in oil-water contacts and solution GOR. The Polaris Pool is under-saturated. Hydrocarbons in place estimates from reservoir simulation are not available because a full-field reservoir simulation model has not been developed. Fluid saturations observed in the pattern models have been compared to saturations calculated by the Polaris log model and are in good agreement. 25/60 Polaris Pool Rules and Area Injecti6__rder Application , J '- September 12, 2002 Reservoir Performance Well Performance While a number of wells have penetrated the Schrader Bluff Formation in the Polaris area, only two wells, S-200 and W-200, have been tested long term. Both wells have been producing since late 1999 and have successfully sustained rates. Both wells have used gas lift as the artificial lift method, which has caused hydrate problems to occur. The hydrate problems have been somewhat resolved by frequent hot oil tubing washes or by methanol injection. Both wells are producing under primary recovery. In addition to these wells, stable production has been established in W-201 and in S-213 with the use of continuous methanol injection. Stable production has not been established in S-201 and S-216 due to hydrate formation. S-200 is a crestal well in the northern S Pad area. Upon completion of drilling, the well received four fracture stimulation treatments targeting the N, OA, OBa, OBb, OBd, and OBe sands. Pressure buildup surveys to evaluate the effectiveness of the stimulation treatments showed skins had been reduced to -3. Some of the sands appear, at least in part, to be somewhat unconsolidated. The N sand showed strong tendencies to produce sand while preparing the well for production so a resin squeeze treatment was performed to consolidate the sand in the near-wellbore region. The treatment successfully mitigated sand production but a skin of +3 was observed from a post-treatment pressure build-up test. S-200 production was initiated in November 1999 and initially produced at 600 bopd, 450 GOR and 0-10% we. While somewhat damaged, production logs show the N sand is still contributing approximately 50 bopd. After 18 months, the well was producing 400-500 bopd, at 5-10% we and 1000 GOR, and had produced approximately 200 mbo, but was incurring 30-50% down-time because of hydrates forming in the tubing. The well has been shut in since October 2001 after developing mechanical problems with the liner. W - 200 is a crestal well in the southern W Pad area. Upon completion of drilling, the OBd and OBf sands were fracture stimulated and tested. A pressure build-up survey 26/60 Polaris Pool Rules and Area .ion Order Application September 12, 2002 indicated a -3.5 skin was achieved with the stimulation treatment. In preparing the well for production, the OBa and OBc sands were perforated and fracture stimulated. Production was initiated in December 1999 and initially tested at 1100 bopd, 450 GOR and 0-5% WC. After 27 months, the well is producing 600 bopd, at 2-50/0 WC and 2500 GOR, and has produced approximately 585 mbo. W-200 experiences minimal downtime and has not experienced significant hydrate formation but has had some paraffin buildup on the tubulars. S-213 penetrates the S/M Pad South fault block. Three fracture stimulation treatments were performed to initiate production from the N, OA, OBa, OBb, and OBd intervals. Production testing between stimulation treatments indicates that all zones are contributing to production. Stimulations were complete by mid-July 2001, and once fully stimulated, the well produced 620 bopd, 12% WC, 1100 GOR. Currently the well is producing using a jet pump as the artificial lift method. W-201 was drilled as a horizontal well in June 2001. The well was designed to find the oil-water contact (OWC) in the OBd interval, be plugged back to provide stand-off from the OWC, and then be completed as a horizontal producer in the OBd interval. The well was drilled and completed as designed, but significant formation damage was incurred in the producing interval. Production was established in July 2001 at 200-400 bopd from the horizontal interval. Attempts to remedy the damage included a formic acid treatment, perforating, and a clay acid treatment, but none were successful. The heel of the well was fracture stimulated in the OBa, OBc, and OBd sands in December 2001, significantly improving production. The well produces 600-700 bopd, 0-5% WC, 450 GOR after 7 months of production as a fracture stimulated well. Other Polaris production wells include S-201, S-216, W-203, and W-211. Exhibit IV-I . shows representative well test results for all Polaris wells. The combination of relatively low rates, low produced fluid temperatures, water, and lift gas has created hydrate problems in wells S-201 and S-216 that have not been remedied with hot oil tubing washes and methanol injection. Both wells have been converted to jet pumps as an alternative artificial lift method. Jet pumps have resolved the hydrate problems. Well W-211 was completed as a conventional fracture stimulated well in the 0 sands and is 27/60 Polaris Pool Rules and Area Injectiot~er Application '~' September 12,2002 currently producing on gas lift. Well W-203 was completed as a trilateral high-angle well with approximate 3500 foot long horizontal sections drilled in each of the OBa, OBc, and OBd sands and is also producing as a gas lifted well. AQuifer Influx The aquifer to the north and east of Polaris could provide pressure support during field development. Early production data from the flanks of the field will be evaluated to determine the extent of pressure support. Gas Conine / Under-Runnine There are no indications of a free gas column in the Polaris Pool; coning or under-run mechanisms are not anticipated. Development Planning Several reservoir models using data from the Polaris Pool were constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles. Reservoir Model Construction Initially two separate fine scale three-dimensional reservoir simulation models were constructed using S-200 and W-200 PVT data and core porosity and permeability information. The models are black oil models with grids of approximately 200 feet by 200 feet, representing an area of approximately 800 acres. The models consist of approximately 90 one-foot thick layers representing the sand in the N, OA, OBa, OBb, OBc, and OBd intervals. Faults are not present in either model. The results of the two models were similar and were used for development planning efforts. Development Options Development options evaluated for the Polaris Pool include pnmary depletion and waterflood. Preliminary screening of miscible gas flooding is also in progress. Primary Recovery Primary recovery was evaluated for development of the Polaris Pool. The primary recovery mechanism was a combination of solution gas drive and reservoir compaction. 28/60 Polaris Pool Rules and Area 1 on Order Application September 12, 2002 Model results indicate that primary depletion would recover approximately 5-100/0 of the development area OOIP. Low primary recovery is a result of a combination of low GOR, low initial reservoir pressure and viscous oil. Waterflood Waterflood has been identified as a viable development option for Polaris. It is anticipated that overall field development will involve 15-25 injectors and 25-35 producers. Due to differences in rock quality and crude quality in the different intervals, recovery ranged from 15% to 30% of OOIP (inclusive of primary recovery) in the developed area, at 1.5 hydrocarbon pore volumes injected (HCPVI). Production rates are estimated to peak at 12,000-15,000 bopd, with a maximum water injection rate of 20,000-25,000 bwpd. The Polaris waterflood oil and water production and water injection forecasts are shown in Exhibit II-5. Enhanced Oil Recovery (EaR) Preliminary evaluations indicate that EOR could yield a net recovery of up to 6% of OOIP where implemented. The recovery estimate accounts for vertical and areal sweep efficiencies in Polaris as well as the Prudhoe Bay reserve impact associated with miscible injectant (MI) usage at Polaris. It is requested that an EOR pilot be allowed on three Polaris wells to aid in designing and implementing a full EOR project. This pilot would provide injectivity and conformance information before MI injection, during MI injection, and after MI injection. The Polaris EOR pilot is requested for a period of two years, starting when water injection is initiated in the wells, to allow sufficient fillup and two full WAG cycles The pilot period will allow water injection to be established and fill-up to occur prior to MI injection and is sufficient time to allow two full WAG cycles. The three wells under consideration include one well in the S Pad area targeting the N, OA, OBa, OBb, and OBd sands and two wells in the W Pad area targeting the OBa, OBc, and OBd sands. The MI source will be Prudhoe Bay miscible injectant (MI). Polaris fluids show compositional similarity to Milne Point Schrader Bluff fluids for which an equation of state (EOS) characterization has been developed (MPU Schrader Bluff EOS). The MPU Schrader Bluff EOS was demonstrated to reliably predict Polaris 29/60 Polaris Pool Rules and Area Injection-Jer Application .~ September 12, 2002 oil PVT properties as shown in Exhibit ll-6. The MPU EOS was then used in slim-tube simulation to predict miscibility between Prudhoe Bay MI and Polaris fluids ranging in live oil viscosity from 5-40 centipoise. The slim-tube modeling demonstrated the classical multi-contact condensing/vaporizing mechanism with a minimum miscibility enrichment (MME) of lean gas with 60-70% Prudhoe Bay MI. The EOR oil recovery and solvent requirement were estimated by first performing a fine- scale fully compositional reservoir simulation using Polaris type pattern models to capture the vertical sweep efficiencies. The type pattern models were based on reservoir description from wells S-200 and W-200. MI injection in the S-200 model included zones N, OA, OBa, OBb, and OBd, and the W-200 model included zones OBa, OBc, and OBd. Scale-up of the type pattern was performed to account for areal sweep efficiencies expected with irregular patterns and complex faulting as well as the reserve impact in Prudhoe Bay due to reduced MI in the Prudhoe Bay Miscible Gas Project. Laboratory phase behavior and slim-tube experiments are underway to fine-tune the EOS characterization. A detailed reservoir simulation study will scale up the S-200 and W -200 pattern model results for application to the entire field. Scale up results will be utilized for optimizing the development to maximize benefits, optimizing WAG parameters (W AG ratio, slug volume, optimum MI start-up time) and defining the volume of Prudhoe Bay MI required as well as the expected returned MI. Horizontal Wells While there have been favorable results with horizontal multi -lateral wells in other Pools within the Schrader Bluff Formation (Milne Point and West Sak), the initial development plan for Polaris consists primarily of vertical wells. Horizontal wells may be utilized selectively. The W-201 well was drilled as a horizontal well to provide horizontal well productivity information. While production from W-201 as a horizontal well was substantially less than expected, the likely source of the problem has been identified. Simulation and development planning efforts show that horizontal wells have the potential to enhance rate and recovery in some areas while reducing development costs and minimizing facility expansion requirements. Horizontal well potential is currentlye30/60 Polaris Pool Rules and Area L on Order Application September 12, 2002 being evaluated in the W Pad area where the target has been narrowed· to three sands - OBa, OBc, and OBd. A tri-Iateral well, W -203, that targeted approximately 3500 feet of horizontal section into each of these three sands has been drilled and is currently on production. Development Plan Reservoir simulation supports implementation of a waterflood in the Polaris Pool. Initial development will take place in a step-wise approach, working from the crests towards the outer limits of the Pool, incorporating data gathering necessary to refine development plans. Peak production rates are expected to be 12,000 to 15,000 bopd. Waterflood peak injection rates are estimated at 20,000 to 25,000 bwpd. The Operator will detennine the optimal field off-take rate based upon sound reservoir management practices. Phase I Development Phase I development focuses on developing and establishing waterflood operations in select portions of three primary areas. Several water flood development options were studied using the Polaris pattern reservoir simulator; the results provided criteria for spacing of wells and identifying the number of injectors for adequate voidage replacement. Phase I development will be used to validate the development assumptions and refine Phase II and Phase III development plans. Phase I development in the S Pad area to date targets two fault blocks. S/M Pad North block development includes sidetracking S-200 to repair a split liner, then converting the well to injection to support wells S-201 and other potential wells. Performing a production test of the Mc sand in the S-200 well prior to conversion to injection is being evaluated. Other wells being planned include an additional crestal production well and a supporting offset injector, which could also support other potential wells. Aurora well S- 104i will provide support for the additional crestal producer through commingled injection in the Schrader Bluff and Kuparuk. The plans for commingled injection for well S-104 are discussed in the Operations section. Development of the S/M Pad South block consists of two existing producers, S-213 and S-216, and a planned supporting injector S-215i. 31/60 Polaris Pool Rules and Area InjectiÒrP-drder Application '-'" September 12, 2002 Phase I development in the W Pad area also is underway and consists of drilling one producer, W-211, and a supporting injector, W-212i, which will also support existing well W-200. A tri-Iateral horizontal well, W-203, in the down-dip area of the W Pad polygon, has recently been drilled. It is anticipated that offset injectors will be planned once horizontal well performance has been evaluated and incorporated into the development plans. Phase II Development Polaris Phase IT development is directed to completing development of the north, graben, and south S Pad polygons, the W Pad polygon, and the K22-11-12 polygon. Development of these polygons will require an additional 8-12 producers and 5-7 injectors in the S Pad area and 3-8 producers and 4-8 injectors in the W Pad and K22-11-12 areas. Potential locations have been identified but may be modified as production performance from Phase I development, especially horizontal well performance, is evaluated and simulation efforts are continued. The Phase II drilling program is designed to access down-dip areas with higher water saturation as well as higher-risk, structurally complex areas. Phase III Development Polaris Phase ITI development would involve developing areas that require improved understanding of fault transmissibility and presence, or refinements in drilling techniques to reach the targets. These areas include the Term Well C area, the Horst Block area, and extreme down-dip areas of the blocks developed in Phase I and Phase II. Phase I and Phase II results and performance data will be key in moving forward with developing Phase III areas. Well Spacin2 Initial well spacing for development is nominally 120 acres under the vertical well development scenario. Due to faulting, the patterns are expected to be irregular and wells may be areally very close to adjacent wells but will be isolated due to reservoir compartmentalization. Infill drilling and peripheral drilling will be evaluated based on production performance and surveillance data. To allow for future flexibility in 32/60 Polaris Pool Rules and Area .l .ion Order Application September 12,2002 developing the Polaris Pool and tighter well spacing across fault blocks, a minimum well spacing of 20 acres is requested. Reservoir Management Strategy A key development strategy is to maintain reservoir pressure above the bubble point. Drilling injectors and establishing waterflood patterns as the producers are drilled will minimize offtake under primary depletion. The voidage replacement ratio (VRR) will be balanced to maintain average reservoir pressure above the bubble point pressure. The objective of the Polaris reservoir management strategy is to operate the Pool in a manner that will maximize recovery consistent with good oil field engineering practices. To accomplish this objective, reservoir management is approached as a dynamic process. The initial strategy is derived from model studies and limited well test information. Development well results and reservoir surveillance data will increase know ledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Polaris Pool will continue to be evaluated throughout the life of the field. Reservoir Performance Conclusions Reservoir simulation supports implementation of a waterflood in the Polaris Pool. Development will take place in up to three phases. The first phase includes establishing production and waterflood operations in key areas at both S Pad and W Pad. Additionally, Phase I accommodates a tri-Iateral horizontal producer. Phase II would encompass developing the remainder of the core areas of the field. Phase III would progress development in areas that currently require improved understanding including fault transmissibility and presence, or refinements in drilling techniques to reach the targets. Peak production rates are expected to be 12,000 - 15,000 bopd. After waterflooding commencement, peak injection rates will be 20,000 - 25,000 bwpd. It is requested that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices. Polaris production performance to date can be divided into two aspects - reservoIr delivery and well operability. Production results to date confirm initial evaluations of 33/60 Polaris Pool Rules and Area Injectioh~er Application ~ September 12, 2002 reservoir delivery. Well operability, affected primarily by hydrate formation, has been more of a problem in recent wells than indicated from initial production. Keeping the wells on line with a combination of low rates, cool production temperatures, presence of ·water, and lift gas composition and temperature, have proven both challenging and costly. The use of alternative artificial lift methods, enhancing rate through better fracture stimulations and the use of horizontal wells are all expected to improve operabili ty. - 34/60 Polaris Pool Rules and Area 1 In Order Application September 12, 2002 III. Facilities General Overview Polaris wells will be drilled from existing IP A drill sites, M Pad, S Pad and W Pad, and will utilize existing IP A pad facilities and pipelines to produce Polaris fluids to Gathering Center 2 (GC-2) for processing and shipment to Pump Station No.1 (PS 1). Polaris fluids will be commingled with IP A fluids on the surface at the respective Well Pads to maximize use of existing IP A infrastructure, minimize environmental impacts, reduce costs, and maximize recovery. The GC-2 production facilities to be ·used include separating and processing equipment, inlet manifold and related piping, flare system, and onsite water disposal. IP A field facilities that will be used include low-pressure large diameter flowlines, gas lift supply lines and water injection supply lines associated with the three IP A pads. Existing MI supply lines may be utilized for future EOR applications. The oil sales line from GC-2 to PS 1 and the power distribution and generation facilities will be utilized. Exhibit III-l shows details of the Polaris well tie-ins at S Pad and Exhibit III-2 shows details of the proposed S Pad Polaris development. Drill Pads and Roads M Pad, S Pad and W Pad have been chosen as the surface locations of Polaris wells to reach the expected extent of the reservoir while minimizing new gravel placement, minimizing well step out, and allowing for the use of existing facilities. An expansion of existing S Pad to accommodate additional wells was completed in April 2000. Additional gravel requirements at M Pad and W Pad have not been determined. However, efforts will be made to stay within the existing permitted footprint of these Well Pads. A schematic of the S Pad drill site layout including contemplated Polaris facility additions is shown in Exhibit 1II-2. Schematics of the existing M and W Pads are included as Exhibit III-3 and III-4. 35/60 Polaris Pool Rules and Area Injectio~er Application '-"' September 12,2002 No new pipelines are planned for development of the Polaris reservolf. Polaris production will be routed to GC-2 via the existing low-pressure large diameter flowlines. No new roads or roadwork is anticipated. Pad Facilities and Operations A trunk and lateral production manifold capable of accommodating up to 20 Polaris wells is planned as an extension to an existing S Pad manifold system. A schematic showing the surface well tie-ins is shown in Exhibit ill-2. The size and type of well tie-in manifold system required for M Pad and W Pad have not been determined. Water for waterflood operations will be obtained by extending an existing 6" water injection supply line at S Pad. Preliminary engineering calculations indicate the line is sufficient to deliver water to Polaris injection wells at a rate of 28,000 bpd and a pressure of approximately 2000 - 2100 psig. Should water injection pressures be insufficient, injection pressure will be boosted locally. An upgrade of the existing S Pad power system should not be required for additional water injection booster pumps. Artificial lift will be performed either with artificial lift gas or with jet pumps using injection water as the power fluid. Artificial lift gas will be obtained from the existing 10" gas lift supply line at S Pad. Preliminary engineering estimates indicate that the line is sufficient to deliver gas to Polaris production wells at a rate of 30 mmscfd and a pressure of approximately 1800 psig. For jet pumping, injection water pressure may need to be boosted locally to optimize the power fluid to produced fluid ratio. It is anticipated that water for waterflood operations, artificial lift gas and MI (if needed) can be supplied to Polaris wells at M Pad and W Pad from the existing pipeline infrastructure. Should injection pressure be insufficient for Polaris requirements, it could be boosted locally. Well control will include automated divert valves. Well safety systems and the pad emergency shutdown system will be set up to be operated manually as well. Wells will be tested using existing well test facilities at S, M and W Pads. Wells will be 36/60 Polaris Pool Rules and Area 1 In Order Application September] 2, 2002 put into test using automated divert valves. Test frequency and protocols are addressed in Section V. Well pad data gathering will be performed both manually and automatically. The data gathering system will be expanded to accommodate the Polaris wells and drill site equipment. The data gathering system will continuously monitor the flow, pressures and temperature of the producing wells. These data will be under the well pad operator's supervision through his monitoring station. Gathering Center No modifications to the GC-2 production center will be required to process Polaris production. GC-2 was built to process a nominal oil rate of 400 mbopd, gas rate of 320 mmscfd (modifications have increased this to 1,200 mmscfd) and a nominal produced water rate of 280 mbwpd. Production, including that from the Polaris Pool, is not expected to exceed GC-2 capacity. 37/60 Polaris Pool Rules and Area lnjectiofr-Jer Application ,-" September 12, 2002 IV. Well Operations Existing Wells A number of exploration, appraisal and development wells that targeted the deeper Kuparuk and Ivishak production have been drilled and logged in the Schrader Bluff Formation. However, only the recently drilled S-200, S-201, S-213, S-215i, S-216 W- 200, W-201, W-203, W-211 and W-212i have been drilled and completed in the Polaris Pool. These well locations are shown in Exhibits 1-2 and 1-3. The Polaris Pool is currently producing from four W Pad wells (W-200, W-201, W-203, and W-211) and four S Pad wells (S-200, S-201 S-213, S-216). Recent well test data for these wells are shown in Exhibit IV-I. S-200 was shut-in in October 2001 due to a liner problem. One W Pad injector, W-212i, and one S Pad injector, S-215i , will be available for water injection upon approval of the Area Injection Order. A second S Pad injector, S-200, will be available for water injection once the well is converted from a producer to an injector, scheduled by year end. Drilling and Well Design Polaris development wells will be direction ally drilled utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in the Prudhoe Bay Unit and other North Slope fields. A 16" or 20" conductor casing will be set 80' to 120' below pad level and cemented to surface. Requirements of 20 AAC 25.035 concerning the use of a diverter system and secondary well control equipment will be met. Surface hole will be drilled no shallower than 500 TVD feet below the base of pennafrost level. This setting depth provides sufficient kick tolerance to drill the wells safely and allows the angle/build portions of high departure wells to be cased. No hydrocarbons have been encountered to this depth in previous PBU wells. Cementing and casing requirements similar to other North Slope fields have been adopted for Polaris. 38/60 Polaris Pool Rules and Area 1 ion Order Application September 12, 2002 The casing head and blowout-preventer stack will be installed onto the surface casing and tested consistent with 20 AAC 25.035. The production hole will be drilled below surface casing to the target depth in the Schrader Bluff Formation, allowing sufficient rathole to facilitate logging. Production casing will be set from surface and cemented. Production liners will be used as needed to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells, such as high departure or horizontal wells. No significant H2S has been detected in the Schrader Bluff Fonnation while drilling other development wells or in any Polaris well drilled to date. However, with planned waterflood operations there is potential of generating H2S over the life of the field. Consequently, H2S gas drilling practices will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellpad. All personnel on the rig will be informed of the dangers of H2S, and all rig pad supervisors will be trained for operations in an H2S environment. Well Design and Completions Multi-lateral, horizontal and conventional wells may be drilled at Polaris. The horizontal and multi-lateral well completions could be perforated casing, slotted liner, barefoot section, or a combination. All conventional wells will have cemented and perforated completions. Fracture stimulation may be necessary to maximize well productivity and injectivity. Tubing sizes will vary from 2-3/8" to 5-1/2" depending upon the estimated production and injection rates. In general, production casing will be sized to accommodate the desired tubing size in the Polaris wells. 39/60 Polaris Pool Rules and Area Injectioñ~er Application ~ September 12, 2002 The following table indicates typical casing and tubing sizes for proposed Polaris wells: Surface Casing Inter / Prod Casing Production Liner Production Tubing Conventional 10-3/4" to 7" 7" to 3-1/2" Not Planned 4-1/2" to 2-3/8" Horizontal & 10-3/4" to 7" 7" to 4-1/2" Multi-lateral 5-1/2" to 2-7/8" 4-1/2" to 2-3/8" Plans are to run L-80 grade casing in the Polaris wells. Tubing strings will be completed with either 13-Chrome or L-80 protected with corrosion inhibitor as necessary. Tubing jewelry will be composed of either 13-Cr or 9-Cr/lMoly, which is compatible with both L-80 and 13-Cr. Use of 13-super chrome or equivalent is possible on certain completion jewelry. Polaris producers will be completed in a single zone (Schrader Bluff Formation). Injectors may be single or multi-zone (Kuparuk, Schrader Bluff, Sag and/or Ivishak Formations) utilizing a single .string and multiple packers as necessary. As shown in the typical well schematics (Exhibit IV-2 for conventional production wells, Exhibit IV-3 for conventional injector wells, and Exhibit IV-4 for multi-zone injector wells), the wells have gas lift mandrels to provide flexibility for artificial lift or commingled production and injection. A sufficient number of mandrels will be run to provide flexibility for varying well production volumes, gas lift supply pressure, and water-cut. Additionally, jewelry will be installed so that jet pumps can be utilized providing further flexibility for artificial lift. Any completions that vary from regulatory specifications will be brought before the Commission on a case by case basis. The Polaris Owners may utilize surplus IP A wells for development provided they meet Polaris needs and contain adequate cement and mechanical integrity. The injectors will be designed to enable multi-fonnation injection where appropriate to the Kuparuk, Schrader Bluff, Sag and Ivishak Formations. Injectors may be pre- produced prior to converting to pennanent injection. Production from these wells could improve their injectivity and be used to evaluate reservoir productivity, connectivity and 40/60 Polaris Pool Rules and Area -ion Order Application September 12, 2002 pressure response, enabling refinement of reservoir models and depletion plans. Measurement while drilling (MWD) and logging while drilling (L WD) will typically begin after setting the 9-5/8" or 7 -5/8" surface casing. Production hole will be drilled to below the Schrader Bluff Formation and either a 5-Y2" by 3-¥z" or 7" long string will be cemented in place across the Schrader Bluff Formation. MWD will typically include drilling parameters such as weight on bit, rate of penetration, inclination angle, etc. L WD measurements will typically include gamma ray (GR), resistivity and density and neutron porosity throughout the reservoir section. Open hole electric logs may supplement or replace LWD logging, including GR, resistivity, density and neutron porosity and other logging tools when wellbore conditions allow their use. A nine (9) to eleven (11) pound per gallon (ppg) freshwater low-solids non-dispersed mud system or equivalent will typically be used to drill the production / injection hole down to the 7" casing point. If any horizontal section is drilled, the mud system parameters may be optimized for that hole section. The horizontal wells and multi-lateral wells will typically utilize 7" intermediate casing set in the Schrader Bluff Formation. The reservoir section will be drilled with a 6-1/8" horizontal production hole, completed with a 4-¥z" or 3-¥z" slotted or solid liner, and cemented and perforated as necessary Surface Safety Valves Surface safety valves (SSV) are included in the wellhead equipment for all Polaris Pool wells (producers and injectors). These devices can be activated by high and low pressure sensing equipment on the flowline and are designed to isolate produced fluids upstream of the SSV if pressure limits are exceeded. Testing of SSVs will be in accordance with Commission requirements. Subsurface Safety Valves The characteristics of the Polaris Pool should not requIre the installation or use of subsurface safety valves on production wells. Polaris producers are relatively low rate oil wells produced by artificial lift in a waterflood development. Subsurface safety 41/60 Polaris Pool Rules and Area Injectioh_Jer Application ---- September 12, 2002 valves (SSSV) will be installed on gas or miscible injectant (M!) injectors when in service. All well completions will be equipped with nipple profile at a depth just below the base permafrost should the need arise to install a downhole flow control device or pressure operated safety valves during maintenance operations or for future MI service. Subsurface safety valves are not required in Polaris wells under the applicable regulation, 20 AAC 25.265. In light of developments in oil field technology, controls and experience in operating in the arctic environment, the Commission has eliminated SSSV requirements from pool rules for the Prudhoe Oil Pool and the Kuparuk River Oil Pool. See Conservation Orders 363 and 348, respectively. In addition, SSSVs have not been required for producing wells at Milne Point, and West Sak, also producing from the Schrader Bluff Formation. Drillin2 Fluids Freshwater low solids, non-dispersed fluids will be used to drill the Schrader Bluff Formation. Typically KCl will be added to this mud system for weight and to reduce formation damage caused by reactive clays. Other muds may be used in the future to minimize skin damage from drilling and enhance performance. Stimulation Methods Fracture stimulation has been implemented for all vertical Polaris producers drilled to date and may be implemented in the future to mitigate formation damage, for sand control and to stimulate Polaris wells. It may also be necessary to stimulate horizontal wells, depending upon well performance. Acid or other forms of stimulation may be performed as needed in the future. Reservoir Surveillance Program Reservoir surveillance data will be collected to monitor reservoir performance and define reservoir properties. Reservoir Pressure Measurements An updated isobar map of reservoir pressures will be maintained and reported at the 42/60 Polaris Pool Rules and Area .ion Order Application September 12, 2002 common datum elevation of 5,000' TVDSS. Pressure data could be stabilized static pressure measurements at bottom-hole or extrapolated from surface (assuming single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, repeat formation test, permanent gauges, or an open hole formation test. An initial static reservoir pressure will be measured on each production or injection service well. A minimum of one reservoir pressure will be taken each year in each of the six Polaris reservoir polygon areas identified in Exhibit 1-7, (i.e., SIM Pad North, SIM Pad Graben, SIM Pad South, W PadffW-C, K221112, and Horst Block polygons), when at least one Polaris production well has been completed in the respective polygons. A minimum of two pressure surveys will be taken annually in the SIM Pad North and the W PadffW-C reservoir polygons, as identified in Exhibit 1-7, when two or more production wells have been completed in each of these polygons. It is anticipated that the operator will collect more pressure measurements during initial field development to identify potential compartmentalization and fewer measurements as the development matures. Data and results from all relevant reservoir pressure surveys will be reported annually and will be available to the Commission upon request. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, may be periodically run to help determine reservoir performance (i.e., production profile and injection profile evaluations). Surveillance logs will be run on commingled injection wells annually to assist in the allocation of flow splits. Completions - Producing Wells Current development plans call for two types of producing wells, conventional hydraulically fractured wells, and high angle/horizontal wells. The conventional hydraulically fractured well will have surface casing set 500 feet or deeper below the base of permafrost, located at approximately 2000' TVDSS, and cemented to surface. A "longstring" production casing will be run from surface to TD which will typically be set 100 feet below the base of the production target to allow room for production logging. The longstring will be cemented from TD to above the highest significant hydrocarbon- 43/60 Polaris Pool Rules and Area InjectioÌì~er Application "--' September 12, 2002 bearing interval in the U gnu section. Production tubing will be run inside the longstring and sealed in the long string at least above the Mc sand with a production packer or other sealing device to provide an isolated annulus to be used for gas lift. Gas lift mandrels will be placed in the tubing string as well as a sliding sleeve to accommodate jet pumps. There will be no subsurface safety valve, however a nipple will be installed at approximately 2200 feet TVDSS. There will also be nipples located above and below a production packer or other sealing device. High angle wells will be similar to the conventional completion described above. High angle wells will either have a cased and perforated completion, a slotted liner hung off in the longstring or some other variation High angle multilateral completions are being evaluated to enhance recovery and rate while reducing development costs, facility requirements, and downtime associated with lower flow rates from conventional wells. Artificial Lift The primary ·artificiallift method will be gas lifting with lift gas supplied from the gas lift system, with jet pumping using injection water as the power fluid as a possible alternative. It is anticipated that all Polaris production wells will require artificial lift for the life of the well. Gas lift has proven to provide a bottom hole flowing pressure of approximately 1000 psi but has caused operational difficulties. The majority of the producing wells are within the hydrate window when they are first starting up with gas lift, making them operationally difficult to keep online until the wellhead temperature is above 50 deg. F. Controlling hydrates has been accomplished with hot oil treatments and methanol injection with mixed success. Jet pumps are currently being deployed and tested and are expected to mitigate the hydrate problems associated with gas lift. Polaris will likely experience a mix of gas lifted and jet pumped wells throughout field life. Completions· Injection Wells The injection wells will have surface casing set below the base of the SV3 sand located at approximately 2800' TVD and cemented to surface. Exhibit IV-3 shows a typical injection well completion diagram. A "longstring" casing will be run from surface to TD which will typically be set 100 feet below the base of the injection target to allow room 44/60 Polaris Pool Rules and Area II )n Order Application September 12, 2002 for future logging. The longstring will be cemented from TD to above the highest significant hydrocarbon-bearing interval in the U gnu section. Injection tubing utilizing metal-to-metal seals will be run inside the longstring and sealed approximately 200 feet above the Ma sand with an injection packer or other sealing device to provide an isolated annulus to be used for monitoring casing integrity. Tubing-casing annulus pressure and injection rate of each injection well will be checked at least weekly to confirm continued mechanical integrity. A schedule will be developed and coordinated with the Commission that ensures 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. There will be no SSSV during water injection service, but injectors will have a nipple capable of accepting an SSSV during MI injection. Commingled Injection Approval is requested to complete commingled injectors where deemed prudent, including approval for commingled water injection in well S-104i in the Aurora and Polaris pools. Well S-104i was completed with isolation packers and injection mandrels, which will allow multi-zone water injection. Installing a restrictive orifice in the injection mandrels will control injection rates. Water injection allocation will be accomplished by performing a spinner survey at least once per year. Additional opportunities may arise to take advantage of commingled injection wells. 45/60 Polaris Pool Rules and Area Injectim,-Jer Application .\----....-- September 12, 2002 v. Production Allocation Polaris production allocation will be done according to the PBU Western Satellite Production Metering Plan, described in the letter dated April 23, 2002. Allocation will rely on performance curves to determine the daily theoretical production from each well. The GC- 2 allocation factor will be applied to adjust total Polaris production. All new Polaris wells will be tested a minimum of two times per month during the first three months of production. A minimum of one well test per month will be used to tune the performance curves and to verify system performance. No NGLs will be allocated to Polaris wells; To support implementation of this procedure, several modifications to the WOA allocation system have been initiated. Conversion of all well test separators in the GC-2 area to two-phase operation with a coriolis meter on the liquid leg is expected to be complete in 2002. The test bank meters at GC-l and GC-2 have been upgraded as part of the leak detection system and a methodology for generating and checking performance curves for each well has been developed. 46/60 Polaris Pool Rules and Area I .;m Order Application September 12, 2002 VI. Area Injection Operations This application, prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), requests authorization for water injection and a miscible gas injection pilot to enhance recovery from the Polaris Pool. The proposed area for Area Injection Operations is the Polaris Participating Area outline shown in Exhibit 1-2. This section addresses the specific requirements of 20 AAC 25.402(c). Plat of Project Area 20 AAC 25.402(c)(1) Exhibit 1-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Polaris Pool, as of June 1, 2002. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or applicable successor regulation. Operators/Surface Owners 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) BP Exploration (Alaska) Inc. is the operator of the proposed Polaris Participating Area. Exhibit VI-l is an affidavit showing that the Operators and Surface Owners within a one- quarter mile radius of the area and within the proposed Polaris Participating Area have been provided a copy of this application for injection. Description of Operation 20 AAC 25.402(c)(4) Development plans for the Polaris Pool are described in Section II of this application. Drill pad facilities and operations are described in Section III. Geologic Information 20 AAC 25.402(c)(6) The geology of the Polaris Pool is described in Section I of this application. 47/60 Polaris Pool Rules and Area Injectiol,-Jer Application .--- September 12, 2002 Injection Well Casing Information 20 AAC 25.402(c)(8) Three wells, S-104i, S-215i, and W-212i, were pennitted and drilled for injection service for the Polaris Poo1. The casing programs for these wells were pennitted and completed in accordance with 20 AAC 25.030. The completion diagram in Exhibit IV-3 is representative of a typical Polaris injection wel1. Exhibit IV -4 demonstrates a typical Polaris-Aurora commingled injector. A cement bond log has been run on S-104i and demonstrates isolation of injected fluids to the Kuparuk River and Schrader Bluff Formations. The S-104i well was completed in accordance with 20 AAC 25.412. Cement bond logs will be obtained on S-215i and W- 212i to demonstrate zonal isolation prior to water injection. 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 permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for newly drilled injection wells. All drilling and production operations will follow approved operating practices regarding the presence of H2S in accordance with 20 AAC 25.065. Conversion of wells from production service to injection service will be in accordance with 20 AAC 25.412. Injection Fluids 20 AAC 25.402(c)(9) Type of Fluid/Source Fluids requested for injection for the Polaris Oil Pool are: a. Produced water from Polaris or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; b. Tracer survey fluid to monitor reservoir performance; c. Fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); d. Source water from the Seawater Treatment Plant; e. Prudhoe Bay miscible gas from the PBU MI distribution system in one S Pad 48/60 Polaris Pool Rules and Area Lon Order Application September 12, 2002 injector and two W Pad injectors for a period of two years for the purpose of testing MI injectivity and post-MI water injectivity (Polaris EOR Pilot). The pilot is requested for two years with the pilot time-period starting when water injection is initiated in the individual wells. The AOGCC will be notified of the pilot wells prior to commencing MI injection. The initial plan is to use produced water from GC-2 as the primary water source for Polaris injection. No compatibility issues between source water and injection zones of interest have been identified. Composition The injection water composition in the Polaris Pool, based on water analysis from the W- 200 well, GC-2 produced water, and sea water, are provided in Exhibit VI-2. The composition of Polaris produced water will be a mixture of connate water and injection water, and these will change over time depending on the rate and composition of injection water. The composition of Prudhoe Bay miscible gas is provided in Exhibit VI-3. Mechanical Integrity of Wells 20 AAC 25.402(c)(l5) Mechanical Integrity of Wells Within 1,4 mile of In.iectors Three injection wells have been drilled S-104i, S-215i, and W-212i. Two injection wells W -207i and S-200i may be drilled in the near future. A map showing all penetrations through the Schrader Bluff Polaris Pool, and wells within 1,4 mile of the injection wells are shown as Exhibit VI -4. The wells within the 1,4 mile radius are, W -15, W -17, K241112, S-03, S-24A, S-31A and S-200PBl. A report of the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of a proposed injection well is included as Exhibit VI-5 to VI-II. 49/60 Polaris Pool Rules and Area Injection'--.ser Application ~ September 12, 2002 Maximum Injected Rate Maximum fluid injection requirements at the Polaris Pool are estimated at 20,000 to 25,000 BWPD. Injection Pressures 20 AAC 25.402(c)(10) The expected average surface water injection pressure for the project is 2300 psig. The estimated maximum surface injection pressure is 2800 psig. The resulting bottom hole pressure will be limited by hydraulic pressure losses in the well tubing, with a maximum expected bottom hole pressure of 5100 psig. Fracture Information 20 AAC 25.402(c)(11) The expected maximum injection pressure for Polaris Pool injection wells will not propagate fractures through the confining strata, which would allow fluids to enter any freshwatèr strata. Each Schrader Bluff 0, N, and M sand is separated from the adjacent overlying and underlying sand by 10 to 75 foot thick non-reservoir silty mudstones which provide effective fluid isolation between adjacent sands as shown by regional fluid level data (e.g., Exhibit 1-4). In several production wells (e.g. S-200 and W-200) the 0 and N inter-sand mudstones have been stimulated with propped hydraulic fracture treatments designed to connect adjacent sands. The minimum stress during the propped fracture treatments has been measured in the 0 and N sands by performing data fracs, which were analyzed to determine closure pressure. The average frac gradient in the sands is 0.61 psi/ft with a range from 0.59 to 0.62 psi/ft. A stress test was performed in Polaris well S-213 to determine the frac gradient of the basal mudstone in the OBa at 6020 feet MD (5067 feet TVDSS). This non-reservoir silty mudstone is typical of Polaris 0, N, and M interval mudstones by virtue of the 95 API units on the GR log versus 35-45 API units for the clean sandstone. The results of the S-213 stress test indicated a frac gradient in the mudstone of 0.66 psi/ft. This would yield a stress contrast of 5100 feet TVDSS x (0.66 - 0.61 psi/ft ) =255 psi 50/60 Polaris Pool Rules and Area I .on Order Application September 12, 2002 between the sandstone and mudstone layers. The average net pressure during the fracture treatments is 189 psi. The treating pressure during these propped fracture treatments exceeds the available produced water injection pressure, therefore, it is unlikely that a net pressure will be reached through injection that will cause a fracture to grow above the mudstone barriers. The stress contrast estimate was confirmed by an analysis of the rock properties in well 5-200 from data obtained by running a Dipole Sonic Log. The analysis shows a 300psi stress contrast between the sandstone and mudstone, which reasonably matches the contrast shown in the 5-213 stress test. The observed mudstone properties appear to be similar through out the Polaris Pool area, both laterally and vertically, therefore, it is apparent that multiple barriers are present which will provide containment within the Pool. To ensure injection conformance, injection performance will be monitored for each injection well. Any significant change in injectivity, which would indicate injection out of zone will be followed up with surveillance. The surveillance could include spinner/temperature logs and if necessary, a tracer survey to determine the location of the injection anomaly. Freshwater Strata Aquifer Exemption Order #1, dated July 11, 1986, exempts all portions of the aquifers beneath the Western Operating area of the Prudhoe Bay Unit, including the area designated under the Polaris Area Injection Order. Hvdrocarbon Recoverv 20 AAC 25.402(c)(14) Polaris Pool original oil in place is discussed in Section II. Reservoir simulation studies, also discussed in Section II, indicate incremental recovery from waterflooding to be approximately 10-20% of the original oil in place, relative to primary depletion. 51/60 Polaris Pool Rules and Area Injection-....er Applicaúon '-'" September 12, 2002 VII. Proposed Polaris Pool Rules BP Exploration (Alaska) Inc., in its capacity as Polaris Operator and Unit Operator, respectfully requests that the Commission adopt the following Pool Rules for the Polaris Oil Pool: Rule 1: Field and Pool Name The field is the Prudhoe Bay Field and the pool is the Polaris Pool. The Polaris Pool is classified as an Oil Pool. Rule 2: Pool Definition The Polaris Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 5393 feet MD and 6012 feet MD in the PBU S-200PB 1 well (-4651 and -5269 feet TVDSS, respectively), within the area described below. Affected Area (Umiat Meridian): Township Range Lease Sections TI2N-RI2E ADL 28256 Sec ADL 47448 Sec ADL 28257 Sec ADL 28258 Sec TI2N-RI3E ADL 28279 Sec TI1N-RI3E ADL 28282 Sec TI1N-RI2E ADL 28260 Sec ADL 28261 Sec 22 S/2 S/2 and NE/4 SE/4 23 S/2 NW/4 and SW/4 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26, 35, 36 27,33 SE/4 SE/4, 34 E/2 W/2 and SW/4 SW/4 and E/2 31 SW/4 NW/4 and SW/4 6 W 12 and SE/4 and S/2 NE/4 and NW 14 NE/4, 7 N/2 and N/2 SW 14 and SE/4 SW 14 and SE/4, 8 W/2 SW/4 1,2, 11 W/2 and NW/4 NE/4, 12 N/2 N/2 and SE/4 NE/4 3, 4 E/2 E/2, 9 NE/4 NE/4 and S/2 NE/4 and SE/4, 10 ADL28263-1 Sec 15, 16E/2 ADL 28263-2 Sec 21 NE/4 NW/4 and NE/4 SE/4 and NE/4, 22 N/2 and N/2 SW 14 and SE/4 SW 14 and SE/4 52/60 Polaris Pool Rules and Area II,. .on Order Application September 12, 2002 ADL 47451 Sec 14 W/2 and W/2 SE/4, 23 W/2 and W/2 E/2 and SE/4 SE/4 and SE/4 NE/4 ADL 28264 Sec 26 N/2 N/2 ADL 47452 Sec 27 NE/4 NE/4 Rule 3: Well Spacing To allow for close proximity of wells in separate fault blocks, spacing within the pool will be a minimum of 20 acres. The pool shall not be opened in any well closer to 500 feet to an external boundary where ownership changes. Rule 4: Casing and Cementing Practices (a) In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75 feet below the surface. (b) In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500' TVD below the base of the permafrost. Rule 5: Automatic Shut-in Equipment (a) All wells must be equipped with a fail-safe automatic surface safety valve system capable of detecting and preventing an uncontrolled flow. (b) All wells must be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a down hole flow control device. (c) Subsurface safety valves (SSSV) must be installed on gas or miscible (MI) injection wells when in service. (d) Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the SSV system, SSSV system, and associated equipment are in proper working condition. Rule 6: Common Production Facilities and Surface Commingling (a) Production from the Polaris Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. (b) The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 is conditionally approved for one year beginning August 1, 2002. (c) All wells must be tested a minimum of once per month. All new Polaris wells must be tested a minimum of two times per month during the first three months of production. 53/60 Polaris Pool Rules and Area Injection-.-der Application '-- September 12, 2002 ~ (d) The operator shall submit a montWy report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. (e) Commission approval of the Prudhoe Bay Unit Western Operating Metering Plan will expire on August 31, 2003. Continued authorization of metering and allocation procedures will be determined no later than July 31, 2003. Rule 7: Reservoir Pressure Monitoring (a) Prior to regular production or injection, an initial pressure survey must be taken in each well. (b) A minimum of one pressure survey will be taken annually in each of the six Polaris reservoir compartments where Polaris production wells exist. A minimum of two pressure surveys will be taken annually in the S/M Pad North and the W PadffW-C reservoir polygons when two or more production wells have been completed in each of these polygons. (c) The reservoir pressure datum will be 5000' feet true vertical depth subsea. (d) Pressure surveys may consist of stabilized static pressure measurements (bottom-hole or extrapolated from surface), pressure fall-off tests, pressure build-up tests, multi- rate tests, drill stem tests, and open-hole formation tests. (e) Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request. (f) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. Rule 8: Gas-Oil Ratio Exemption Wells producing from the Polaris Pool are exempt from the gas-oil ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240(b) are met. Rule 9: Pressure Maintenance Project Water injection for pressure maintenance will commence before reservoir pressure drops below 1633 psi at the datum depth of 5000' or by May 1,2003, whichever occurs first. Rule 10: Multiple Completion of Water Injection Wells (a) Water injectors may be completed to allow for injection in multiple pools within the same wellbore so long as there is mechanical isolation between pools. (b) Prior to initiation of commingled injection, the Commission must approve methods for allocation of injection to the separate pools. 54/60 Polaris Pool Rules and Area: ;on Order Application September 12, 2002 (c) Results of logs or surveys used for determining the allocation of water injection must be supplied in the yearly reservoir surveillance report. Rule 11: Reservoir Surveillance Report An annual reservoir surveillance report for the prior calendar year must be filed by April 1st: (a) Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation techniques. (b) Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval. (c) Summary and analysis of reservoir pressure surveys within the pool. (d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. (e) Review of pool production allocation factors and issues over the prior year. Cf) Future development plans Cg) Review of annual Plan of Operations and Development. Rule 12: Administrative Action Upon proper application, 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 fresh water. 55/60 Polaris Pool Rules and Area lnjectior,-",er Application -- September 12, 2002 VIII. Proposed Area Injection Order L:~ BP Exploration (Alaska) Inc., in its capacity as Polaris Operator and Unit Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Polaris Pool and consider the following rules to govern such activity: Affected Area: Township Range Lease Sections TI2N-R12E ADL 28256 See 22 S/2 S/2 and NE/4 SE/4 ADL 47448 See 23 S/2 NW/4 and SW/4 ADL 28257 See 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26, 35, 36 ADL 28258 See 27,33 SE/4 SE/4, 34 E/2 W/2 and SW/4 SW/4 and E/2 T12N-R13E ADL 28279 See 31 SW/4 NW/4 and SW/4 T11N-R13E ADL 28282 See 6 W 12 and SE/4 and S/2 NE/4 and NW 14 NE/4, 7 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4, 8 W/2 SW/4 T11N-R12E ADL 28260 See 1, 2, 11 W 12 and NW 14 NE/4, 12 N/2 N/2 and SE/4 NE/4 ADL 28261 See 3,4 E/2 E/2, 9 NE/4 NE/4 and S/2 NE/4 and SE/4, 10 ADL 28263-1 See 15, 16 E/2 ADL 28263-2 See 21 NE/4 NW 14 and NE/4 SE/4 and NE/4, 22 N/2 and N/2 SW 14 and SE/4 SW 14 and SE/4 ADL47451 See 14 W 12 and W 12 SE/4, 23 W 12 and W 12 E/2 and SE/4 SE/4 and SE/4 NE/4 ADL 28264 See 26 N/2 N/2 ADL 47452 See 27 NE/4 NE/4 56/60 Polaris Pool Rules and Area IT 1n Order Application September 12, 2002 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to, and correlate with, the interval between the measured depths of 5393 and 6012 feet in the PBU S-200PB1 well (-4651 and -5269 feet TVDSS, respectively). Rule 2: Authorized Injection Fluids Fluids authorized for injection within the affected area are: (a) Produced water from Polaris or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; (b) Tracer survey fluid to monitor reservoir performance; (c) Source water from the Seawater Treatment Plant; (d) Prudhoe Bay miscible gas from the PBU MI distribution system in one S Pad injector and two W Pad injectors for a period of two years for the purpose of testing MI injectivity and post-MI water injectivity (Polaris EOR Pilot). The pilot is requested for two years with the pilot time-period starting when water injection is initiated in the individual wells. The AOGCC will be notified of the pilot wells prior to commencing MI injection. Rule 3: Fluid Injection Wells The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412. The application to drill or convert a well for injection must be accompanied by sufficient information to verify the mechanical condition of wells within one-quarter mile radius. The information must include cementing records, cement quality log or formation integrity test records. Rule 4: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to confirm continued mechanical integrity. Rule 5: Demonstration of Tubing/Casing Annulus Mechanical Integrity 57/60 Polaris Pool Rules and Area Injectioò-,er Application '--, September 12, 2002 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 6: Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 2 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. Rule 7: Administrative Action Upon proper application, 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 an increased risk of fluid movement into a fresh water source. 58/60 Polaris Pool Rules and Area I on Order Application September 12, 2002 IX. List of Exhibits I-I Location of the Polaris Pool Alaska North Slope 1-2 Polaris Pool and Proposed Polaris Participating Area Outline Map 1-3 Polaris Pool Area Top Schrader Bluff OA Structure Map 1-4 Polaris Pool Area Structural Cross Section A - A' 1-5 Polaris Pool Type Log S-200PB 1 1-6. Polaris Pool Area Lower Mb2 Mudstone Isopach Thickness Map 1-7 Polaris Pool Area Nand 0 Sand Reservoir Compartment Map 1-8 Polaris Pool Sand M Pad Area Interpreted OillW ater Contacts Cross Section B -B' 1-9 Polaris Pool W Pad Area Interpreted OillWater Contacts Cross Section C-C'. 1-10 Polaris Pool Area Schrader Bluff 0 Sand Composite Net Pay Thickness Map 1-11 Polaris Pool Area Schrader Bluff N Sand Composite Net Pay Thickness Map 1-12 Polaris Pool Area Lower Ugnu M Sand Composite Net Pay Thickness Map 1-13 Polaris Pool Area Schrader Bluff 0 Sands Composite Oil Pore Foot Thickness Map 1-14 Polaris Pool Area Schrader BluffN Sands Composite Oil Pore Foot Thickness Map 1-15 Polaris Pool Area Lower Ugnu M Sands Composite Oil Pore Foot Thickness Map II-I Polaris Model Reservoir Description 59/60 Polaris Pool Rules and Area Injectiol___Jer Application ""= 11-2 11-3 11-4 11-5 11-6 Ill-l III - 2 III - 3 Ill-4 IV-I IV-2 IV-3 IV-4 '- '-' September 12, 2002 Polaris Relative Permeability Plot Polaris Fluid Properties Polaris Model PVT Properties Polaris Waterftood Rate Forecast Polaris PVT Match Using MPU Schrader Bluff EOS Polaris Well Tie-ins -Northern S Pad Polaris S Pad Development - Surface Facilities Polaris M Pad Development - Surface Facilities Polaris W Pad Development - Surface Facilities Polaris Well Test Summary Typical Polaris Production Well Bore Schematic Typical Polaris Injection Well Bore Schematic Typical Polaris-Aurora Commingled Injector Well Bore Schematic VI-l Affidavit VI-2 Polaris Injection Water Compositions VI-3 Prudhoe Bay Miscible Gas Properties VI-4 Polaris Pool/Injection Area VI-5 W -15 Well Integrity Report VI-6 W -17 Well Integrity Report VI-7 K241112 Well Integrity Report VI-8 S-03 Well Integrity Report VI-9 S-24A Well Integrity Report VI-I0 S-3IA Well Integrity Report VI-II S-200 & S-200PBl Well Integrity Report 60/60 -.. - --... ---...... ..---- L cati n f th laska Milne Poirit U Kuparuk River Unit - -- -- --------------1 laris 01 h I pe I I North Star Unit River _ Prudhoe Bay j Unit I ~ I o 3 6 Miles . 4 \ ......... '- ......... Polaris Production Well ......- - " in a I I I I I j I I I I I I I I I I I I Po ·5 Pool/lnje io ea Top Schrader 81 ructure ap Schrader Bluff Schrader Bluff · Production Well Injection Well Schrader Bluff High Angle Production Well I I I I I I I I I I I I I I I I I I I - m è= (D ,..., c: - v A Polaris Pool/Injection pe II S-200PB1 ..-12 API (from V-200 SWC) 3 APi API APi 18 API APi APi API API APi API 23 API API API API ~ - - 30000 I 25000 20000 (!) - & 15000 ~ ,! ~ "0 C 11:I is 10000 5000 - - - -- - -- - Waterflood Polaris Production Water Polaris Water 2005 2010 .. .. .. - II Ti - i.bit 111..1 ins... North rn S-Pad N s- 4 8-216 WI Booster Pump (Future ) Gas lift Water .. .. Production Trunk Gas Lift Trmk Test Water Injection Trunk MI (#) re . III M Pad I .. 10 t . 11 , ~ ~ i ". j' '\ 16 18 15~' ~=IIII 19 20 t ~ 33 21 12 t, ~=IIII 22 31 11 ~.~ ~ti 23 ~ 10 ...... 9~ I 8·-£' , , I I I I I I I I I I I I I I I I I I I I I 53n WELL WELL INJECTOR .. DATE: 09/18/2001 - M SCALE: 1" "" 250' A are weil M Pad IIIIIIIIIIIIIII b$14495.dgn (" . " ./ _ Polaris Future Scope NOTES: I:::. ~ ~ NO HEAD CELLAR ONLY -- NO * SUBSIDENCE WELL j '" SUMP N '\... r -~-~----~-~~-~~~-~- EXHIBIT IV-1. POLARIS REPRESENTATIVE WELL TEST SUMMARY Oil Flow Rate Watereut Gor Tubina Tubina Well Test Date BPD Pet sef/bbl oil Gas Lift Rate Temp Pressure S-200* 10/23/2001 409 0 584 . 1,330 39 304 8-201 ** 8/22/2002 252 26 690 0 112 306 e S-213** 8/23/2002 276 10 865 0 107 305 8-216** 7/4/2002 362 8 393 0 110 293 W-200 8/15/2002 609 3 1,190 1,540 55 287 W-201 8/27/2002 610 18 641 1,560 52 284 W -203*** 8/27/2002 1548 7 1428 3460 69 298 W-211 8/19/2002 315 61 1323 2990 62 313 * Shut-in ** On Jet Pump *** Multi-lateral Well e I I I I I, t I I I I, I, I I I I I I I I TREE = 4" 5000 psi 19-5/8" CSG, 40#, L-80-BTC, 10 = 8.835" I Mnirnrn ID = 2.813" 3-1/2' X NIPPLE 13-1/2" lBG, 9.3# L·80 .0087 bpf , 10 = 2.992" I 17" CSG, 26#, L-80 MOD-BTC, 10 = 6.276" I e Exhibit IV-2. l ) j L - . ..l......LL g " l!III!IIII4 ~ z.. e 4-1/2" X 3-1/2" XO NP. 10 = 2.992"1 3-1/2" XNP,ID=2.813" I I GAS LIFT MANDRELS I I Sliding Sleeve 3-1/2" X NP,ID = 2.813"1 7" X 4-1/2" A<R,ID = 3.875" 3-1/2" liES X NP,ID = 2.813" 3-1/2" HES X NP,ID = 2.813" WLEG 20'SHORTJOINT& RA TAG I 20'SHORTJOINT& RA TAG I PRUDHOE BAY UNIT / ffiLARIS FIB.D Typical Production Well BP Exploration (Alas ka) I· I I I I I I I I I I I I I I I I I I TREE = 4" 5000 psi 19-5/8" CSG, 40#, L-80-BTC, ID = 8.835" I Mnim.rn ID 3.725" 4-112" XN-Nipple 13-1/2" 1BG,9.3# L-SO .00S7 bpf , ID = 2.992" I 7"CSG, 26#,L-SO MOD-BTC,ID= 6.276" I e Exhibit IV-3. .. . :8: z.. " ifJ!IJffÅ e I 4-1/2" X NP,ID = 3.S13" I 4-112" X NP,ID = 3.S13"I 7" X 4-1/2" PKR,ID = 3.93S" 4-1/2" X NP,ID = 3.S13" 4-1/2" XN NIP ,ID = 3.S13" WLEG 20'SHORTJOINT& RA TAG I 20'SHORTJOINT& RA TAG I PRUDHOE BAY UNIT / FOLARIS FIB.D Typical Polaris Injection Well BP Exploration (Alas ka) I e e I Exhibit IV-4. TREE: 4-1/16" - 5M CIW Carbon WELLHEAD: 11" - 5M FMC G5 I I I I 4-1/2" 'X' Landing Nipple with 3.813" seal bore. ~ 9-5/8",40 #/ft, L-80, BTC - ~ I I I t I 1900-4000' TVDss L L '~ 4-1/2" 'X' Landing Nipple 3.813" 10 J . ~ 4-112" 12.6# L-80, Premium Connection Tubing 7" x 4-1/2" Baker "Premium" ~ " Production Packer I I 3-1/2" MMGW Water Flood GLM ---!:: with Injection Valve w/ Pram threads ~ - L -/ 3-1/2" N5CT 9.3 # L-80 Tubing between MMGW GLM's I I I ,r 3-1/2" 'X' Landing Nipple 2.813"10 7" x 4-1/2" Baker "5-3" Packer 3-1/2" 'X' Landing Nipple 2.813" 10 3-1/2" 'X' Landing Nipple 2.813" 10 3-1/2" WireLine Entry Guide Plug Back Depth I I 7",26 #/1t, L-80, BTC-Mod I PRUDHOE BAY UNIT/ POLARIS FIELD Typical Polaris-Aurora Commingled Injector API NO: 50-029-xxxx I BP Exploration (Alaska) I I I I I' I I I I I I I I I I I I I I e e Exhibit VI-t. AFFIDA VIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Gilbert G. Beuhler, declare and affirm as follows: 1. I am the Greater Prudhoe Bay Satellites Manager for BP Exploration (Alaska) Inc., the designated operator of the proposed Polaris Participating Area, and as such have responsibility for Polaris operations. 2. On -:;;<./"f" II.- ~oò),... I caused copies of the Polaris Pool Rules and Area Injection Order Application to be provided to the following surface owners and operators of all land within a quarter mile radius of the proposed injection area: Operators: BP EXPLORATION (ALASKA), INe. A TIENTION: NEIL MCCLEARY P.O. BOX 196612 ANCHORAGE, AK 99519-6612 Surface Owners: STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES ATIENTION: DR. MARK MYERS 550 WEST 7TH AVENUE, SUITE 800 ANCHORAGE, AK 99501-3510 Dated: ::;;~..), / /.) :J.... 0 0 ~ ~~ Gilbert G. Beuhler Declared and affirmed before me this ~ day of (') ~()-I- L"'^ b,u- 2- oQ2- ~~ V ~Á- C-. '---L^'-À CÂo{ ~ð 0s'J- Notary Public in and for Alaska My commission expires: _ PATRICIA lUOOI~GTO.N. My Commission Expires 7/19/04 ----~~~--~~-~~-~-~- Exhibit VI-2: Polaris Injection Water Compositions W-200 GC2 Source, ppm Formation Water Produced Water Sea Water ,......:... ......,' ...c.....- ,,- ,,:-, .-: .. '->:." .... .:',: ":",d'< . Bati Ur11 Bicarbonate Calcium· . Chloride Iron' Magnesium pH. ..... Potassiym . Sodium Stronti urn Sulfate TDS e ¡ , . 16.9 ! 2. 17 ¡ 0 ¡ -,..~"',""---'"'~--'-~'~"'~-"" '"'..__.~....~_.~>........ ._........'"....._~.__..._.."..,,,_.__.._-<~..,.._. _.._~~<.<.._...,.... .~....__.__......¡ 4640 ¡ 1640 ¡ 140 ¡ C".,_~,._....._.~.,""">' ~ ;'''''-'' ......c··.,.....~i"O'"....""""""....n,..'........<'..,....~.., .-,-.=.~..; 'H'_""'.,.",·.,· ... -.. ~~.~J........,..".cr.""""'''"_' ,..."'.'. .,'.' '" ''''' ..,...~-......"..-"....,-""'~'..... '-.......-.<~-'"""'_,'" ...,....._~,._-.- -4...........-..- -".""",......., _.."",,,,,,,,,~~..,,,,,."'._-,,--,, ,-,. "",-_ ........._.n...,--...-.,... <J 55 ! 247 i 407 ; , ¡ ':~~..'~<.~"'~..:'. ~.j~~~~~~'.".'.' .....~<~.>~~"'......j..~~~...<......_._..__.....~_~.~g~..,...... _.,.., ........ .< ..... ....~..~!!9.·.·..~_~_ ~~.~.~ <0.02 ¡ 4.32 ¡ '.""~' "'..."m'·'_··~··-"'~1"Ô9·-~-"""·····"·-·_·_·'T",¡" ..".~"" ....- ·'..·"'1"56·..··..·..··..· ..... .'.<0 ·..·-..·1· 2'9()" ............... ",". .~ -___,~.. ...;.,..,~-'.~ .c". "',_4 ~ , .,...,..... "",,.~,' w'.,..._·...~."., ¢."".' ;u....~ _,..,..",. 8 6.9 i '.':-.w"·</·...,, .~....'-'....,;;'¡O" ... ,~.._....""';Q>,..,~,.<_,=O"..""" ':'''1 , ..":"'~ ;;;~:.:. ...-.'.~'.,..".1:U",,:N,.,'+,'_.'. ··'''-''',,..,,S'' .·'.0·',....'._._-,,;--..."". ,',,;~:ÿ)-: .,....."...:...,.~~ '_.."':."""'¡¡'-::-':', .~. O.":;:'';::.\'.L'''''''-''':'~';;';.. 271 107 ¡ , ~~.__.;.;u'-"".._.,.-..'';''-''¡-'¡' '''-''-...::..c.. , .. nW;Ô\ .:,.;_~..~...:-:,. .'."~' '", .... I Æ ';',¡' .. .~.) ..=;.;¡." ..,....',. ...~""- ',:...~ -, "._N· .;. ',;>- ...._.,._.. -~'. "".';' '.' ·.-··-x..... :"";,J'-..~..."':>-,;.....;..:..,'...." 7221 8080 8400 ", ,"""',", <...-,~ ...... '.=....,..<~ _ "A"""-"""""'" ",<.",,>oJ<o'~ "-.,..... ".' ""'·..L..,......·y"'~." ~.Ã"'''''' "'.. ",.,.,^","" - ..~. ~"~..,,..., .-;^ ,~_ .~", ~_...,..'~' ~'" >. .'.~_' ''-'".' ,,,. 10.3 26.2 5 ........ ,...~-o........",.-. "- _"~.""''''._~_ ~_",-"",·.·_~~",-,__",.~,."...._C~_...-"...-. .c-.'y..·.· .""'..""~.",. ......_,... ""'-" -__·""H·""~.......·_.,..,.".......·_-.,- ·d....." '\.' __.~'" 479 560 2670 26322 23427 28687 e -~~~--~-~-~---~~-~- Exhibit VI-3: Prudhoe Bay Miscible Gas Properties C t M I Wt Prudhoe Bay MI omponen 0 Mole 0/0 C02 C1 C2 C3 nC4 nCS·· C6 . C7-9· C10-13 C14~19 C20-35 C36+ Mol Wt 44.01 18.8 - 19.3 ."~ _ ~'·¥___""_'N._~._·._____.._.··..".. .__..." '__.~.~_.__"'. ";,-",,__,_,~_,_,, .._~.~ ".__"...__. .... 16.04 34.5 - 36.6 . _.. "- ,_ ....___'.__.~'_.,_.._. ..~.... __,"."_ ,,,,,_,_, _,.,,' . _._'..~...,..~/..._... _.~ ~__r_."_~·_..._ ~_.,.__ ...~_._._...~_ _ ._...~ ~__. 30.07 18.9 - 19.6 __"._' J. .~_ __.,.'...........r. _,....'._ _ _ . ...~ " _. ..~ ,_.~ ___ '~. '. _..... _..._~~".__._". .. "__".' .M. .~._._..~.._~. _. ." __',_','__ . .... .,.-_.~_ 44.1 20.1 - 23.7 .- '-","~ _..þ-......-..-.......~..--.....". .-,. '-"..- .~----.~.'-.. ..._,....,---_.,--..~~ .--_.,~. ~.._,._-- _. - "_.~'-'" .->.." 58.12 1.9-5.4 ",_,~~--._.~.._.,_....~.".......,...._,,, ·'-··F._._·_ ".,.~_ ,. ',.,,,' ...._~, ~...,.,~ "..~_.. ~..__._.._.._._. ".___._~__ "",__ '--".' .'..____ ....._ 72.15 .01 - .09 ~ ... '·'U~'__~·"_.' .'_'-"'..",_F'-'_~ ,,_, Fh~ ".,,_,.,-._ ~". ..... ,..¥_~___".._.".....~__._... ,0..·..·"_·...·. .-,..." 84 0.0 - 0.001 '_.._." .,_, ..__w_",.._~_~..4._ _."........... ,. ____~ ,..... ~·_..~._F_."4 .._.. .._._,,_...._.....-.....___ . __ ~. .~.h_.._.."._. ._., 108.9 0.0 - 0.001 ~. ,..~"..-.~-_. ..._-_..'._~._-_..-..... '-" .'-~~"._.__... ,...., .~ ". . .' ..~-'.~~,_.. --... ~.. --.- ~-..' -,-~-.......~-.~ '.- .. ....-...." ..._- ".'..' ~-' 153.26 0.0 ._ ~ _. .'A'.'~ '_'___"~'-" '_.4P_ '.__~~_., .'_'~' ....' "~.~._"_.._~. ._......'.'.,,_.,,__ ~..~ _ ....~......._. ........' "..~ _,~.. '._. _.__ ._ ,.._,,~_ ...A 223.51 0.0 , ... .. ~,.., '.' _._...,~ ....,_..._". _.6'''_' - .....~ ,. . ._ ", ~__.." ___"'~'''_''. ..,_ __".___,.,.~ '.. ~_ ." ... '_~~'.__'.'...__"' . . 373.52 0.0 u...._·_~~....._.'~._.·__·~~_,n_,_ ,·_._.,~.·____·v_... .....~._ "".' .--._.......,...-..._. ~~,..~_...~~ ....._,_.~.~, _" .~.'_~-" 0__ . ._,~'.._..._ 722 0 31.9-32.1 e e · "" ............. 20 " 30 4 3\ \ 13 19 ......... '- """'" "' Polaris Production Well OA in a non-Polaris -~----~--~---~-~--- Exhibit VI-5: W-15 Well Integrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: Schrader Bluff Penetration Casing Diameter: Well Status as of 9/2002: Cement Logs Across Schrader Bluff: 7/14/90 12-114" 9-5/8" e SI-CTD Sidetrack None Comments: Cement returns to surface were noted during the 13-3/8" primary cement The 13-3/8" casing was tested to 3000 psi. The 9-5/8" primary cement job was designed to cover the U gnu sands. The 9-5/8" casing was pressure tested at 2500 psi. At the time of this writing W -15 is being sidetracked with coiled tubing in the 9-5/8" casing with a window cut at 11822'md. Additional Information: Exhibit VI-5a Exhibit VI-5b Exhibit VI-5c Well Diagram Directional Survey Significant Drilling Daily Reports & Cement Program e I e TREE = I WB.LI..EAD = . ACTUATOR';' KB. ELEV ;. BF. ELBt = I KOP= Max Angle = Datum MD = Datum TV D= 4-1/16" C1-JV FMC . OTIS 90.64' 54.24' 3193' 90 @ 12700' 11692' 8BOO'SS I I I I I I I I I I I I I I I I 13-318" CSG, 72#, L-BO, ID = 12.347" H 2650' r--- I Minimum ID = 3.813" @ 2085' 4-1/2" OTIS SSSV NIPPLE 19-518" CSG, 47#, L-BO, NSœ, ID=8.681" H 11630' f--A TOP OF 1lW TlEBAO< SLEEVE,ID = 5.25" H 1183T I 17" X 4-1/2" 1lW S-6 PKR, D = 3.863" H 11844' I I7"X 4-1/2" HN HYDROHGR,ID=3.863" H 11851' I IT' LNR. 26#, L..80, ID = 6.276" H 11974' I ... ÆRFORA 1l0N SLMIIAA. RY REF LOG: TIE N LOGISONAIRWD ON 07/07/90 ANGLE AT TOPÆRF: 67 @ 11810' Note: Refer to Production æ for historical perf data SIZE SA" NTffiVAL Opn/Sqz DATE 2-7/8" 6 11810-11840 0 05/03198 2-7/8" 6 11868 - 11974 0 05/03198 2-3/4" 6 12420 - 12440 0 7/2/1993 2-3/4" 6 12540 - 12560 0 7/2/1993 2-3/4" 6 12680 - 12700 0 7/2/1993 Exhibit VI - Sa W-15 . L :8: ~ l ï t···" ,~ ~ I I e SAFETY NOTES: W8.L ANGLE> 70· @ 11848' & > 90" @ 12148'. "HORIZONTAL W8.L* 2085' H 4-1/2" OTIS HXO SSSV NP. ID = 3.813" I ST MD 5 2985 4 6279 3 9304 2 10988 1 11215 GAS LFT IlAA.NDRELS lV D DEV TYPE V LV LATCH PORT ()\ lE 2894 3 OllS DMY RA 0 07l19¡Q2 5429 52 OTIS DMY RA 0 07/19102 7198 47 OllS DMY RA 0 07/19102 8375 49 OTIS DMY RA 0 07/19102 8521 51 OTIS DMY RA 0 07/19102 11244' H4-112"PA~ERSWSf\lP,ID=3.813" I 11251' H9-5/8" X 4-1/2" OTIS I-CMPKR, ID=3.850" I 11275' H4-112" PA~ERSWS f\lP,ID =3.813" I I 11336' H 9-5/8" X 7" TIW LI'R I-GR / TIEBACK SL V ~ i 11822' HWHPSTOO< (08/18/02) J I 11838' H4-112" llW SEAL ASSY w/o SEALS I I 11846' H ELMDTTLOG NOT AVAILABLE I 1185T H COIvPOSrrE BRIDGE PlUG (08/17/02) I 12019' H4-1/2" OTIS XD SLIDING SLV, ID = 3.813" I H4-1/2" OTS XD SLIDNG SLV, ID = 3.813" 12370' H CTC 8<T CSG PKR I 12411' H4-1/2"OTSXDSLIDNGSLV, ID=3.813" I 12712' H4-1/Z' OTIS XD SLIDING SLV, ID = 3.813" I 12732' H CTC EXT COO PKR I 12773' H4-1/Z' OllS XD SLIDING SLV, ID =3.813" I 14-1/2" LNR, 12.6#, L-80, .0152 bpf, ID = 3.958" H 13165' ()\ TE REV BY CONMENTS 07/14/90 IXF ORGINALCOIvPLETION 02109/01 SIS-QAA corw ERTED TO CA rw AS 03105/01 SIS-LG FINAL 04105/02 RNICHITP CORRECTIONS 07/19/02 Jßltlh GLV UFÐATE 13134' H4-1/2" OTS XD SLIDNG SLV, ID= 3.813" I 13144' H3" BKRIBP-08l29J90 I ()\ lE REV BY COMM::NTS 08118102 JLJ/KK SEr WHIPSTOCK & ŒP PRLDI-OE BA Y UfIIT WB.L: W-15 ÆRMrr No: 190-0530 AA No: 50-029-22042-00 SEC 21, T11 N, R12E, 836' FI'I.. & 1184' FEL BP Exploration (Alaska) 'weli W-15 Directional Surv_ Exhibit VI -e> Iwell: l~:~~ 11- ...,...,..¥...."".... ~ " ' ,>,,~~:è~~~~ : I ...-............................ ...............................................................-... . ............_........._............_.~....... API/UWI: 500292204200 Survey Type: COMP I Company: Bp Exploration (Alaska) Survey Date: I Survey Top: 0' MD Survey Btm: 13,166' MD I MD TVD SS INCLINE AZIMUTH DOGLEG ASP_X ASP_Y 0 0.00 90.64 0.00 0.00 0.0 612,048.6 5,959,421.2 40 40.00 50.64 0.22 116.07 0.0 612,048.8 5,959,421.2 I 41 41.00 49.64 0.22 120.31 1.6 612,048.8 5,959,421.2 48 48.00 42.64 0.15 126.42 1.0 612,048.8 5,959,421.2 60 59.80 30.84 0.10 127.60 0.4 612,048.8 5,959,421.2 I 72 71.60 19.04 0.12 122.85 0.2 612,048.8 5,959,421.2 83 83.40 7.24 0.13 117.54 0.1 612,048.8 5,959,421.2 95 95.10 -4.46 0.13 116.21 0.0 612,048.8 5,959,421.2 109 108.50 -17.86 0.12 118.42 0.1 612,048.9 5,959,421.2 I 122 122.45 -31.81 0.12 117.92 0.0 612,048.9 5,959,421.2 136 136.40 -45.76 0.10 116.60 0.1 612,048.9 5,959,421.2 150 150.35 -59.71 0.10 112.13 0.1 612,048.9 5,959,421.2 164 164.30 -73.66 0.10 101.66 0.1 612,048.9 5,959,421.2 I 178 178.30 -87.66 0.10 92.19 0.1 612,049.0 5,959,421.2 192 192.30 -101.66 0.08 81.35 0.2 612,049.0 5,959,421.2 206 206.35 -115.71 0.05 63.53 0.3 612,049.0 5,959,421.2 222 221.65 -131.01 0.02 335.38 0.4 612,049.0 5,959,421.2 I 238 237.85 -147.21 0.05 233.02 0.4 612,049.0 5,959,421.2 254 253.95 -163.31 0.12 201.61 0.5 612,049.0 5,959,421.2 270 270.15 ":179.51 0.17 176.85 0.5 612,049.0 5,959,420.8 I 286 286.35 -195.71 0.20 150.38 0.6 612,049.0 5,959,420.8 303 302.55 -211.91 0.17 113.25 0.8 612,049.0 5,959,420.8 319 318.75 -228.11 0.15 65.66 0.8 612,049.0 5,959,420.8 335 334.95 -244.31 0.08 0.08 0.9 612,049.1 5,959,420.8 I 351 351.25 -260.61 0.07 251.33 0.8 612,049.1 5,959,420.8 368 367.50 -276.86 0.13 157.43 0.9 612,049.1 5,959,420.8 384 383.80 -293.16 0.17 107.08 0.8 612,049.1 5,959,420.8 400 400.05 -309.41 0.20 65.08 0.8 612,049.1 5,959,420.8 I 416 416.35 -325.71 0.18 24.30 0.8 612,049.3 5,959,420.8 433 432.60 -341.96 0.10 282.80 1.4 612,049.3 5,959,420.8 449 448.90 -358.26 0.10 155.66 1.1 612,049.1 5,959,420.8 I 465 465.10 -374.46 0.15 82.56 1.0 612,049.3 5,959,420.8 481 481.30 -390.66 0.23 65.33 0.6 612,049.3 5,959,420.8 498 497.65 -407.01 0.32 48.63 0.7 612,049.4 5,959,420.8 514 514.00 -423.36 0.25 348.60 1.8 612,049.4 5,959,421.2 I 530 530.35 -439.71 0.15 39.17 1.2 612,049.4 5,959,421.2 547 546.65 -456.01 0.23 92.75 1.1 612,049.4 5,959,421.2 563 563.00 -472.36 0.32 33.08 1.7 612,049.5 5,959,421.2 579 579.35 -488.71 0.17 294.96 2.3 612,049.5 5,959,421.2 I 596 595.70 -505.06 0.15 154.71 1.8 612,049.5 5,959,421.2 612 612.05 -521.41 0.30 53.66 2.2 612,049.5 5,959,421.2 628 628.40 -537.76 0.22 341.90 1.9 612,049.5 5,959,421.2 I 645 644.75 -554.11 0.15 18.04 0.8 612,049.5 5,959,421.2 661 661.05 -570.41 0.28 63.90 1.3 612,049.6 5,959,421.2 677 677.20 -586.56 0.30 1.24 1.9 612,049.6 5,959,421.5 693 693.30 -602.66 0.18 45.57 1.3 612,049.6 5,959,421.5 I 709 709.45 -61a.81 0.23 85.05 0.9 612,049.6 5,959,421.5 726 725.60 -634.96 0.30 19.40 1.8 612,049.7 5,959,421.5 742 741.80 -651.16 0.15 270.06 2.3 612,049.7 5,959,421.5 758 757.95 -667.31 0.18 141.49 1.8 612,049.7 5,959,421.5 I 774 774.10 -683. 2.1 612,049.7 5,959,421.5 '790 790.30 -699. ehibit VI - 5b 1.9 612~tl7 5,959,421.5 806 806.45 -715. 2.2 612, .7 5,959,421.5 823 822.60 -731.' 2.0 612,049.7 5,959,421.5 I 839 838.80 -748.16 0.32 57.27 2.0 612,049.9 5,959,421.5 855 855.00 -764.36 0.22 345.22 2.0 612,049.9 5,959,421.5 871 871.15 -780.51 0.17 35.19 1.1 612,049.9 5,959,421.5 I 887 887.35 -796.71 0.28 93.46 1.5 612,049.9 5,959,421.9 904 903.55 -812.91 0.28 30.33 1.8 612,050.0 5,959,421.9 920 919.65 -829.01 0.17 309.57 1.9 612,050.0 5,959,421.9 936 935.85 -845.21 0.17 192.77 1.8 612,050.0 5,959,421.9 I 952 952.05 -861.41 0.27 86.65 2.2 612,050.0 5,959,421.9 968 968.25 -877.61 0.23 14.81 1.8 612,050.0 5,959,421.9 984 984.35 -893.71 0.17 295.40 1.6 612,050.0 5,959,421.9 1,001 1,000.55 -909.91 0.22 212.61 1.6 612,050.0 5,959,421.9 I 1,017 1,016.70 -926.06 0.22 115.43 2.0 612,050.0 5,959,421.9 1,033 1,032.85 -942.21 0.15 21. 71 1.7 612,050.0 5,959,421.9 1,049 1,048.95 -958.31 0.17 291.10 1.4 612,050.0 5,959,421.9 I 1,065 1,065.10 -974.46 0.27 229.86 1.5 612,050.0 5,959,421.9 1,081 1,081.29 -990.65 0.35 216.54 0.7 612,049.9 5,959,421.9 1,098 1,097.49 -1,006.85 0.30 204.65 0.5 612,049.9 5,959,421.5 1,114 1,113.69 -1,023.05 0.23 216.77 0.6 612,049.9 5,959,421.5 I 1,130 1,129.89 -1,039.25 0.33 216.34 0.6 612,049.7 5,959,421.5 1,146 1,146.09 -1,055.45 0.42 192.09 1.1 612,049.7 5,959,421.5 1,162 1,162.29 -1,071.65 0.28 187.71 0.9 612,049.7 5,959,421.5 1,178 1,178.44 -1,087.80 0.30 203.64 0.5 612,049.8 5,959,421.2 I 1,195 1,194.64 -1,104.00 0.43 208.59 0.8 612,049.6 5,959,421.2 1,211 1,210.84 -1,120.20 0.37 186.99 1.0 612,049.6 5,959,421.2 1,227 1,226.99 -1,136.35 0.25 185.71 0.8 612,049.6 5,959,421.2 I 1,243 1,243.24 -1,152.60 0.33 203.36 0.7 612,049.6 5,959,420.8 1,259 1,259.44 -1,168.80 0.47 201.93 0.9 612,049.5 5,959,420.8 1,276 1,275.64 :'1,185.00 0.38 182.04 1.1 612,049.5 5,959,420.8 1,292 1,291.84 -1,201.20 0.25 159.82 1.1 612,049.5 5,959,420.4 I 1,308 1,308.04 -1,217.40 0.25 178.75 0.5 612,049.5 5,959,420.4 1,324 1,324.29 -1,233.65 0.38 200.72 1.1 612,049.5 5,959,420.4 1,341 1,340.54 -1,249.90 0.43 185.37 0.7 612,049.5 5,959,420.4 1,357 1,356.74 -1,266.10 0.33 160.04 1.2 612,049.5 5,959,420.1 I 1,373 1,372.94 -1,282.30 0.22 154.22 0.7 612,049.5 5,959,420.1 1,389 1,389.19 -1,298.55 0.30 179.32 0.9 612,049.6 5,959,420.1 1,405 1,405.44 -1,314.80 0.48 184.95 1.1 612,049.5 5,959,420.1 1,422 1,421.59 -1,330.95 0.45 159.04 1.3 612,049.7 5,959,419.7 I 1,438 1,437.59 -1,346.95 0.35 144.50 0.9 612,049.7 5,959,419.7 1,454 1,453.59 -1,362.95 0.28 145.25 0.4 612,049.7 5,959,419.7 1,470 1,469.59 -1,378.95 0.22 168.15 0.7 612,049.8 5,959,419.7 I 1,486 1,485.59 -1,394.95 0.33 193.29 1.0 612,049.8 5,959,419.7 1,502 1,501.59 -1,410.95 0.48 192.89 0.9 612,049.7 5,959,419.3 1,518 1,517.69 -1,427.05 0.45 176.63 0.8 612,049.7 5,959,419.3 1,534 1,533.69 -1,443.05 0.37 152.43 1.2 612,049.8 5,959,419.3 I 1,550 1,549.79 -1,459.15 0.28 141.24 0.7 612,049.8 5,959,419.0 1,566 1,565.84 -1,475.20 0.22 160.84 0,7 612,049.8 5,959,419.0 1,582 1,581.89 -1,491.25 0.32 184.06 0.9 612,049.8 5,959,419.0 1,598 1,597.94 -1,507.30 0.43 176.26 0.8 612,049.8 5,959,419.0 I 1,614 1,613.94 -1,523.30 0.35 151. 63 1.2 612,049.9 5,959,418.6 1,630 1,629.94 -1,539.30 0.30 137.00 0.6 612,049.9 5,959,418.6 1,646 1,646.03 -1,555.39 0.23 128.98 0.5 612,049.9 5,959,418.6 I 1,662 1,662.13 -1,571.49 0.18 162.00 0.8 612,050.0 5,959,418.6 1,678 1,678.23 -1,587.59 0.20 168.75 0.2 612,050.0 5,959,418.6 1,694 1,694.33 -1,603.69 0.22 135.03 0.8 612,050.0 5,959,418.6 1,710 1,710.43 -1,619.79 0.15 112.14 0.6 612,050.0 5,959,418.6 I 1,727 1,726.63 -1,635.99 0.13 159.14 0.7 612,050.0 5,959,418.6 1,743 1,742.73 -1,652.09 0.13 156.29 0.0 612,050.2 5,959,418.2 1,759 1,758.93 -1,668.29 0.13 65.70 1.1 612,050.2 5,959,418.2 1,775 1,775.03 -1,684.39 0.22 50.38 0.6 612,050.2 5,959,418.2 I 1,791 1,791.23 -1,700.59 0.23 31.69 0.5 612,050.2 5,959,418.6 1,807 1,807.38 -1,716.74 0.23 27.63 0.1 612,050.3 5,959,418.6 1,824 1,823.58 -1,732.94 0.23 58.06 0.7 612,050.3 5,959,418.6 I 1,840 1,839.78 . "'-1,749.14 0.28 38.65 0.6 612,050.3 5,959,418.6 1,856 1,855.88 -1,765.24 0.27 28.64 0.3 612,050.4 5,959,418.6 1,872 1,872.08 -1,781.44 0.28 52.67 0.7 612,050.4 5,959,418.6 1,888 1,888.28 -1,797.64 0.30 26.11 0.8 612,050.5 5,959,419.0 . - . - - ~ - - - - - - I l,9U~ l,9U4.~3 -l,tn3.~Y J.b bl¿,U:JU.:J :J,':I:J':I,41':l.U 1;921 1,920.73 -1,830.09 e Exhibit VI - 5b ).9 61215 5,959,419.0 1,937 1,936.93 -1,846.29 l.l 612 7 5,959,419.0 1,953 1,953.13 -1,862.49 2.1 612, .7 5,959,419.0 I 1,969 1,969.33 -1,878.69 0.17 6.96 0.8 612,050.7 5,959,419.0 1,986 1,985.53 -1,894.89 0.27 70.89 1.5 612,050.7 5,959,419.0 2,002 2,001.83 -1,911.19 0.33 22.25 1.6 612,050.8 5,959,419.4 2,017 2,016.53 -1,925.89 0.35 340.82 1.6 612,050.8 5,959,419.4 I 2,028 2,028.03 -1,937.39 0.33 330.55 0.6 612,050.6 5,959,419.4 2,040 2,039.63 -1,948.99 0.27 307.75 1.1 612,050.6 5,959,419.4 2,051 2,051.23 -1,960.59 0.17 265.06 1.6 612,050.6 5,959,419.4 I 2,063 2,062.83 -1,972.19 0.13 177.86 1.8 612,050.6 5,959,419.4 2,074 2,074.38 -1,983.74 0.20 86.21 2.1 612,050.6 5,959,419.4 2,086 2,085.93 -1,995.29 0.28 30.65 2.0 612,050.6 5,959,419.4 2,098 2,097.53 -2,006.89 0.28 325.33 2.6 612,050.6 5,959,419.4 I 2,109 2,109.08 -2,018.44 0.23 266.19 2.2 612,050.6 5,959,419.4 2,121 2,120.68 -2,030.04 0.17 179.93 2.4 612,050.6 5,959,419.4 2,132 2,132.28 -2,041.64 0.22 82.04 2.6 612,050.6 5,959,419.4 2,144 2,143.68 -2,053.04 0.30 31.25 2.1 612,050.6 5,959,419.4 I 2,156 2,156.28 -2,065.64 0.27 336.35 2.1 612,050.6 5,959,419.4 2,172 2,171.63 -2,080.99 0.22 331.46 0.4 612,050.6 5,959,419.7 2,188 2,188.18 -2,097.54 0.28 341.05 0.4 612,050.6 5,959,419.7 , 2,205 2,204.78 -2,114.14 0.23 269.67 1.8 612,050.5 5,959,419.7 I 2,221 2,221.38 -2,130.74 0.18 146.14 2.2 612,050.5 5,959,419.7 2,238 2,238.08 -2,147.44 0.28 25.08 2.4 612,050.5 5,959,419.7 2,255 2,254.78 -2,164.14 0.32 323.87 1.8 612,050.5 5,959,419.7 I 2,271 2,271.43 -2,180.79 0.22 238.40 2.3 612,050.5 5,959,419.7 2,288 2,288.08 -2,197.44 0.20 107.96 2.3 612,050.5 5,959,419.7 2,305 2,304.78 -2,214.14 0.25 7.69 2.1 612,050.5 5,959,419.7 2,322 2,321.48 -2,230.84 0.23 308.93 1.4 612,050.5 5,959,419.7 I 2,338 2,338.18 -2,247.54 0.22 246.16 1.4 612,050.4 5,959,419.7 2,355 2,354.83 -2,264.19 0.20 159.76 1.7 612,050.4 5,959,419.7 2,372 2,371.53 -2,280.89 0.20 174.12 0.3 612,050.4 5,959,419.7 2,388 2,388.33 -2,297.69 0.23 237.01 1.3 612,050.4 5,959,419.7 I 2,405 2,405.03 -2,314.39 0.25 190.64 1.1 612,050.4 5,959,419.7 2,422 2,421.73 -2,331.09 0.18 70.46 2.2 612,050.4 5,959,419.7 2,439 2,438.53 -2,347.89 0.17 282.83 2.0 612,050.4 5,959,419.7 I 2,455 2,455.33 -2,364.69 0.27 185.12 2.0 612,050.4 5,959,419.7 2,472 2,472.08 -2,381.44 0.20 107.63 1.8 612,050.4 5,959,419.4 2,489 2,488.83 -2,398.19 0.18 119.58 0.3 612,050.4 5,959,419.4 2,506 2,505.63 -2,414.99 0.33 155.21 1.3 612,050.5 5,959,419.4 I 2,522 2,522.43 -2,431.79 0.17 179.04 1.1 612,050.5 5,959,419.4 2,539 2,539.18 -2,448.54 0.17 191.19 0.2 612,050.5 5,959,419.4 2,556 2,555.98 -2,465.34 0.33 130.02 1.7 612,050.5 5,959,419.4 2,573 2,572.78 -2,482.14 0.23 143.75 0.7 612,050.6 5,959,419.4 I 2,590 2,589.58 -2,498.94 0.27 147.83 0.3 612,050.7 5,959,419.0 2,606 2,606.38 -2,515.74 0.22 84.13 1.6 612,050.8 5,959,419.0 2,623 2,623.18 -2,532.54 0.17 106.48 0.5 612,050.8 5,959,419.0 2,640 2,639.93 -2,549.29 0.30 152.99 1.3 612,050.8 5,959,419.0 I 2,657 2,656.78 -2,566.14 0.40 149.24 0.6 612,050.9 5,959,419.0 2,674 2,673.58 -2,582.94 0.47 140.59 0.6 612,050.9 5,959,419.0 2,690 2,690.38 -2,599.74 0.52 117.33 1.2 612,051.0 5,959,418.6 I 2,707 2,707.13 -2,616.49 0.63 111.12 0.8 612,051.2 5,959,418.6 2,724 2,723.92 -2,633.28 0.72 121.10 0.9 612,051.4 5,959,418.6 2,741 2,740.67 -2,650.03 0.75 120.85 0.2 612,051.5 5,959,418.6 2,757 2,757.42 -2,666.78 0.80 113.32 0.7 612,051.8 5,959,418.3 I 2,774 2,774.32 -2,683.68 0.90 107.78 0.8 612,052.0 5,959,418.3 2,791 2,791.12 -2,700.48 1.02 106.43 0.7 612,052.3 5,959,418.3 2,808 2,807.91 -2,717.27 1.23 108.23 1.3 612,052.6 5,959,418.3 2,825 2,824.71 -2,734.07 1.67 112.11 2.7 612,053.0 5,959,417.9 I 2,842 2,841.60 -2,750.96 1.98 111.24 1.8 612,053.5 5,959,417.9 2,858 2,858.39 -2,767.75 2.25 110.91 1.6 612,054.1 5,959,417.6 2,875 2,875.27 -2,784.63 2.55 111.02 1.8 612,054.7 5,959,417.6 I 2,892 2,892.05 -2,801.41 2.97 110.24 2.5 612,055.5 5,959,417.2 2,909 2,908.63 -2,817.99 3.42 109.29 2.7 612,056.4 5,959,416.9 2,925 2,925.20 -2,834.56 3.70 109.04 1.7 612,057.4 5,959,416.5 2,942 2,941.76 -2,851.12- 4.08 108.94 2.3 612,058.5 5,959,416.2 I 2,959 2,958.31 -2,867.67 4.45 108.78 2.2 612,059.6 5,959,415.8 2,975 2,974.86 -2,884.22 4.82 108.98 2.2 612,060.8 5,959,415.5 2,992 2,991. 39 -2,900.75 5.48 109.66 4.0 612,062.3 5,959,414.8 "'" I"\nn "'" ^"..., ,..... "'" n~"" ""'-' ,. " " .. .." ".... ... ,. ,... "'" 1"\,.... n .... ""....,... A.. A A I .),uuo .),UU/.~.I. -L.,~.I./.L.I .).0 O.l.L.,UO.).O :J,~:J~,"t.l."t."t 3,025 3,024.36 -2,933.72 .Xhibit VI - 5b 1.8 6121.5 5,959,413.7 3,042 3,040.85 -2,950.21 2.3 612; .4 5,959,413.0 3,058 3,057.33 -2,966.69 2.3 612, .3 5,959,412.3 I 3,075 3,073.79 -2,983.15 I....JV 2.3 612,071.3 5,959,412.0 3,091 3,090.24 -2,999.60 7.97 109.37 2.9 612,073.4 5,959,411.3 3,108 3,106.67 -3,016.03 8.35 109.68 2.3 612,075.6 5,959,410.2 3,125 3,123.14 -3,032.50 8.70 109.24 2.1 612,078.0 5,959,409.5 I 3,141 3,139.49 -3,048.85 9.02 108.47 2.1 612,080.4 5,959,408.8 3,158 3,155.98 -3,065.34 9.40 107.68 2.4 612,082.9 5,959,408.1 3,174 3,172.34 -3,081. 70 9.82 106.96 2.6 612,085.7 5,959,407.4 I 3,191 3,188.30 -3,097.66 10.12 106.46 1.9 612,088.3 5,959,406.4 3,205 3,202.42 -3,111. 78 10.45 105.88 2.4 612,090.7 5,959,405.7 3,225 3,222.12 -3,131.48 10.93 105.02 2.5 612,094.3 5,959,405.0 3,250 3,246.25 -3,155.61 11.43 104.30 2.1 612,099.0 5,959,403.6 I 3,276 3,272.40 -3,181.76 11.97 103.58 2.1 612,104.2 5,959,402.6 3,303 3,298.59 -3,207.95 12.50 102.97 2.0 612,109.8 5,959,401.2 3,330 3,324.63 -3,233.99 12.97 102.45 1.8 612,115.5 5,959,400.2 3,357 3,350.63 -3,259.99 13.45 101.83 1.9 612,121.6 5,959,398.8 I 3,383 3,376.57 -3,285.93 13.98 101.18 2.1 612,127.8 5,959,397.8 3,410 3,402.59 -3,311.95 14.52 100.63 2.1 612,134.4 5,959,396.4 3,437 3,428.60 -3,337.96 15.07 100.14 2.1 612,141..0 5,959,395.4 3,464 3,454.54 -3,363.90 15.60 100.03 2.0 612,148.1 5,959,394.5 I 3,491 3,480.42 -3,389.78 16.07 100.18 1.8 612,155.4 5,959,393.1 3,518 3,506.33 -3,415.69 16.63 100.35 2.1 612,162.8 5,959,391.7 3,545 3,532.15 -3,441.51 17.30 100.34 2.5 612,170.6 5,959,390.4 I 3,572 3,557.79 -3,467.15 17.90 100.11 2.2 612,178.7 5,959,389.1 3,599 3,583.38 -3,492.74 18.62 99.76 2.7 612,187.0 5,959,387.7 3,625 3,608.67 -3,518.03 19.45 99.46 3.1 612,195.6 5,959,386.7 3,656 3,637.46 -3,546.82 20.20 99.46 2.5 612,205.9 5,959,385.1 I 3,682 3,661.82 -3,571.18 20.73 99.74 2.1 612,214.8 5,959,383.7 3,717 3,694.60 -3,603.96 21.53 100.28 2.3 612,227.3 5,959,381.7 3,753 3,727.45 -3,636.81 22.30 100.57 2.2 612,240.4 5,959,379.4 3,788 3,760.18 -3,669.54 22.87 100.57 1.6 612,253.8 5,959,377.0 I 3,823 3,792.84 -3,702.20 23.28 100.53 1.2 612,267.6 5,959,374.6 3,859 3,825.40 -3,734.76 23.67 100.37 1.1 612,281.4 5,959,372.3 3,895 3,858.04 -3,767.40 24.13 99.94 1.4 612,295.7 5,959,369.9 I 3,930 3,890.42 -3,799.78 24.62 99.26 1.6 612,310.3 5,959,368.0 3,966 3,922.77 -3,832.13 25.08 98.62 1.5 612,325.0 5,959,365.6 4,001 3,954.81 -3,864.17 25.57 98.14 1.5 612,340.1 5,959,363.6 4,037 3,986.77 -3,896.13 26.05 97.86 1.4 612,355.4 5,959,362.0 I 4,072 4,018.68 -3,928.04 26.58 97.55 1.5 612,371.2 5,959,360.1 4,108 4,050.48 -3,959.84 27.13 97.31 1.6 612,387.1 5,959,358.1 4,144 4,082.11 -3,991.47 27.82 97.33 1.9 612,403.4 5,959,356.2 4,179 4,113.53 -4,022.89 28.60 97.42 2.2 612,420.1 5,959,354.2 I 4,215 4,144.74 -4,054.10 29.47 97.58 2.5 612,437.3 5,959,352.3 4,251 4,175.64 -4,085.00 30.35 97.73 2.5 612,455.0 5,959,350.4 4,286 4,206.30 -4,115.66 31.03 97.75 1.9 612,473.1 5,959,348.1 4,322 4,236.75 -4,146.11 31.63 97.73 1.7 612,491.5 5,959,345.8 I 4,357 4,266.48 -4,175.84 32.32 97.80 2.0 612,510.0 5,959,343.5 4,392 4,295.96 -4,205.32 33.17 98.07 2.5 612,528.8 5,959,341.2 4,427 4,325.20 -4,234.56 34.03 98.33 2.5 612,548.0 5,959,338.9 I 4,462 4,353.71 -4,263.07 34.77 98.46 2.2 612,567.4 5,959,336.3 4,496 4,382.03 -4,291.39 35.57 98.60 2.3 612,587.2 5,959,333.7 4,531 4,410.01 -4,319.37 36.47 98.72 2.6 612,607.4 5,959,330.7 4,566 4,437.73 -4,347.09 37.30 98.75 2.4 612,627.9 5,959,328.1 I 4,601 4,465.38 -4,374.74 38.10 98.68 2.3 612,649.1 5,959,325.1 4,636 4,492.88 -4,402.24 38.98 98.59 2.5 612,670.8 5,959,322.1 4,671 4,520.06 -4,429.42 39.92 98.58 2.7 612,692.9 5,959,319.1 4,706 4,546.86 -4,456.22 40.88 98.68 2.7 612,715.5 5,959,315.8 I 4,741 4,573.28 -4,482.64 41.83 98.81 2.7 612,738.5 5,959,312.9 4,777 4,599.33 -4,508.69 42.72 98.96 2.5 612,762.1 5,959,309.6 4,812 4,625.06 -4,534.42 43.53 99.06 2.3 612,785.8 5,959,305.9 I 4,847 4,650.40 -4,559.76 44.38 99.16 2.4 612,810.1 5,959,302.6 4,882 4,675.34 -4,584.70 45.37 99.37 2.8 612,834.6 5,959,298.9 4,917 4,699.78 -4,609.14 46.35 99.60 2.8 612,859.5 5,959,295.3 4,952 4,723.80 -4,633.16 47.28 99.77 2.7 612,884.8 5,959,291.3 I 4,988 4,747.54 -4,656.90 48.22 99.92 2.7 612,910.6 5,959,286.9 5,023 4,770.64 -4,680.00 49.17 100.09 2.7 612,936.6 5,959,282.9 5,057 4,793.06 -4,702.42 50.05 100.20 2.6 612,962.6 5,959,278.5 I:; no") LlQ11:;1., _Ll 7.,Ll LlQ I:;n QQ 1 nn .,1:; .,Ll ~ 1., OQO n I:; 01:;0 .,7Ll ., I J,v,..,_ 't"".....,,·...- "",1 _..--r""" v__,,..,v,.,._ _,..,.."..",_, --r.c.. 5,127 4,836.79 -4,746.15 exhibit VI - 5b 2.3 613'16 5,959,269.8 5,161 4,858.07 -4,767.43 2.3 613, 6 5,959,265.5 5,196 4,878.97 -4,788.33 2.3 613, .7 5,959,260.7 I 5,230 4,899.43 -4,808.79 54.00 100.30 2.2 613,097.2 5,959,256.4 5,265 4,919.64 -4,829.00 54.53 100.32 1.5 613,124.8 5,959,251.7 5,299 4,939.62 -4,848.98 54.57 100.26 0.2 613,152.5 5,959,247.0 5,334 4,959.56 -4,868.92 54.22 100.18 1.0 613,180.0 5,959,242.6 I 5,368 4,979.76 -4,889.12 53.98 100.22 0.7 613,207.5 5,959,237.9 5,403 5,000.00 -4,909.36 54.18 100.36 0.7 613,235.1 5,959,233.6 5,437 5,020.18 -4,929.54 54.33 100.43 0.5 613,262.7 5,959,228.9 5,472 5,040.42 -4,949.78 54.22 100.45 0.3 613,290.5 5,959,224.2 I 5,506 5,060.69 -4,970.05 54.15 100.52 0.3 613,318.2 5,959,219.5 5,541 5,080.96 -4,990.32 54.27 100.58 0.4 613,345.9 5,959,214.8 5,576 5,101.19 -5,010.55 54.27 100.59 0.0 613,373.7 5,959,210.1 I 5,610 5,121.42 -5,030.78 54.30 100.59 0.1 613,401.4 5,959,205.3 5,645 5,141.62 -5,050.98 54.38 100.64 0.3 613,429.1 5,959,200.3 5,680 5,161.80 -5,071.16 54.12 100.58 0.8 613,456.8 5,959,195.6 5,714 5,182.05 -5,091.41 54.00 100.53 0.4 613,484.2 5,959,190.9 I 5,748 5,201.95 -5,111.31 54.10 100.58 0.3 613,511.4 5,959,186.5 5,781 5,221.54 -5,130.90 54.08 100.57 0.1 613,538.0 5,959,181.8 5,815 5,241.19 -5,150.55 54.13 100.53 0.2 613,564.7 5,959,177.1 ,5,848 5,260.87 -5,170.23 53.90 100.55 0.7 613,591.5 5,959,172.7 I 5,882 5,280.72 -5,190.08 53.68 100.60 0.7 613,618.2 5,959,168.0 5,916 5,300.85 -5,210.21 53.72 100.65 0.2 613,645.2 5,959,163.3 5,950 5,321.04 -5,230.40 53.55 100.63 0.5 613,672.2 5,959,158.9 I 5,984 5,341.34 -5,250.70 53.37 100.60 0.5 613,699.2 5,959,154.2 6,018 5,361.68 -5,271.04 53.25 100.62 0.4 613,726.1 5,959,149.5 6,052 5,382.05 -5,291.41 53.27 100.67 0.1 613,752.9 5,959,144.8 6,086 5,402.51 -5,311.87 53.10 100.69 0.5 613,779.9 5,959,140.1 I 6,121 5,423.10 -5,332.46 52.77 100.70 1.0 613,806.8 5,959,135.3 6,155 5,443.70 -5,353.06 52.63 100.76 0.4 613,833.4 5,959,131.0 6,189 5,464.41 -5,373.77 52.58 100.82 0.2 613,860.1 5,959,126.3 6,223 5,485.04 -5,394.40 52.43 100.81 0.4 613,886.6 5,959,121.5 I 6,257 5,505.82 -5,415.18 52.35 100.84 0.3 613,913.2 5,959,116.8 6,291 5,526.73 -5,436.09 52.18 100.91 0.5 613,939.8 5,959,112.1 6,325 5,547.65 -5,457.01 52.12 100.93 0.2 613,966.3 5,959,107.4 6,359 5,568.56 -5,477.92 52.35 100.89 0.7 613,992.8 5,959,102.6 I 6,393 5,589.19 -5,498.55 52.45 100.82 0.3 614,019.2 5,959,098.3 6,426 5,609.57 -5,518.93 52.58 100.75 0.4 614,045.4 5,959,093.6 6,460 5,629.82 -5,539.18 52.90 100.76 1.0 614,071.7 5,959,088.8 I 6,493 5,649.91 -5,559.27 53.28 100.78 1.1 614,098.0 5,959,084.5 6,527 5,669.79 -5,579.15 53.67 100.80 1.2 614,124.5 5,959,079.8 6,560 5,689.51 -5,598.87 53.98 100.81 0.9 614,151.0 5,959,075.0 6,593 5,709.02 -5,618.38 54.28 100.78 0.9 614,177.6 5,959,070.3 I 6,626 5,728.30 -5,637.66 54.70 100.76 1.3 614,204.2 5,959,065.6 6,660 5,747.49 -5,656.85 55.17 100.77 1.4 614,231.1 5,959,061.2 6,693 5,766.54 -5,675.90 55.50 100.73 1.0 614,258.2 5,959,056.2 6,727 5,785.38 -5,694.74 55.83 100.65 1.0 614,285.4 5,959,051.5 I 6,760 5,804.04 -5,713.40 56.25 100.63 1.3 614,312.7 5,959,046.7 6,794 5,822.53 -5,731.89 56.53 100.64 0.8 614,340.2 5,959,042.0 6,827 5,840.88 -5,750.24 56.70 100.64 0.5 614,367.5 5,959,037.3 I 6,860 5,859.16 -5,768.52 56.95 100.71 0.8 614,395.2 5,959,032.6 6,894 5,877.26 -5,786.62 57.20 100.80 0.8 614,422.7 5,959,027.9 6,927 5,895.27 -5,804.63 57.43 100.91 0.7 614,450.3 5,959,022.8 6,960 5,913.05 -5,822.41 57.70 101.01 0.9 614,477.9 5,959,018.1 I 6,993 5,930.69 -5,840.05 57.97 101.11 0.9 614,505.5 5,959,013.1 7,026 5,948.17 -5,857.53 58.18 101.20 0.7 614,533.1 5,959,008.0 7,058 5,964.90 -5,874.26 58.32 101.25 0.5 614,559.6 5,959,003.3 7,090 5,981.64 -5,891.00 58.38 101.30 0.2 614,586.4 5,958,998.2 I 7,122 5,998.31 -5,907.67 58.42 101.38 0.3 614,613.0 5,958,993.5 7,154 6,015.04 -5,924.40 58.43 101.43 0.1 614,639.8 5,958,988.4 7,186 6,032.04 -5,941.40 58.47 101.47 0.2 614,667.0 5,958,983.3 I 7,219 6,049.04 -5,958.40 58.47 101.50 0.1 614,694.3 5,958,978.2 7,251 6,066.04 -5,975.40 58.55 101.51 0.3 614,721.5 5,958,973.2 7,284 6,083.05 -5,992.41 58.67 101.59 0.4 614,748.9 5,958,967.7 7,317 6,099.99 , -6,009.35 58.68 101.67 0.2 614,776.3 5,958,962.7 I 7,349 6,116.99 -6,026.35 58.70 101.73 0.2 614,803.6 5,958,957.6 7,382 6,133.96 -6,043.32 58.75 101.83 0.3 614,831.1 5,958,952.2 7,415 6,150.89 -6,060.25 58.88 101.92 0.5 614,858.5 5,958,946.7 7.447 6.167.78 -6.077.14 58.95 102.03 0.4 614.886.0 5.958.941.3 I ~,480 6,184.56 -6,093.92 _hibit VI - 5b 0.4 614,913.4 5,958,935.8 7,513 6,201.48 -6,110.84 0.3 614,.8 5,958,930.4 7,545 6,218.38 -6,127.74 0.5 614, .3 5,958,925.0 I 7,578 6,235.27 -6,144.63 ...JJ.~V 0.6 614,995.8 5,958,919.2 7,611 6,252.06 -6,161.42 59.10 102.54 0.1 615,023.3 5,958,913.7 7,643 6,268.87 -6,178.23 58.93 102.59 0.5 615,050.7 5,958,907.9 7,676 6,285.85 -6,195.21 58.72 102.63 0.7 615,078.2 5,958,902.1 I 7,709 6,302.70 -6,212.06 58.58 102.66 0.4 615,105.2 5,958,896.7 7,741 6,319.50 -6,228.86 58.52 102.71 0.2 615,132.1 5,958,890.9 7,773 6,336.33 -6,245.69 58.35 102.79 0.6 615,158.9 5,958,885.4 7,805 6,353.25 -6,262.61 58.03 102.89 1.0 615,185.6 5,958,879.6 I 7,837 6,370.33 -6,279.69 57.82 102.99 0.7 615,212.3 5,958,873.8 7,869 6,387.66 -6,297.02 56.83 103.14 3.1 615,238.7 5,958,868.3 7,902 6,405.32 -6,314.68 56.62 103.21 0.7 615,264.9 5,958,862.5 I 7,934 6,422.79 -6,332.15 57.22 103.19 1.9 615,291.1 5,958,856.7 7,966 6,440.29 -6,349.65 56.95 103.20 0.8 615,317.6 5,958,850.9 7,998 6,457.88 -6,367.24 56.57 103.24 1.2 615,343.8 5,958,845.1 8,030 6,475.67 -6,385.03 56.25 103.42 1.1 615,369.9 5,958,839.2 I 8,062 6,493.51 -6,402.87 56.10 103.62 0.7 615,395.9 5,958,833.4 8,094 6,511.46 -6,420.82 55.88 103.72 0.7 615,421.8 5,958,827.6 8,126 6,529.54 -6,438.90 55.58 103.76 0.9 615,447.7 5,958,821.8 8,158 6,547.73 -6,457.09 55.25 103.84 1.1 615,473.4 5,958,815.9 I 8,190 6,566.14 -6,475.50 54.87 103.94 1.2 615,499.1 5,958,809.7 8,222 6,584.65 -6,494.01 54.45 104.03' 1.3 615,524.5 5,958,803.9 8,254 6,603.36 -6,512.72 54.13 104.14 1.0 615,549.9 5,958,798.1 I 8,286 6,622.06 -6,531.42 53.83 104.27 1.0 615,574.9 5,958,791.9 8,318 6,640.75 -6,550.11 53.38 104.36 1.5 615,599.6 5,958,786.0 8,348 6,659.04 -6,568.40 52.92 104.46 1.5 615,623.3 5,958,780.5 8,381 6,679.16 -6,588.52 52.50 104.66 1.4 615,648.9 5,958,774.0 I 8,416 6,700.41 -6,609.77 52.10 104.94 1.3 615,675.6 5,958,767.4 8,449 6,720.39 -6,629.75 51.90 105.00 0.6 615,700.4 5,958,761.2 8,481 6,740.25 -6,649.61 51.63 104.45 1.6 615,724.9 5,958,755.4 8,513 6,760.32 -6,669.68 50.98 103.20 3.7 615,749.4 5,958,749.5 I 8,545 6,780.78 -6,690.14 49.97 101.68 4.8 615,773.6 5,958,744.8 8,577 6,801.65 -6,711.01 48.93 100.21 4.8 615,797.5 5,958,740.4 8,609 6,823.00 -6,732.36 48.17 98.86 3.9 615,821.4 5,958,736.7 8,642 6,844.56 -6,753.92 47.72 97.71 3.0 615,845.2 5,958,733.8 I 8,674 6,866.28 -6,775.64 47.35 96.58 2.8 615,868.7 5,958,730.9 8,706 6,888.19 -6,797.55 47.03 95.74 2.2 615,892.3 5,958,728.7 8,738 6,910.11 -6,819.47 47.02 95.60 0.3 615,915.8 5,958,726.8 I 8,770 6,931.99 -6,841.35 47.20 95.82 0.8 615,939.2 5,958,725.0 8,803 6,953.87 -6,863.23 47.35 96.04 0.7 615,962.8 5,958,722.8 8,835 6,975.65 -6,885.01 47.53 96.20 0.7 615,986.5 5,958,720.6 8,867 6,997.43 -6,906.79 47.68 96.37 0.6 616,010.2 5,958,718.4 I 8,899 7,019.14 -6,928.50 47.82 96.63 0.7 616,034.0 5,958,715.9 8,932 7,040.86 -6,950.22 48.00 96.89 0.8 616,058.0 5,958,713.7 8,964 7,062.43 -6,971.79 48.22 97.18 1.0 616,081.8 5,958,710.7 8,996 7,083.57 -6,992.93 48.40 97.47 0.9 616,105.3 5,958,708.2 I 9,028 7,104.59 -7,013.95 48.55 97.72 0.8 616,129.0 5,958,705.6 9,059 7,125.54 -7,034.90 48.72 97.96 0.8 616,152.6 5,958,702.7 9,091 7,146.43 -7,055.79 48.80 98.11 0.4 616,176.2 5,958,699.7 I 9,123 7,167.34 -7,076.70 48.72 98.19 0.3 616,199.9 5,958,696.5 9,154 7,188.26 -7,097.62 48.53 98.21 0.6 616,223.4 5,958,693.5 9,186 7,209.19 -7,118.55 48.33 98.14 0.7 616,246.9 5,958,690.6 9,218 7,230.34 -7,139.70 48.10 98.10 0.7 616,270.3 5,958,687.7 I 9,249 7,251.58 -7,160.94 47.80 98.09 0.9 616,293.7 5,958,684.7 9,281 7,272.90 -7,182.26 47.52 98.14 0.9 616,317.0 5,958,681.4 9,313 7,294.31 -7,203.67 47.28 98.22 0.8 616,340.0 5,958,678.5 9,344 7,315.86 -7,225.22 47.10 98.32 0.6 616,363.0 5,958,675.5 I 9,376 7,337.50 -7,246.86 46.98 98.43 0.5 616,386.2 5,958,672.6 9,408 7,359.25 -7,268.61 46.87 98.55 0.4 616,409.2 5,958,669.7 9,440 7,381.00 -7,290.36 46.65 98.69 0.8 616,432.1 5,958,666.4 I 9,471 7,402.85 -7,312.21 46.40 98.82 0.8 616,454.8 5,958,663.1 9,503 7,424.66 -7,334.02 46.32 98.90 0.3 616,477 .5 5,958,660.1 9,534 7,446.42 -7,355.78 46.30 98.93 0.1 616,500.2 5,958,656.8 9,566 7,468.12 -7,377.48 46.23 99.09 0.4 616,522.6 5,958,653.5 I 9,597 7,489.65 -7,399.01 46.17 99.36 0.7 616,544.7 5,958,650.2 9,628 7,511.00 -7,420.36 46.08 99.67 0.8 616,566.8 5,958,646.9 9,659 7,532.70 -7,442.06 45.78 100.06 1.3 616,588.8 5,958,643.5 9,690 7,554.46 -7,463.82 45.38 100.58 1.8 616,610.7 5,958,639.9 I. 9,721 7,576.44 -7,485.80 5 1.5 616,632.5 5,958,636.2 ~,753 7,598.56 -7,507.92 eXhibit VI - 5b .~ 0.9 616,_3 5,958,632.1 9,784 7,620.70 -7,530.06 0.4 616, .9 5,958,628.1 9,815 7,642.92 -7,552.28 r4 0.1 616,697.5 5,958,624.0 I 9,846 7,665.06 -7,574.42 44.82 101.33 0.3 616,719.2 5,958,619.9 9,878 7,687.25 -7,596.61 44.88 101.29 0.2 616,740.9 5,958,615.9 9,909 7,709.41 -7,618.77 44.97 101.27 0.3 616,762.6 5,958,611.8 I 9,940 7,731.54 -7,640.90 45.05 101.30 0.3 616,784.4 5,958,608.1 9,971 7,753.66 -7,663.02 45.05 101.32 0.1 616,806.2 5,958,604.1 10,003 7,775.78 -7,685.14 44.98 101.33 0.2 616,828.0 5,958,600.0 10,034 7,797.87 -7,707.23 44.87 101.46 0.5 616,849.7 5,958,596.0 I 10,065 7,820.14 -7,729.50 44.75 101.64 0.6 616,871.3 5,958,591.9 10,097 7,842.43 -7,751.79 44.83 101.79 0.4 616,893.0 5,958,587.5 10,128 7,864.69 -7,774.05 1.4.92 101.87 0.3 616,914.8 5,958,583.4 10,160 7,886.92 -7,796.28 4... 93 101.88 0.0 616,936.6 5,958,579.0 I 10,191 7,909.16 -7,818.52 45.1.J7 101.85 0.5 616,958.4 5,958,575.0 10,222 7,930.91 -7,840.27 45.23 101.78 0.5 616,979.9 5,958,570.6 10,253 7,952.60 -7,861.96 45.28 101.72 0.2 617,001.4 5,958,566.5 I 10,283 7,974.29 -7,883.65 45.18 101.63 0.4 617,022.9 5,958,562.4 10,314 7,995.99 -7,905.35 45.05 101.55 0.5 617,044.3 5,958,558.4 10,345 8,017.75 -7,927.11 45.02 101.52 0.1 617,065.7 5,958,554.3 ,10,376 8,039.60 -7,948.96 44.98 101.52 0.1 617,087.2 5,958,550.3 I 10,407 8,061.40 -7,970.76 44.88 101.61 0.4 617,108.6 5,958,546.2 10,437 8,083.27 -7,992.63 44.68 101.87 0.9 617,129.8 5,958,542.1 10,468 8,105.23 -8,014.59 44.35 102.25 1.4 617,151.0 5,958,538.1 10,499 8,127.36 -8,036.72 44.12 102.62 1.1 617,172.1 5,958,533.6 I 10,530 8,149.47 -8,058.83 44.17 102.96 0.8 617,193.1 5,958,529.2 10,561 8,171.61 -8,080.97 44.32 103.29 0.9 617,214.2 5,958,524.8 10,592 8,193.64 -8,103.00 44.33 103.70 0.9 617,235.2 5,958,520.0 10,623 8,215.74 -8,125.10 44.35 104.22 1.2 617,256.2 5,958,515.2 I 10,653 8,237.83 -8,147.19 44.53 104.68 1.2 617,277.3 5,958,510.0 10,684 8,259.64 -8,169.00 44.97 105.00 1.6 617,298.2 5,958,504.9 10,715 8,281.18 -8,190.54 45.52 105.14 1.8 617,319.3 5,958,499.3 I 10,745 8,302.52 -8,211.88 46.07 105.21 1.8 617,340.5 5,958,493.8 10,776 8,323.54 -8,232.90 46.58 105.29 1.7 617,361.8 5,958,488.7 10,806 8,344.26 -8,253.62 46.95 105.33 1.2 617,383.3 5,958,483.1 10,836 8,364.68 -8,274.04 47.30 105.37 1.2 617,404.5 5,958,477.6 I 10,866 8,385.02 -8,294.38 47.68 105.55 1.3 617,426.0 5,958,471.7 10,896 8,405.36 -8,314.72 47.97 105.71 1.0 617,447.7 5,958,466.2 10,932 8,429.30 -8,338.66 48.38 105.80 1.2 617,473.6 5,958,459.3 10,955 8,444.19 -8,353.55 48.72 105.78 1.5 617,489.8 5,958,454.8 I 10,977 8,458.71 -8,368.07 49.00 105.82 1.3 617,506.0 5,958,450.6 11,000 8,473.79 -8,383.15 49.03 106.07 0.8 617,522.7 5,958,446.1 11,024 8,489.55 -8,398.91 49.05 106.38 1.0 617,540.2 5,958,441.3 I 11,048 8,505.31 -8,414.67 49.32 106.58 1.3 617,557.8 5,958,436.4 11,072 8,520.97 -8,430.33 49.58 106.71 1.2 617,575.3 5,958,431.6 11,096 8,536.61 -8,445.97 49.93 106.94 1.6 617,593.2 5,958,426.4 11,121 8,552.11 -8,461.47 50.18 107.23 1.4 617,610.9 5,958,421.2 I 11,145 8,567.58 -8,476.94 50.33 107.47 1.0 617,628.8 5,958,416.0 11,169 8,583.04 -8,492.40 50.50 107.82 1.3 617,646.7 5,958,410.4 11,189 8,596.03 -8,505.39 50.82 108.20 2.1 617,661.8 5,958,405.9 11,206 8,606.19 -8,515.55 51.27 108.53 3.2 617,673.7 5,958,402.0 I 11,222 8,616.31 -8,525.67 51.45 108.81 1.8 617,685.8 5,958,398.2 11,238 8,626.44 -8,535.80 51.42 108.93 0.6 617,697.9 5,958,394.3 11,254 8,636.58 -8,545.94 51.53 109.28 1.8 617,710.0 5,958,390.1 11,271 8,646.72 -8,556.08 51.58 109.68 2.0 617,722.1 5,958,386.3 I 11,287 8,656.87 -8,566.23 51.68 109.89 1.2 617,734.2 5,958,382.1 11,303 8,666.95 -8,576.31 51.97 110.10 2.0 617,746.4 5,958,377.9 11,320 8,676.95 -8,586.31 52.30 110.35 2.4 617,758.4 5,958,373.7 I 11,336 8,686.85 -8,596.21 52.57 110.65 2.2 617,770.6 5,958,369.1 11,352 8,696.71 -8,606.07 52.77 111.12 2.6 617,782.8 5,958,364.9 11,374 8,709.92 -8,619.28 53.00 111.66 2.2 617,799.0 5,958,358.6 11,399 8,724.82 -8,634.18 53.20 111. 94 1.2 617,817.7 5,958,351.6 I 11,424 8,739.72 -8,649.08 53.23 112.02 0.3 617,836.2 5,958,344.5 11,449 8,754.58 -8,663.94 53.15 112.17 0.6 617,854.7 5,958,337.1 11,473 8,769.40 -8,678.76 53.47 112.68 2.1 617,873.2 5,958,329.7 11,498 8,784.11 -8,693.47 54.12 113.27 3.2 617,891.9 5,958,322.3 I 11,523 8,798.57 -8,707.93 54.53 113.60 2.0 617,910.4 5,958,314.6 11 ,548 8,812.86 -8,722.22 55.15 113.25 2.8 617,929.2 5,958,306.8 11,573 8,826.84 -8,736.20 56.20 112.27 5.4 617,948.2 5,958,299.1 I I I I I I I I I I I I I I I I I I I 11,598 11;623 11,648 11,673 11,698 11,723 11,754 11,817 11,848 11,877 11,943 11,972 11,984 12,060 12,110 12,148 12,237 12,332 12,485 12,639 12,859 12,957 13,052 13,113 13,165 13,166 8,840.57 8,854.03 8,867.29 8,880.32 8,893.10 8,905.72 8,920.72 8,946.54 8,957.37 8,966.21 8,981.16 8,985.45 8,986.82 8,992.05 8,993.01 8,993.04 8,993.51 8,995.42 9,000.36 9,004.66 9,008.69 9,011.68 9,016.90 9,021.63 9,026.26 9,026.35 -8,749.93 -8,763.39 -8,776.65 -8,789.68 -8,802.46 -8,815.08 -8,830.08 -8,855.90 -8,866.73 -8,875.57 -8,890.52 -8,894.81 -8,896.18 -8,901.41 -8,902.37 -8,902.40 -8,902.87 -8,904.78 -8,909.72 -8,914.02 -8,918.05 -8,921.04 -8,926.26 -8,930.99 -8,935.62 -8,935.71 .26 Ahibit VI - 5b .56 .. .72 ,92 105.74 104.70 98.60 98.20 100.00 98.90 100.70 101.00 101.00 104.20 104.20 105.20 104.90 105.60 106.60 106.30 107.00 106.30 107.70 107.30 107.70 107.70 59.55 59.68 63.30 68.30 70.80 73.70 80.10 82.90 84.00 88.10 89.70 90.20 89.20 88.50 87.80 89.00 88.90 87.60 86.10 85.00 84.80 84.80 5.1 3.3 3.4 6.9 7.8 3.6 20.6 8.0 9.7 10.6 10.1 9.7 9.2 6.8 3.2 2.9 1.2 1.0 0.8 0.8 0.3 1.5 2.2 1.9 0.9 0.0 617,967.7 617...5 618_.5 618,027.8 618,048.4 618,069.2 618,096.4 618,153.3 618,182.0 618,209.4 618,272.8 618,301.0 618,312.8 618,387.1 618,435.7 618,472.5 618,558.8 618,650.8 618,798.3 618,946.6 619,158.3 619,252.5 619,343.7 619,401.9 619,451.6 619,452.4 5,958,291.7 5,958,284.7 5,958,277.3 5,958,271.0 5,958,265.1 5,958,259.6 5,958,254.5 5,958,247.0 5,958,242.7 5,958,238.7 5,958,228.8 5,958,223.7 5,958,221.7 5,958,206.0 5,958,194.7 5,958,185.4 5,958,163.7 5,958,140.3 5,958,099.8 5,958,058.6 5,957,998.6 5,957,971.9 5,957,945.5 5,957,928.1 5,957,913.2 5,957,912.8 I I I I I I I I I I I I I I I I I I I e Exhi.I-5C ." ~. . 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I I' TNLE TRILl 1 TRILl ODDI COST COOE ":'" - I Z) -~~n ...1IMP 2 B OFI row. ---~ J./ IW'C 2 I CONTIW:1OR 3c r;:;: . f1 - ~ ~...,? I A... _I. I TRIII.I CO$1' :) 1= !i ""~ 1 I '~IM:E co. ¥ J' I I FLUID INJ I Cll'HER I ITRBLE COST ...1= I =~ ze; I I CATI_ 4 I I e :; ~ Exhibit VI -e PBU!EWE DRILLING PROGRAM PROPOSED WET J, DIAGRAM WELL WLi15 (42-22-11-12) HIGH ANGLE WELL AFE ·125183 AUDI RIG 3 - 4-112" Ball Valve J. with Flow Couplings 2100' \' ~ ~ 13 318" Shoe 2680' 17 112" Open Hole 2700' .J ~ 9518"47#L80 NSCC .J 4 112" Liner Shoe 13042' r1 n L---" 00 8 112" ~ JD J JL. 13042' RECOMENDED: ~~~1\O 0)0 APPROVED: ~'-A ¡j~ 6/11 ß1¿ Drilling Engilleer 1I1ing Engineering Supervisor APPROVED: ~~~ APPROVED: /ML/~¢Þ/'lø Completi¢S E~gin\x:r S7f~k 0 Drilling Superintendent RIS 5/10/90 I I CEMENTATION: I I 13 318" CEMENT SLURRY: Lead Slurry: 1920 cuft (1000 sacks) ¡, COLD SET III Tail Slurry : 1920 cu ft (2000 sacks) COLD SET II I I I 9518" CEMENT SLURRY: I Lead Slurry: 2153 cu ft (1087 sacks) Class G+8% . (see program for details) I Tail Slurry: , 576 cu ft (500 sacks) I' Class G i (see program for details) I I 7" LINER SLURRY: I BATCH MIX I Slurry: I 247 cu ft (160 sacks) i Class G+35%Si Flour f (see program for details)' I I 4 1/2" COMPLETION: WELLHEAD: FMC 4-1/16" TREE KOP: 2800' MAX. ANGLE: 87.8° TAILPIPE SIZE: 4 112" I I I I j ¡i .J I;' .J ,1 .J &,;8 I I ~ ~ ;~.~ I I 'I· Is æ:· -Iii. 00 ~:~ 00 l20" eo..wøm ~ 13 318" 68# L-80 Butl I I Base Pennafrost 1862' . 4 1{}." 12.6# L-80 TDS with GLM's TIW 9 5/8" Packer 11234' TIW Liner Hanger 11284' 9518" Casing Shoe 11534' 12 1/4" Open Hole 11544' 7" 26# L-80 IJ4S "Off Bottom" Cemented Liner TIW Liner Hanger and Packer 11942' 7" Shoe 12042' 4-112" 12.6# L-80 IDS Solid Liner clw 2 External Casing Packers and Sliding Sleeves I I I I I I I I il I I I I I I I I I I e Exhibit VI __ 13-3/8" CASING AND CEMRNTING PROGRAM WELL W-15 (PßU/RWR) PROGRAM: 1. Install mud-line suspension landing ring on 20" conductor ensuring it is level. Ensure mandrel hanger O.D. will pass through riser. Nipple up riser. 10 " 2. Drill 17-1/2" hole veHkally to 2700 ft. MD BKB. i; I I Circulate until hole is dean. POH to run 13-3/8" casing. NOTES: a) Maintain mud temperature as low as possible (40-45 deg. F). b) Clean, visually inspect, and drift casing. c) Have B.J. TITAN perform thickening time tests on cement delivered to loc~tion using mix water which will be used for the job. TT = 4-1/2 hours @ 50 deg. F for tail slurry. d) Ensure 13-3/8'¡ Buttress double pin pup joint is of correct length so that ,the casing head flange will be 18" above the top of the cellar. i:i e) Notify Alaska Oil & Gas Commission (279-1433) 48 hours in advance to witness 13-3/8" BOPE test. 3. Run 13-3/8" 68# L-80Buttress casing as follows: - Float shoe (landed @ approximately 2680 ft.) - 1 joint 13-3/8",68#, L-80, Buttress casing - Float collar - 13-3/8",68#, L-80, BUTT casing (approx. 67 jts. total) - Mud-line suspension hanger assembly - 13-3/8" "Specially Cut" Buttress double pin pup joint - Landing joint~: CASING RUNNING AND (CEMENTING NOTES: a) Place 13-3/8" centralizers 5 ft. and 20 ft. above the shoe and every joint for the next 9 joints (11 total). \. b) Bakerlok first three (3) connections. c) Fill casing as necessary. ! d) Have a 13-3/8" buttress swage with a 2" valve and cementer connection available on the floor while running casing. I, e) Place two (2) 13-3/8" metal petal baskets inside conductor: One at 90 ft. BKB using stop rings above and below basket; and one on the first full joint below mud-line hanger to bottom out on casing collar (at approx. 65 ft. BKB) using a stop ring above basket. W-15 Drilling Program 5/16/90 Page 2 I I I I I I I I I I Î I ,f I I I 1\ I I e Exhibit VI - =e 4. Land 13-3/8" casing Shoe at approximately 2680 ft. MD BKB as follows: a) Install mud-linf suspension hanger on last joint. b) Pick up 13-3/8" landing joint and wash down last joint if required. Tag 20" landing ring. Slack off weight while monitoring conductor for settlement. . If settlement occurs, set slips and slack off remaining weight. If conductor does not settle, slack off all remaining weight on the landing ring and set slips for safety. 5. RU B.J. TITAN cementers. Make up plug holding head (with top plug installed) onto landing joint. Install bottom plug, make up landing joint and test lines to 30oo!psi. Break circulation. Pump 20 bbls. of water ahead of cement. M~ and pump cement as follows: Lead Slurry: Slurry: 1920 cu ft \ (1000 sacks) , COLD SET III I I Weight: 12.2 ppg. Yield: 1.92 cu ftlsack Water: 10.53 gallsack IT: 4.5 hours* Tail Slurry: Slurry: ,ê 1920 cu ft (2000 sacks) COLD SET II ¡ Weight:)4.95 ppg. Yield: ,0.96 cu ftlsack ,,'I Water: ·3.80 gallsack IT: 4.5 hours* *Have B.J. TITAN perform thickening time tests on cement delivered to location using mix water which will be used for the job. 6. Release top plug. Displace cement to float collar at a rate of 8-10 bpm. Bump plug with 2001) psi. DO NOT OVER-DISPLACE plug by more than 1/2 the shoe volume (3 barrels). Provide details of cement returns on morning report and lADC report. 7. wac 4 hours to allow cement to develop sufficient strength to support the 13-3/8" casing. Rem9¥e the slips and slack off weight slowly and observe casing for settlement; If settlement occurs, pick up all weight and wac an additional two (2) hours and repeat slack off procedure. 8. Nipple down riser and perform top job if necessary. 9. Bakerlok and make up '13-3/8", 5000 psi split speed head so that tubing head annulus valves are oriented 90 deg. to the right of the direction facing the reserve pit. Approximate torque = 14,500 ft-Ibs. However, under no circumstances should the head be "backed-out" counter-clockwise to meet this orientation requirement. 10. Install and test BOP stack as per BOP manual. W -15 Drilling Program 5/16/90 Page 3 I Î , I I I I t i I t I I i I I I I I j! e Exhibit VI - e 11. Install long bowl protector. Test 13-3/8" casing to 3000 psi. before drilling out float equipment. 12. Drill out shoe plus a minimum of 10ft. new hole and perfonn fonnation integrity test. Drill1t-1/4" hole per directional map. 13. Measure KB to ground level and KB to BF. Record measurements on tour sheet and telex. I I I I"~· W-15 Drilling Program Page 4 5/16/90 Exhibit VI -- -- ....""'-" ; ¡. JJ.:.3'/8" MATERIALS LIST !YEl~I,··W-15 AFE # 11·5183 QTY ITEM VOCAB N!! 1 13-3/8" Buttress float shoe Howco f ':-, I 1 13-3/8" Buttress float collar Howco I: I, ,.".- 70 13-3/8" 68# L-80,BUTT, R-3 86050071 (including three extra joints) I 11 13-3/8" LO ,bow-type centralizers 86127408 2 13-3/8" Metal petal basket Howco ! 5 13-3/8" Stop rings 86129493 1 13-3/8" 68#;1..-80 Buttress double N/S built -- pin pup join~~ i 1 FMC split speedhead system, _d 13-3/8" Buttress w/AB seal ring x 86623800 13-5/8" APfsOOO psi. flange and 13-5/8" x 13-5/8" tubing spool 1 FMC mud-line suspension FMC system 86623906 2 pails Thread dope - API modified 86139010 1 box Bakerlok 86139001 (10 x 1 # ca..'1S ),. , . i t:~ W-15 Drilling Program i. ( Page 5 5/16/90 , . Exhibit VI - [ <--, ',-~ 9-5/8" CASING AND CEMENTING PROGRAM ,1£ELL W-15 (PBU!EWE) ~. SUMMARY: .. ! A. Run 9-5/8" 47# NT80~NSCC casing to surface. Land shoe within 5 ft. of bottom with mandr~l hanger. B. Cement casing with Class G cement. Inject down annulus after .--- cement is in place to clear cement from annulus. Have cement company run thickening time tests on each load of cement delivered to location using mix water which will be used for the job. I / C. Install and test pack-offs. i D. Test casing to 3000 psi. before drilling out shoe. PROGRAM: ~"' 1. Drill 12-1/4" hole dqwn through the entire Sag River Sandstone formation (Top Sag. 8784' TVD BKB) and penetrate 10' into the top of the Shu~lik formation (Top Shublik 8865' TVD BKB) and maintain control ~~ per target map. The North Slope geologist will predict the top of the ~hublik fonnation from rig site data. While drilling from 7006' TVD to 112-1/4" T.D., the mud weight should be a minimum of 9.7 ppg. Open hoie logs will be run as per saddleblanket. - 2. Condition hole for casing. Pull wear bushing and install 9-5/8" rams. 3. Run 9-5/8" 47# NT80-S casing (set shoe within 5 ft. of 12-1/4" T.D.) as follows: ,. Float shoe (Buttress) with side ports - 3 joints of 47# L-80 NSCC casing (first joint with pin nose seal removed) - Float collar (Buttress) - 9-5/8" 47# NSCC casing to surt'ace ( approx. 304 jts. total) (first joint wifh pin nose seal removed) - Mandrel hange'r - Landing J oinr CASING RUNNING NOtES: a) Bakerlok bottom 3 joints. b) Centralize bott-Jm 10 joints with stand-off bands. Run turboclamps on every third joint from surface to 2680 ft. c) Have circulatin;g swage with valve and cementer hook-up available on floor while running casing. d) Fill casing as necessary W -15 Drilling Program Page 6 5/16/90 Exhibit VI _ r --- --- - 4. 5. ~ e) Cut off nose s~al of the two NSCC pins which will be made up with buttress float equipment. Circulate last joint to bottom and land mandrel hanger in the wellhead. If mandrel hanger cannot be run, use emergency slips and pack -off. RU B.J. TITAN cementers. Rig up injection line to 13-3/8" x 9-5/8 annulus. Instal1, bòttom plug in casing and top plug in head. Test all lines to 3000 psi. Rump 20 bbls of fresh water preflush ahead of the cement. ! " { / '- 6. Mix and pump cemenf.Cement volume based on the 100% annular volume between 9-5/8" casing and 12-1/4" hole to bring the top of the cement to 500'"MD above the top of the Ugnu sands + 50 cu.ft. (Top Ugnu sands 3473' TVD, 3480' MD, top of cement 2980' MD). Lead Slurry: '.~=- 2153 cu.ft. (1087 sacks) Class G cement with 8% BENTONITE + 0.2% CD-31 + 0.6% R-l + 1 gal/l00 sacks FP-6L. Weight: 13.0 ppg. Yield: 1.98 cu.ft./sack Water: 10.78 ga1./sack IT: 5:40 hours* Tail Slurry: I 576 cU.f!. (500 sackJ) Class G cement + 0.65 % FL-20 + 0.1% CD-31 + 0.06% R-l + 1 Ga./l00 sacks FP-6L. I <-~r· Weight: 15.8 þpg. Yield: 1.152: cu.ft./sack Water: 4.96 ga1./sack TT: 4 hours* *Have B.J. TIT AN r$n thickening time tests on each load of cement delivered to the rig using water which will be used for the job. .~ 7. Drop the top plug. Displace the cement with mud at 8 to 10 bbl./min. Do not over-displace by m.ore than half of the volume from the float collar to the shoe (4.4 bbls.). Bump plug and pressure to 3000 psi. After bumping the plug, dose annular preventer and inject 50 bbl mud into the 13-3/8'" x 9-5/8" annulus at no more than 4 bbl/min to clear the 'annulus. 8. Drain the BOP stack imd remove the landing joint. Flush pack-off area, install pack-off and energize as per wellhead manufacturers 9-5/8" mandrel hanger procedures. 9. Test pack-off to 5000 psi. with annulus open. InstallS" rams. Test BOPE. Install short bowl protector. -,. 10. RIH with 8-1/2" bit and drill cement to float collar. Test casing to 3000 psi. Clean out float collar. Displace well to oil based mud prior to W -15 Drilling Program . Page 7 5/16/90 I:.: ~ Exhibit VI- 5c '---"' -"'-" drilling out the re~naining cement, and 9-5/8" float shoe. Condition mud at sho~and drill 8-1/2" hole maintaining directional control as per target map. T~e Baroid RLL tool (EWR/CNPhi/SFD/GR) will be run while drilling the 8-112" hole section, together with a MAD run on the wiper trip after reaching TD (at ROP of 150'jhr or less). ;'"~ Recommended Oil Based Mud Displacement Procedure: a) Drill cement to 9-5/8" shoe and condition water based mud for displacement. : I I ~ (",......,... b) Transport all water based fluids in the surface system to the injection plant for injectìon. c) Clean and flush the mu~ pits and surface equipment. d) Pump 100 bbl of water/dirt magnet spacer. '- e) Pump 75 bbl of EZ Sp'ot spacer and follow with the Oil Based Mud. f) After break through <ti- 200 Electrical Stability), circulate and condition the mud at the shoe pfior to drilling out. ! g) It is recommended to disconnect all sources of water in the pit system to avoid possible contamination of the OBM. I I ~, Oil Based Mud Recommended Properties: Weight: PV: YP: Fluid Loss: Solids: Oil/Water Ratio: Electrical Stability: 9.0 ppg 12-14 cP 8-10 Ib/l00 squft < 8 cc HPHT at 2500P <8% 85/15 - 80/20 > 1 000 V t:: Oil Based Mud Notes: !;) The mud weight while drilling the 8-1/2" hole should be maintained at 9.0 ppg if hole conditions pennit. This mud weight will provide 264 psi overbalance at the top of the Sadlerochit, and 272 psi overbalance at TD. The mud weight should be kept to 9.0 ppg if possible, as the CTC packers are designed to inflate With 750 psi over the mud hydostatic. If the mud hydrostatic gets too high, t.here is a danger that with the addition of the inflation pressure, the packer pressure may be high enough to fracture the fonnation (frac. pressu';"e could be as low as 0.58 psi/ft, which is equal to 5,220 psi at 9000' TVI? BKB). Research and field results have shown that the most effective method of hole cleaning for high' angle wells is by drilling with a "thin" or "low vis" mud in turbulent flow, and pumping "high vis" sweeps as required. W -15 Drilling Program Page 8 5/16/90 4 { Exhibit VI-6: W -17 Well Integrity Report Original Completion Date: 7/5/1988 Schrader Bluff Penetration Hole Diameter: 12-1/4" Schrader Bluff Penetration Casing Diameter: 9-5/8" ( Well Status as of 9/2002: Cement Logs Across Schrader Bluff: Shut-in/Freeze Pròtected/Trouble Well None Comments: This well had a workover performed in Oct. of 1990 to replace the top 2,127 ft. of the 9-5/8' casing and mill out a cement sheath in the 7" liner. On 10/16/90 the 9-5/8' annulus was pressure tested @ 2500 psi for 30 min. and held. Tubing to IA communication first noted in 12/1998. A flowing gas lift survey indicated holes in the tubing at 2250', 2274'and 2672'md. There is cement in the 9-5/8" by 13-3/8" annulus. This is based on the outer annulus pressure test and reports of cement during the work over. ( Exhibit VI-6b Exhibit VI-6c Well Diagram Directional Survey Significant W orkover & Drilling Daily Reports Additional Information: Exhibit VI-6a Exhibit VI - 6a c_ .~ lREE = WELLH&\ 0 = ACT~ TOR = KB. B..EV = BF. REV = KOP= fv'ax An~e =. Datum M) = Datum TVO = 3" WCBlOY WCBl OY 011S 81.62' 53.71' 1484' 52 @ 11848' 11492' 8800' SS (t) W-17 I 13-318" CSG, 72#, L-BO, ID = 12.34 7" H 2854' ~ L Minimum ID = 2.750" @ 2096' 3-1/2" OTIS SSSV NIPPLE I :8: :8: 3-1/2" lBG, 9.2#, L-80, 0.0087 bpf, 10 = 2.992" H 11195' I I I TOPOF7"LNRH 11160' I :=:;:;:-:: .~ 9-5/8" COO, 47#, L-80, ID = 8.681" H 11417' ~ 1 ":>p;:: ~ '~ FERFORA 1l0N SlJv1MARY REF LOG: BHC- GR ON 07/05/88 ANGLEATTOPPERF:50@ 11627' Note: Refer to Production DB for historical perf data SIZE SPF INTER\! AL Opn/Sqz DA 1£ 5" 5 11627-11647 S 05103189 2-1/2" 4 11684-11709 S 09110/90 2-1/2" 4 11653-11673 S 09110/90 2-1/8" 4 11709-11720 S 09/10/90 3-3/8" 6 11684-11710 0 10/14/90 2-1/8" 6 11627-11657 0 02108194 :I. I PBTO H 11932' ~ 7" Lf\.R, 26#, L-80, U4S, 0.0383 bpf, ID = 6.276" H 11973' DATE 9/88 10/16/90 02/09101 03105101 09/05/01 REV BY COMrvENTS ORIGINAL OOMJL ErION JQ ORIGINAL OOMJLErION SIS-QAA OONVERTED TO CANVAS SIS-LG ANAL RN'TP OORRECTIONS Qt\TE RBI BY OOrvtv1ENTS ~.... L SA ÆTY !\OTES 2096' H3-1/2"OT6 SSSV LAND. NP. 10=2.75" ~ GAS UFT MANOOELS ST M) TVD DEV TYPE VLV LATCH FORT" DATE 6 3271 2920 40 OTIS RA 5 7034 5638 47 OTIS RA 4 8772 6922 40 OTIS RA 3 9782 7673 45 OTIS RA 2 10476 8141 48 OTIS RA 1 11076 8533 51 OTIS RA 1110T H 3-1/2" PA ~ER SWS NIp, ID = 2. 750" I 11116' H9-5I8" X 3-112" OTIS PKR 10 = 2.750" I 11162' H3-1/2"PA~ERSWSNIP,10=2.750" I 11183' H3-1/2"PA~ERSWSNIP.ID=2.750" 11195' H3-1/2" WLEG I 11185' H ELMDTTLOGGED02/07/99 FRUCHOE SA Y UNT WB..L: W-17 FERMIT No: 88-0950 APlI'b: 50-029-21856-00 Sec. 21, T11N, R12E 8P Exploration (Alaska) Well'W-17 Directional Survp-" .- '-- Well: I.~~~?. ; ¡ .. _. ._... A Exhibit VI - 6b .. ____ _.. . n..·...._...._.m.. . - .......-........--...-----.---..-----.-----.-...------._..._-~..__._--..._.__..._.._.__.~--- -.._-_..__..._.~.._..._---_..-.-...__._-------_._._--_....--....--.-...---..-.-- API/UWI: 500292185600 Survey Type: GYRO Company: Schlumberger Survey Date: Survey Top: 0' MD Survey Btm: 12,048' MD ------....---+.... - --~.--_. ---. ------------- _._--~-------------- --- -- -.-_._--------- "--" ---.'- MD TVD SS INCLINE AZIMUTH DOGLEG ASP_X ASP_Y 0 0.00 81.60 0.00 0.00 0.0 612,049.3 5,959,490.0 20 20.00 61.60 0.00 0.00 0.0 612,049.3 5,959,490.0 24 23.90 57.70 0.13 71.16 3.3 612,049.3 5,959,490.0 39 38.50 43.10 0.10 116.62 0.6 612,049.3 5,959,490.0 53 53.10 28.50 0.17 152.80 0.7 612,049.3 5,959,490.0 68 67.80 13.80 0.28 141.48 0.8 612,049.5 5,959,490.0 82 82.40 -0.80 0.30 138.60 0.2 612,049.5 5,959,490.0 97 97.10 -15.50 0.28 136.56 0.2 612,049.6 5,959,490.0 112 111. 70 -30.10 0.27 138.71 0.1 612,049.6 5,959,489.6 126 126.30 -44.70 0.22 147.15 0.4 612,049.6 5,959,489.6 141 140.90 -59.30 0.18 160.08 0.4 612,049.6 5,959,489.6 156 155.50 -73.90 0.15 172.97 0.3 612,049.6 5,959,489.6 170 170.20 -88.60 0.15 177.65 0.1 612,049.7 5,959,489.6 185 184.80 -103.20 0.17 171.21 0.2 612,049.7 5,959,489.6 199 199.40 -117.80 0.18 160.77 0.2 612,049.7 5,959,489.6 214 214.00 -132.40 0.20 152.04 0.2 612,049.7 5,959,489.6 229 228.60 -147.00 0.17 148.45 0.2 612,049.7 5,959,489.3 243 243.30 -161.70 0.12 160.36 0.4 612,049.7 5,959,489.3 258 257.60 -176.00 0.10 183.33 0.3 612,049.7 5,959,489.3 272 272.00 -190.40 0.10 190.61 0.1 612,049.7 5,959,489.3 286 286.40 -204.80 0.12 171. 68 0.3 612,049.7 5,959,489.3 301 300.80 -219.20 0.12 150.30 0.3 612,049.7 5,959,489.3 315 315.10 -233.50 0.10 160.04 0.2 612,049.7 5,959,489.3 330 329.50 -247.90 0.10 182.07 0.3 612,049.7 5,959,489.3 344 343.90 -262.30 0.17 184.42 0.5 612,049.7 5,959,489.3 358 358.20 -276.60 0.17 179.44 0.1 612,049.7 5,959,489.3 373 372.60 -291.00 0.13 165.90 0.4 612,049.7 5,959,489.3 387 387.00 -305.40 0.13 151. 79 0.2 612,049.7 5,959,489.3 401 401.40 -319.80 0.15 152.55 0.1 612,049.9 5,959,488.9 416 415.80 -334.20 0.17 163.49 0.3 612,049.9 5,959,488.9 430 430.20 -348.60 0.17 178.96 0.3 612,049.9 5,959,488.9 445 444.50 -362.90 0.15 185.16 0.2 612,049.9 5,959,488.9 459 459.00 -377.40 0.17 177.78 0.2 612,049.9 5,959,488.9 473 473.30 -391. 70 0.17 161.27 0.3 612,049.9 5,959,488.9 488 487.70 -406.10 0.20 150.42 0.3 612,049.9 5,959,488.9 502 502.10 -420.50 0.22 152.88 0.2 612,049.9 5,959,488.9 517 516.50 -434.90 0.20 167.23 0.4 612,049.9 5,959,488.5 531 531.00 -449.40 0.20 181.01 0.3 612,049.9 5,959,488.5 545 545.40 -463.80 0.22 179.09 0.2 612,049.9 5,959,488.5 560 559.80 -478.20 0.22 167.86 0.3 612,049.9 5,959,488.5 574 574.20 -492.60 0.20 154.77 0.4 612,050.0 5,959,488.5 589 588.60 . -507.00 0.18 149.32 0.2 612,050.0 5,959,488.5 603 602.90 -521.30 0.15 157.50 0.3 612,050.0 5,959,488.5 617 617.40 -535.80 0.17 172.49 0.3 612,050.0 5,959,488.5 632 631. 70 -550.10 0.18 172.40 0.1 612,050.0 5,959,488.2 646 646.10 -564.50 0.20 160.09 0.3 612,050.0 5,959,488.2 661 660.60 -579.00 0.20 147.49 0.3 612,050.0 5,959,488.2 675 675.00 -593.40 0.15 145.10 0.4 612,050.0 5,959,488.2 689 689.30 -607.70 0.18 154.49 0.3 612,050.1 5,959,488.2 704 703.80 -622.20 0.18 169.07 0.3 612,050.1 5,959,488.2 7·18 718.20 -636.60 0.15 186.13 0.4 612,050.1 5,959,488.2 733 732.60 -651.00 0.15 - . - -- ì.l 5,959,488.2 ~' 747 747.00 -665.40 ',,-,0.12 \~.1 5,959,488.2 761 761.40 -679.80 0.13 Exhibit VI - 6b .1 5,959,488.2 776 775.90 -694.30 0.17 .1 5,959,487.8 - 790 790.30 -708.70 0.12 ....,...",....,...J.l 5,959,487.8 805 804.70 -723.10 0.12 199.81 0.2 612,050.1 5,959,487.8 819 819.20 -737.60 0.13 191.51 0.1 612,050.1 5,959,487.8 834 833.60 -752.00 0.10 191.19 0.2 612,050.1 5,959,487.8 848 848.00 -766.40 0.05 184.37 0.4 612,050.1 5,959,487.8 862 862.40 -780.80 0.03 181.27 0.1 612,050.1 5,959,487.8 877 876.90 -795.30 0.03 187.54 0.0 612,050.1 5,959,487.8 891 891.30 -809.70 0.05 205.57 0.2 612,050.1 5,959,487.8 - 906 905.70 -824.10 0.05 209.99 0.0 612,050.0 5,959,487.8 920 920.10 -838.50 0.05 192.34 0.1 612,050.0 5,959,487.8 935 934.50 -852.90 0.05 178.24 0.1 612,050.0 5,959,487.8 ...... 949 948.90 -867.30 0.05 173.85 0.0 612,050.0 5,959,487.8 963 963.10 -881. 50 0.05 191. 64 0.1 612,050.0 5,959,487.8 977 977.30 -895.70 0.08 203.56 0.2 612,050.0 5,959,487.8 992 991.50 -909.90 0.10 197.71 0.2 612,050.0 5,959,487.8 - 1,006 1,005.60 -924.00 0.08 188.17 0.2 612,050.0 5,959,487.8 1,020 1,019.80 -938.20 0.07 181.09 0.1 612,050.0 5,959,487.8 1,034 1,034.00 -952.40 0.08 189..82 0.1 612,050.0 5,959,487.8 1,048 1,048.10 -966.50 0.10 205.25 0.2 612,050.0 5,959,487.8 - 1,062 1,062.30 . -980.70 0.10 203.60 0.0 612,050.0 5,959,487.4 1,077 1,076.50 -994.90 0.12 182.40 0.3 612,050.0 5,959,487.4 1,091 1,090.70 -1,009.10 0.13 154.98 0.4 612,050.0 5,959,487.4 1,105 1,104.80 -1,023.20 0.17 142.33 0.4 612,050.0 5,959,487.4 - 1,119 1,119.00 -1,037.40 0.23 136.13 0.4 612,050.1 5,959,487.4 1,133 1,133.20 -1,051.60 0.38 122.21 1.2 612,050.1 5,959,487.4 1,147 1,147.40 -1,065.80 0.65 110.47 2.0 612,050.2 5,959,487.4 ~ 1,162 1,161.49 -1,079.89 0.98 102.12 2.5 612,050.4 5,959,487.4 1,176 1,175.79 -1,094.19 1.38 97.21 2.9 612,050.7 5,959,487.4 1,190 1,189.89 -1/108.29 1.73 93.77 2.6 612,051.1 5,959,487.4 1/204 1/204.08 -1/122.48 2.00 91.88 2.0 612,051.6 5/959/487.1 1,218 1,218.27 -1,136.67 2.30 91.12 2.1 612,052.1 5,959,487.1 1/233 1,232.46 -1/150.86 2.58 90.53 2.0 612,052.7 5,959,487.1 1,247 1,246.64 -1,165.04 2.90 90.43 2.3 612,053.3 5,959,487.1 1,261 1,260.82 -1,179.22 3.27 90.33 2.6 612,054.2 5,959,487.1 ~ 1,275 1/274.89 -1,193.29 3.68 89.86 2.9 612,054.9 5,959,487.1 1/289 1,289.06 -1,207.46 4.12 89.03 3.1 612,055.9 5,959,487.2 1,303 1,303.22 -1,221.62 4.53 88.06 2.9 612,057.0 5,959,487.2 - 1/318 1/317.27 -1,235.67 4.97 87.54 3.1 612,058.2 5,959,487.6 1/332 1/331.41 -1/249.81 5.43 87.35 3.2 612/059.5 5,959,487.6 1/346 1/345.54 -1/263.94 5.90 86.98 3.3 612,060.9 5,959,487.6 1,360 1,359.66 -1/278.06 6.43 86.68 3.7 612,062.5 5,959,487.6 1,374 1,373.76 -1,292.16 6.93 86.21 3.5 612,064.1 5,959,487.6 1,388 1,387.75 -1,306.15 7.43 85.49 3.6 612,065.8 5,959,488.0 1,403 1,401.82 -1,320.22 8.02 84.59 4.2 612,067.8 5,959,488.1 1,417 1,415.87 -1/334.27 8.63 83.57 4.4 612,069.7 5,959,488.5 1,431 1,429.90 -1/348.30 9.17 82.82 3.9 612,072.0 5,959,488.5 1,445 1,444.01 -1,362.41 9.60 82.21 3.1 612,074.2 5,959,488.9 1,460 1,458.00 -1,376.40 10.10 81.50 3.6 612,076.6 5,959,489.3 1,474 1,471.97 -1,390.37 10.63 80.89 3.8 612,079.1 5,959,489.7 1,488 1,486.01 -1,404.41 11.10 80.52 3.3 612,081.8 5,959,490.5 1,502 1,499.94 -1,418.34 11.53 80.19 3.1 612,084.5 5,959,490.9 1/516 1,513.84 -1,432.24 12.05 80.05 3.7 612,087.4 5,959,491.3 ~ 1/531 1,527.81 -1,446.21 12.63 80.13 4.1 612,090.4 5,959,492.1 1,545 1,541.75 -1,460.15 13.25 80.19 4.3 612,093.5 5,959,492.5 1/570 1/566.23 -1,484.63 14.20 80.10 3.8 612,099.4 5,959,493.7 1,600 1/595.16 -1,513.56 15.05 80.00 2.8 612,106.8 5,959,494.9 -.. 1,633 1/626.48 -1/544.88 15.87 79.91 2.5 612,115.3 5,959,496.8 1,670 1,661.88 -1,580.28 16.88 79.94 2.7 612,125.5 5,959,498.8 1,707 1,697.68 -1,616.08 17.82 80.49 2.6 612,136.5 5,959,500.8 1,745 1,733.41 -1,651.81 18.40 81.39 1.7 612,148.1 5,959,502.8 ~ 1,782 1,769.24 -1/687.64 18.78 82.51 1.4 612,159.9 5,959,504.4 1,820 1,805.16 -1,723.56 19.28 83.90 1.8 612,172.2 5,959,506.1 1,858 1/840.96 -1/759.36 19.97 85.19 2.1 612,184.9 5,959,507.7 - 1,897 1,876.68 -1/795.08 20.72 86.10 2.1 612,198.1 5/959/508.7 1/935 1,912.34 -1,830.74 21.28 86.63 1.6 612,211.8 5,959,510.0 --- ---- -------- 1,973 1,947.~0 -1,~ob.20 21.9U ~o.~b 1.0 012,22~.~ ~,9~9,~10.9 2,011 1,983.29 -1,901.69 ""2.75 5,959,511.9 - 2,050 2,018.49 -1,936.89 ,,--,,3.68 5,959,512.8 .~ 2,088 2,053.54 -1,971.94 24.52 Exhibit VI - 6b 5,959,513.8 2,126 2,088.27 -2,006.67 25.35 5,959,514.8 2,165 2,122.93 -2,041.33 26.30 VI...J.J. ,...J VJ.L.,..JV..J.:1 5,959,515.7 2,203 2,157.10 -2,075.50 27.37 87.19 2.8 612,321.1 5,959,516.7 2,241 2,191.03 -2,109.43 28.48 87.07 2.9 612,339.0 5,959,518.1 2,280 2,224.59 -2,142.99 29.65 87.08 3.1 612,357.7 5,959,519.1 2,318 2,257.69 -2,176.09 30.80 87.20 3.0 612,376.9 5,959,520.5 2,356 2,290.40 -2,208.80 31.85 87.39 2.8 612,396.8 5,959,521.9 2,394 2,322.43 -2,240.83 32.78 87.60 2.5 612,417.0 5,959,522.9 2,432 2,353.90 -2,272.30 33.58 87.88 2.2 612,437.6 5,959,524.0 2,470 2,385.17 -2,303.57 34.37 88.20 2.2 612,458.6 5,959,525.0 2,507 2,416.11 -2,334.51 35.28 88.39 2.4 612,480.2 5,959,526.1 2,545 2,446.68 -2,365.08 36.37 88.51 2.9 612,502.2 5,959,527.1 2,583 2,476.85 -2,395.25 37.33 88.63 2.6 612,524.7 5,959,527.8 2,620 2,506.61 -2,4'25.01 38.02 88.82 1.9 612,547.7 5,959,528.5 2,658 2,536.20 -2,454.60 38.57 88.96 1.5 612,571.0 5,959,529.6 2,696 2,565.48 -2,483.88 39.13 88.86 1.5 612,594.6 5,959,530.3 - 2,733 2,594.59 -2,512.99 39.78 88.23 2.0 612,618.6 5,959,531.4 2,771 2,623.35 -2,541.75 40.40 86.89 2.8 612,642.7 5,959,532.5 2,809 2,651.89 -2,570.29 40.85 85.30 3.0 612,667.2 5,959,534.7 2,846 2,680.35 -2,598.75 41.13 84.05 2.3 612,691.7 5,959,537.3 2,884 2,708.46 -2,626.86 41.40 83.53 1.2 612,716.2 5,959,540.2 2,921 2,736.56 -2,654.96 41.52 83.49 0.3 612,740.9 5,959,543.5 2,959 2,764.67 -2,683.07 41.40 83.48 0.3 . 612,765.4 5,959,546.8 2,996 2,793.00 -2,711.40 41.15 83.49 0.7 612,790.2 5,959,550.1 3,034 2,821.35 -2,739.75 40.98 83.50 0.5 612,814.6 5,959,553.0 3,071 2,849.61 -2,768.01 40.88 83.49 0.3 612,838.9 5,959,556.3 3,108 2,877.62 -2,796.02 40.70 83.47 0.5 612,862.9 5,959,559.3 3,145 2,905.61 -2,824.01 40.65 83.45 0.1 612,886.7 5,959,562.5 3,182 2,933.68 -2,852.08 40.62 83.44 0.1 612,910.6 5,959,565.5 3,219 2,961. 72 -2,880.12 40.48 83.42 0.4 612,934.4 5,959,568.8 3,256 2,989.87 -2,908.27 40.47 83.41 0.0 612,958.2 5,959,571.7 3,293 3,018.03 -2,936.43 40.40 83.47 0.2 612,982.1 5,959,575.0 3,330 3,046.23 -2,964.63 40.27 83.53 0.4 613,005.8 5,959,577.9 3,367 3,074.47 -2,992.87 40.25 83.57 0.1 613,029.6 5,959,580.8 3,404 3,102.65 -3,021.05 40.17 83.66 0.3 613,053.1 5,959,584.1 3,441 3,130.97 -3,049.37 39.93 83.74 0.7 613,076.8 5,959,587.0 3,478 3,159.45 -3,077.85 39.80 83.79 0.4 613,100.3 5,959,589.9 3,515 3,187.80 -3,106.20 39.80 83.82 0.1 613,123.9 5,959,592.8 3,552 3,216.23 -3,134.63 39.75 83.81 0.1 613,147.3 5,959,595.8 3,589 3,244.72 -3,163.12 39.58 83.80 0.5 613,170.7 5,959,598.7 3,626 3,273.34 -3,191.74 39.43 83.80 0.4 613,194.1 5,959,601.6 3,663 3,301.96 -3,220.36 39.25 83.82 0.5 613,217.4 5,959,604.1 3,700 3,330.50 -3,248.90 39.03 83.84 0.6 613,240.5 5,959,607.0 3,737 3,359.24 -3,277.64 39.02 83.90 0.1 613,263.6 5,959,610.0 3,773 3,387.52 -3,305.92 39.02 84.01 0.2 613,286.3 5,959,612.9 3,810 3,415.72 -3,334.12 39.05 84.13 0.2 613,309.1 5,959,615.4 3,846 3,443.82 -3,362.22 39.10 84.23 0.2 613,331.7 5,959,618.3 3,882 3,471.90 -3,390.30 39.18 84.36 0.3 613,354.5 5,959,620.8 3,918 3,500.03 -3,418.43 39.22 84.48 0.2 613,377.2 5,959,623.4 3,955 3,528.16 -3,446.56 39.20 84.50 0.1 613,400.0 5,959,625.9 3,991 3,556.26 -3,474.66 39.35 84.46 0.4 613,422.9 5,959,628.5 4,027 3,584.38 -3,502.78 39.47 84.38 0.4 613,445.9 5,959,631.0 4,064 3,612.47 -3,530.87 39.53 84.26 0.3 613,468.9 5,959,633.5 4,100 3,640.38 -3,558.78 39.58 84.26 0.1 613,491. 7 5,959,636.5 4,136 3,668.43 -3,586.83 39.58 84.34 0.1 613,514.8 5,959,639.0 4,173 3,696.43 -3,614.83 39.48 84.40 0.3 613,537.7 5,959,641.5 4,209 3,724.44 -3,642.84 39.52 84.4 7 0.2 613,560.6 5,959,644.1 4,245 3,752.43 -3,670.83 39.57 84.50 0.2 613,583.7 5,959,646.6 4,281 3,780.32 -3,698.72 39.67 84.53 0.3 613,606.6 5,959,649.2 4,318 3,808.23 -3,726.63 39.80 84.61 0.4 613,629.7 5,959,651. 7 4,354 3,836.13 -3,754.53 39.78 84.75 0.3 613,652.7 5,959,654.3 4,390 3,863.96 -3,782.36 39.72 84.87 0.3 613,675.8 5,959,656.8 4,426 3,891.65 -3,810.05 39.72 84.92 0.1 613,698.7 5,959,659.0 4,462 3,919.02 -3,837.42 39.77 85.06 0.3 613,721.3 5,959,661.5 4,497 3,946.31 -3,864.71 39.78 85.24 0.3 613,743.9 5,959,663.7 4,533 3,973.68 -3,892.08 39.70 85.37 0.3 613,766.6 5,959,665.9 .. --.... -- ...... "'..,.., ...... ,. ....... -,"'''' ..... r- nrn ,..,.n n <+, ::¡0:1 <+,UU~.UO -..),:1 ~ :1.<+0 ,,):1.0,,) 0:>.<+:> U.L O~..),/O:1.L :>,:1:>:1,OOO.U 4,604 4,028.52 -3,946.92 19.55 85.50 0.2 613,p11.8 5,959,670.2 4,640 4,055.89 -3,974.29 ___/9.57 "~' 5,959,672.4 4,675 4,083.29 -4,001.69 39.78 5,959,674.6 4,711 4,110.62 -4,029.02 39.93 Exhibit VI - 6b 5,959,676.4 4,746 4,137.87 -4,056.27 40.15 5,959,678.5 4,782 4,164.87 -4/083.27 40.47 U..J.V..J V.::1 UJ.JI:;J¿,J·J 5,959/680.7 4/817 4,191.90 -4,110.30 40.73 85.84 0.8 613,948.3 5,959,682.9 4,853 4/218.74 -4,137.14 41.02 85.97 0.9 613,971.4 5/959/685.1 4/889 4,245.55 -4/163.95 41.25 86.08 0.7 613,994.8 5/959,686.9 4/924 4/272.20 -4/190.60 41.47 86.27 0.7 614/018.1 5/959/688.7 4/959 4/298.68 -4/217.08 41. 70 86.45 0.7 614,041.6 5/959/690.5 4/995 4/325.06 -4/243.46 41.93 86.51 0.7 614/065.1 5,959/692.4 5/030 4/351.35 -4,269.75 42.13 86.56 0.6 614/088.7 5/959,694.2 5,066 4,377.49 -4/295.89 42.35 86.68 0.7 614,112.4 5,959/696.0 5,100 4,403.08 -4/321.48 42.62 86.79 0.8 614/135.8 5/959,697.8 5/135 4,428.56 -4,346.96 42.85 86.82 0.7 614/159.3 5,959,699.3 5/170 4A53.88 -4/372.28 43.10 86.82 0.7 614,182.8 5,959,701.1 5,204 4,479.21 -4/397.61 43.50 86.93 1.2 614,206.6 5,959,702.6 5,239 4,504.23 -4A22.63 43.85 87.10 1.1 614/230.4 5,959,704.0 5,274 4/529.19 -4A47.59 44.17 87.23 1.0 614/254.5 5,959/705.8 5,308 4,554.01 -4A72.41 44.50 87.34 1.0 614/278.7 5/959/707.3 5/343 4,578.69 -4,497.09 44.8b 87.45 0.9 614/303.1 5,959/708.8 5/378 4/603.20 -4,521.60 45.02 87.59 0.7 614/327.4 5,959,710.3 5,412 4,627.65 -4/546.05 45.37 87.77 1.1 614,352.0 5/959,711.4 5,447 4,651.86 -4,570.26 45.82 87.91 1.3 614/376.7 5,959/712.8 5,482 4/675.91 -4,594.31 46.12 88.00 0.9 614A01.6 5/959,713.9 5,516 4,699.83 -4/618.23 46.40 88.08 0.8 614A26.5 5,959,715.4 5,551 4,723.62 -4,642.02 46.75 88.13 1.0 614,451.7 5/959,716.5 5,585 4,747.21 -4/665.61 46.95 88.21 0.6 614,476.7 5/959/717.7 5,620 4/770.82 -4,689.22 47.00 88.28 0.2 614,502.0 5,959/718.8 5,654 4/794.33 -4/712.73 47.08 88.30 0.2 614,527.2 5/959/719.9 5,689 4,817.80 -4/736.20 47.20 88.35 0.4 614,552.5 5,959/721.0 5,723 4,841. 11 -4,759.51 47.18 88.45 0.2 614,577.7 5/959,722.1 5,757 4/864.05 -4,782.45 47.30 88.52 0.4 614,602.5 5,959¡l23.2 5/791 4,886.95 -4,805.35 47.43 88.58 0.4 614/627.3 5/959,724.3 5/825 4,909.92 -4,828.32 47.27 88.68 0.5 614/652.2 5,959,725.1 5,859 4,932.99 -4,851.39 47.27 88.79 0.2 614/677.2 5/959/726.2 5/893 4,955.98 -4,874.38 47.63 88.92 1.1 614/702.2 5,959,726.9 5,927 4,978.76 -4/897.16 47.93 89.10 1.0 614/727.3 5/959/727.7 5/961 5,001.50 -4/919.90 48.12 89.34 0.8 614,752.6 5/959,728.4 5,995 5/024.18 -4/942.58 48.20 89.55 0.5 614¡l77.9 5,959,729.2 6/029 5/046.85 -4,965.25 48.17 89.66 0.3 614/803.2 5,959,729.6 6,063 5/069.50 -4,987.90 48.28 89.78 0.4 614/828.5 5,959,730.0 6/097 5,092.12 -5,010.52 48.30 89.92 0.3 614/853.9 5,959/730.7 6,131 5,114.80 -5/033.20 48.30 90.07 0.3 614/879.4 5/959,731.1 6/165 5,137.39 -5,055.79 48.43 90.20 0.5 614/904.8 5/959,731.1 6/199 5,159.94 -5,078.34 48.50 90.26 0.2 614,930.3 5/959,731.5 6,233 5,182.50 -5,100.90 48.65 90.39 0.5 614,955.8 5,959,731.9 6/267 5/204.92 -5,123.32 48.83 90.50 0.6 614,981.4 5/959¡l31.9 6/301 5/227.30 -5,145.70 48.87 90.45 0.2 615/006.9 5/959/732.3 6/335 5/249.69 -5,168.09 48.73 90.36 0.5 615/032.6 5,959,732.4 6/368 5,271.80 -5/190.20 48.67 90.36 0.2 615/057.7 5,959,732.7 6A02 5/293.80 -5/212.20 48.65 90.38 0.1 615,082.8 5,959,732.8 6A35 5,315.88 -5/234.28 48.57 90.36 0.2 615,107.8 5,959,733.1 6A68 5,337.93 -5,256.33 48.48 90.32 0.3 615,132.8 5,959,733.2 6/502 5,360.07 -5/278.47 48.50 90.31 0.1 615,157.7 5,959,733.5 6/535 5/382.23 -5,300.63 48.35 90.35 0.5 615,182.8 5,959,733.6 6/568 5,404.35 -5,322.75 48.10 90.40 0.8 615,207.5 5,959,733.9 6/602 5A26.62 -5/345.02 47.98 90.44 0.4 615/232.3 5,959,734.0 6/635 5A48.94 -5,367.34 47.85 90.42 0.4 615,257.0 5,959/734.3 6/668 5A71.23 -5/389.63 47.78 90.32 0.3 615/281.6 5,959/734.3 6/701 5A93.62 -5A12.02 47.70 90.16 0.4 615,306.3 5,959/734.7 6,735 5,515.99 -5,434.39 47.60 90.03 0.4 615/330.7 5/959/735.1 6,768 5,538.46 -5,456.86 47.52 89.96 0.3 615,355.3 5,959,735.5 ~ 6,801 5,560.98 -5,479.38 47.37 89.88 0.5 615,379.8 5,959/735.9 6,834 5,583.57 -5,501.97 47.2C 89.75 O.S 61S,~04.3 5,959;736.2 6,368 5,606.20 -5,524.60 47.12 89.61 0.3 6 1 ~-:!.:+ 28. 7 5,959,737.C 6,901 5,628.83 -5,547.23 47.18 89.4 7 0.3 E: ~-J453.2 5,959/737.3 6,934 5/651.43 -5,569.83 47.03 89.40 0.5 615,477.5 5/959/738.1 C nc '7 C C'7A 1 ") _c;: c;:a') c;:') .d. ç:; 7 c;: Qa ~ç:; na ç:; 1 c;: c;:n 1 7 c;: ac;:a 7~Q c;: ...."-,,,,, -',...."... ~"- ....JI-'J&-·w'" v.a..-'I-'V.a..., oJ,J-'-', I -''-'.oJ 7,ÒOO 5,696.48 -5,614.88 46.63 89.25 0.4 615.5')E).4 5,959,739.2 7,033 5,718.88 -5,637.28 6.57 5,959,739.9 7,065 5,741.32 -5,659.72 46.42 .~ 5,959,740.7 7,098 5,763.84 -5,682.24 46.23 Exhibit VI - 6b 5,959,741.4 7,131 5,786.50 -5,704.90 46.03 5,959,742.1 7,163 5,809.13 -5,727.53 46.02 ~9.12 0.1 615,643.3 5,959,742.8 7,196 5,831.78 -5,750.18 45.98 89.09 0.1 615,666.7 5,959,743.6 7,228 5,854.46 -5,772.86 45.87 89.08 0.3 615,690.2 5,959,744.3 7,261 5,877.25 -5,795.65 45.73 89.11 0.4 615,713.6 5,959,745.0 7,294 5,900.03 -5,818.43 45.65 89.16 0.3 615,736.9 5,959,745.7 7,326 5,922.91 -5,841.31 45.55 89.18 0.3 615,760.3 5,959,746.1 7,359 5,945.90 -5,864.30 45.43 89.08 0.4 615,783.6 5,959,746.8 7,392 5,968.85 -5,887.25 45.40 89.01 0.2 615,807.0 5,959,747.6 7,424 5,991. 75 -5,910.15 45.35 89.03 0.2 615,830.2 5,959,748.6 7,457 6,014.75 -5,933.15 45.28 88.98 0.2 615,853.4 5,959,749.4 7,490 6,037.77 -5,956.17 45.22 88.91 0.2 615,876.6 5,959,750.1 7,522 6,060.75 -5,979.15 45.12 88.89 0.3 615,899.7 5,959,750.8 7,555 6,083.86 -6,002.26 44.95 88.81 0.6 615,922.7 5,959,751.5 7,587 6,106.67 -6,025.07 44.83 88.66 0.5 615,945.5 5,959,752.6 7,619 6,129.45 -6,047.85 44.78 88.61 0.2 615,968.0 5,959,753.3 7,652 6,152.26 -6,070.66 44.67 88.60 0.3 615,990.6 5,959,754.0 7,684 6,175.06 -6,093.46 44.42 88.51 0.8 616,013.1 5,959,755.1 7,716 6,198.03 -6,116.43 44.22 88.43 0.7 616,035.6 5,959,756.2 7,748 6,220.98 -6,139.38 44.13 88.46 0.3 616,057.8 5,959,756.9 7,780 6,244.05 -6,162.45 43.98 88.60 0.6 616,080.1 5,959,758.0 7,812 6,267.21 -6,185.61 43.68 88.78 1.0 616,102.3 5,959,758.7 7,844 6,290.51 -6,208.91 43.20 88.94 1.5 616,124.3 5,959,759.4 7,876 6,313.92 -6,232.32 42.80 89.08 1.3 616,146.1 5,959,760.1 7,908 6,337.47 -6,255.87 42.43 89.36 1.3 616,167.9 5,959,760.8 7,940 6,361.23 -6,279.63 42.05 89.69 1.4 616,189.4 5,959,761.1 7,972 6,385.07 -6,303.47 41.63 89.98 1.4 616,210.7 5,959,761.8 8,004 6,409.07 -6,327.47 41.22 90.29 1.4 616,232.0 5,959,761.8 8,036 6,433.28 -6,351.68 40.82 90.58 1.4 616,252.9 5,959,762.1 8,068 6/457.59 -6/375.99 40.33 90.89 1.7 616,273.8 5,959,762.1 8,100 6/481.98 -6,400.38 39.93 91.27 1.5 616,294.3 5,959,762.0 8,132 6,506.53 -6,424.93 39.85 91.49 0.5 616,314.9 5,959,762.0 8,164 6,531.09 -6,449.49 39.92 91.46 0.2 616,335.4 5,959,761.6· 8,195 6,555.19 -6,473.59 39.80 91.44 0.4 616,355.6 5,959,761.5 8,227 6/579.28 -6,497.68 39.55 91.51 0.8 616,375.5 5,959,761.1 8,258 6,603.45 -6,521.85 39.35 91.50 0.6 616,395.4 5,959,761.0 8,289 6,627.69 -6,546.09 39.15 91.52 0.6 616,415.2 5,959,760.6 8,321 6,652.00 -6,570.40 38.95 91.60 0.7 616,434.9 5,959,760.6 8,352 6,676.39 -6,594.79 38.68 91.50 0.9 616,454.5 5,959,760.5 8,383 6/700.84 -6,619.24 38.55 91.29 0.6 616,474.0 5,959,760.1 8,415 6,725.30 -6,643.70 38.65 91.16 0.4 616,493.5 5,959,760.0 8,446 6,749.80 -6,668.20 38.82 91.14 0.5 616,513.2 5,959,759.9 8,477 6,774.23 -6,692.63 38.97 91.18 0.5 616,532.9 5,959,759.9 8,509 6/798.63 -6,717.03 39.07 91.35 0.5 616,552.7 5,959,759.8 8,540 6,823.10 -6,741.50 39.00 91.37 0.2 616,572.6 5,959,759.4 8,572 6,847.45 -6,765.85 38.87 91.17 0.6 616,592.2 5,959,759.3 8,603 6,871.97 -6,790.37 38.88 91.14 0.1 616,612.0 5,959,759.3 8,634 6/896.41 -6,814.81 38.88 91.35 0.4 616,631.8 5,959,759.2 8,666 6,920.84 -6,839.24 38.93 91.61 0.5 616,651.4 5,959,758.8 8,697 6,945.25 -6,863.65 39.08 91. 74 0.5 616,671.2 5,959,758.7 8,729 6,969.68 -6,888.08 39.20 91.67 0.4 616,691.0 5,959,758.3 8,760 6,993.76 -6,912.16 39.33 91.69 0.4 616,710.7 5,959,757.9 8,791 7,017.55 -6,935.95 39.53 91.90 0.8 616,730.3 5,959,757.8 8,821 7,041.28 -6,959.68 39.68 92.06 0.6 616,750.0 5,959,757.4 8,852 7/064.88 -6,983.28 39.85 92.17 0.6 616,769.6 5,959,757.0 8,883 7/088.41 -7,006.81 40.00 92.34 0.6 616,789.3 5,959,756.5 8,914 7,112.00 -7,030.40 40.08 92.53 0.5 616,809.0 5,959,755.7 8,944 7,135.48 -7,053.88 40.12 92.63 0.3 616,828.8 5,959,755.3 8,975 7,159.04- -7,077.44 40.08 92.63 0.1 616,848.7 5,959,754.5 9,006 7,182.52 -7,100.92 40.10 92.71 0.2 615,868.5 5,959,754.1 9,037 7/206.08 -7,124.48 40.13 92.96 0.5 616,888.2 5,959,753.3 a nc:..7 7,27J.53 -7,147.93 ¿10.2~ 93.08 OA E< c:. ?OS.O 5,959,752.5 .j! >..J ._- ! 9,098 7,2S2.97 -7,171.37 .:10.3'=' 93.25 n / 6::.::/~<27.9 5,959,751.7 V.-~ 9,129 7,276.38 -7,194.78 40.30 93.69 0.9 616,9¿17.7 5,959,750.9 9/159 7,299.78 -7,218.18 40.35 93.97 0.6 616,967.6 5,959/749.8 1'I 1 1'I" ï ";2")";2 1 t:. _ 7 ')¿11 ¡:;¡; ¿1n ¡:;n QA. 11:\ O_n 616.987.5 5.959.748.6 9,221 7,346.46 -7,264.86 40.70 94.46 0.9 617 ,on7.4 5,959,747.5 9,252 7,369.70 -7,288.10 ~0.93 94.73 0.9 617,'.4 5,959,746.3 9,282 7,392.85 -7,311.25 ---'41.17 "-'. 5,959,744.8 9,313 7,415.91 -7,334.31 41.43 5,959,743.3 9,343 7,438.49 -7,356.89 41.82 Exhibit VI - 6b 5,959,741.8 9,373 7,460.84 -7,379.24 42.30 5,959,739.9 9,403 7,482.94 -7,401.34 42.80 ~b.lb l.ö bl/,lLö.l 5,959,738.0 9,433 7,504.96 -7,423.36 43.13 96.52 1.4 617,148.5 5,959,736.1 9,463 7,526.89 -7,445.29 43.37 96.96 1.3 617,169.0 5,959,733.9 9,493 7,548.72 -7,467.12 43.60 97.29 1.1 617,189.5 5,959,731. 7 9,524 7,570.49 -7,488.89 43.78 97.39 0.6 617,210.2 5,959,729.4 9,554 7,592.18 -7,510.58 44.00 97.41 0.7 617,230.9 5,959,727.2 9,584 7,613.78 -7,532.18 44.25 97.44 0.8 617,251.8 5,959,724.6 9,614 7,635.24 -7,553.64 44.45 97.52 0.7 617,272.5 5,959,722.3 9,644 7,656.76 -7,575.16 44.68 97.61 0.8 617,293.6 5,959,719.7 9,674 7,678.12 -7,596.52 44.92 97.68 0.8 617,314.6 5,959,717.1 9,704 7,699.39 -7,617.79 45.12 97.62 0.7 617,335.8 5,959,714.9 9,734 7,720.61 -7,639.01 45.22 97.51 0.4 617,357.1 5,959,712.3 9,765 7,741.86 -7,660.26 45.38 97.56 0.5 617,378.3 5,959,709.7 9,795 7,762.98 -7,681.38 45.50 97.76 0.6 617,399.6 5,959,707.1 9,825 7,784.07 -7,702.47 45.55 97.97 0.5 617,420.9 5,959,704.5 9,855 7,805.12 -7,723.52 45.63 98.19 0.6 617,442.3 5,959,701. 9 9,885 7,826.07 -7,744.47 45.78 98.39 0.7 617,463.6 5,959,699.0 9,914 7,846.54 -7,764.94 46.03 98.58 1.0 617,484.5 5,959,696.4 9,944 7,866.97 -7,785.37 46.30 98.77 1.0 617,505.5 5,959,693.4 9,973 7,887.22 -7,805.62 46.60 98.91 1.1 617,526.7 5,959,690.4 10,003 7,907.40 -7,825.80 47.08 99.02 1.7 617,548.0 5,959,687.5 10,032 7,927.35 -7,845.75 47.50 99.18 1.5 617,569.4 5,959,684.1 10,061 7,947.15 -7,865.55 47.75 99.38 1.0 617,590.8 5,959,681.2 10,091 7,966.96 -7,885.36 47.90 99.56 0.7 617,612.5 5,959,677.9 10,120 7,986.74 -7,905.14 47.90 99.71 0.4 617,634.0 5,959,674.5 10,150 8,006.51 -7,924.91 47.93 99.82 0.3 617,655.7 5,959,671.2 10,179 8,026.18 -7,944.58 48.10 99.84 0.6 617,677.2 5,959,667.5 10,209 8,045.83 -7,964.23 48.35 99.80 0.9 617,699.0 5,959,664.2 10,238 8,065.33 -7,983.73 48.57 99.76 0.8 617,720.8 5,959,660.9 10,268 8,084.83 -8,003.23 48.67 99.68 0.4 617,742.6 5,959,657.6 10,297 8,104.32 -8,022.72 48.63 99.66 0.2 617,764.5 5,959,653.9 10,327 8,123.82 -8,042.22 48.65 99.76 0.3 617,786.4 5,959,650.6 10,356 8,143.24 -8,061.64 48.63 99.93 0.4 617,808.2 5,959,647.2 10,385 8,162.68 -8,081.08 48.55 100.08 0.5 617,830.0 5,959,643.6 10,415 8,182.18 -8,100.58 48.38 100.23 0.7 617,851.7 5,959,640.2 10,444 8,201.54 -8,119.94 48.20 100.39 0.7 617,873.1 5,9~9,636.6 10,473 8,220.77 -8,139.17 48.02 100.64 0.9 617,894.3 5,959,632.9 10,502 8,240.07 -8,158.47 47.83 100.90 0.9 617,915.3 5,959,629.2 10,530 8,259.44 -8,177.84 47.65 101.08 0.8 617,936.3 5,959,625.5 10,559 8,278.88 -8,197.28 47.47 101.34 0.9 617,957.2 5,959,621.8 10,588 8,298.34 -8,216.74 47.47 101.67 0.8 617,978.0 5,959,617.7 10,617 8,317.77 -8,236.17 47.67 101.87 0.9 617,998.9 5,959,613.6 10,646 8,337.13 -8,255.53 47.83 102.08 0.8 618,019.9 5,959,609.6 10,674 8,356.42 -8,274.82 48.07 102.36 1.1 618,040.8 5,959,605.5 10,703 8,375.61 -8,294.01 48.42 102.61 1.4 618,061.9 5,959,601.1 10,732 8,394.64 -8,313.04 48.82 102.91 1.6 618,082.9 5,959,596.7 10,761 8,413.53 -8,331. 93 49.22 103.14 1.5 618,104.3 5,959,592.2 10,790 8,432.33 -8,350.73 49.62 103.26 1.4 618,125.7 5,959,587.4 10,818 8,450.93 -8,369.33 49.92 103.29 1.1 618,147.1 5,959,582.7 10,847 8,469.43 -8,387.83 50.13 103.32 0.7 618,168.7 5,959,577.9 10,876 8,487.86 -8,406.26 50.30 103.36 0.6 618,190.3 5,959,573.1 10,905 8,506.29 -8,424.69 50.48 103.27 0.7 618,212.1 5,959,568.3 10,934 8,524.53 -8,442.93 50.62 103.18 0.5 618,233.8 5,959,563.5 10,962 8,542.78 -8,461.18 50.70 103.16 0.3 618,255.5 5,959,558.7 10,991 8,560.57 -8,478.97 50.78 103.20 0.3 618,276.8 5,959,554.3 11,018 8,578.14 -8,496.54 50.77 103.28 0.2 618,297.7 5,959,549.5 11,046 8,595.62 -8,514.02 50.65 103.46 0.7 618,318.7 5,959,544.7 11,066 8,C08.36 -8,526.76 50.70 103.60 0.6 618,333.8 5,959,541.3 11,085 8,620.45 -8,538.85 50.77 103.76 0.7 612,:>~8.3 5,959,538.2 11,::(\~ 8.632.53 -8,550.93 50.7C 103.97 o 0 é< ~·,3;S2.7 5,959,534.8 1 ~ I :. ~; 3 c. ,'- - ,1 r:--~ -8,562.97 104.17 O.~ - -. 376.--; 5/i~S9/531.~ ~ 1"-- - . - I ~ 11,1-;'2 8,G5+S.0·j -8,575.09 50.=:2 104.38 0.9 61J,~·':l.3 Sf95:;/~27.9 11,161 8,668.82 -8,587.22 50.58 104.55 0.7 618,405.7 5,959,524.5 1 1 1 A 1 A ¡;AfI Qd -R I:\Qq ~d t;n hR 1()4hq nR hlR.41Q.q S.QSQ.S71.1 11,200 8,693.06 -8,611.46 50.57 104.83 0.8 618,434.3 5,959,517.6 ·1 ì,220 8,705.91 -8,624.31 '0.40 5,959,513.8 11,244 8,721.15 -8,639.55 "'-dO. 35 '-" 5,959,509.4 11,268 8,736.61 -8,655.01 50.23 Exhibit VI - 6b 5,959,504.5 11,292 8,752.10 -8,670.50 50.22 5,959,499.7 11/317 8,767.72 -8/686.12 50.15 .L v .J . ::7"::1 .L..L O.Lö/:>L1.4 5/959,494.8 11,341 8/783.46 -8,701.86 49.95 106.23 1.1 618,539.5 5/959,490.0 11/366 8,799.32 -8,717.72 49.73 106.60 1.5 618/557.6 5/959,485.2 11/390 8,815.40 -8/733.80 49.42 107.01 1.8 618/575.8 5/959,480.0 11,415 8,831.55 -8/749.95 49.27 107.30 1.1 618/593.8 5/959,474.4 11,440 8,847.66 -8,766.06 49.33 107.55 0.8 618,611.8 5,959,469.2 11,465 8,863.74 -8,782.14 49.43 107.66 0.5 618/629.7 5,959,463.6 11,489 8,879.79 -8/798.19 49.55 107.61 0.5 618/647.7 5/959,458.4 11/514 8,895.47 -8,813.87 49.68 107.61 0.5 618/665.4 5,959,453.2 11/538 8/911.05 -8/829.45 49.78 107.70 0.5 618/682.9 5/959,447.6 11,562 8/926.66 -8,845.06 49.83 107.76 0.3 618,700.7 5,959,442.4 11/586 8,942.28 -8,860.68 49.77 107.71 0.3 618/718.3 5/959,437.2 11,610 8,957.92 -8,876.32 49.72 107.54 0.6 618/736.0 5,959,431.6 11,634 8,973.48 -8,891.88 49.87 107.41 0.8 618/753.7 5,959,426.4 11/659 8,989.04 -8,907.44 50.10 107.40 1.0 618,771.4 5,959,421.2 11,683 9,004.53 -8,922.93 50.30 107.41 0.8 618/789.3 5/959/416.0 11,707 9,019.94 -8,938.34 50.60 107.34 1.3 618/807.1 5/959,410.4 11,731 9,035.20 -8,953.60 50.88 107.24 1.2 618/825.0 5,959,405.2 11/755 9,050.41 -8,968.81 51.20 107.13 1.4 618,843.1 5/959,400.0 11,779 9,065.52 -8,983.92 51.52 107.07 1.3 618/861.2 5/959/394.8 11,803 9,080.22 -8,998.62 51. 77 107.04 1.1 618/879.1 5/959/389.6 11,822 9,091. 77 -9,010.17 51.93 107.03 0.9 618,893.2 5/959,385.4 11,837 9,101.32 -9,019.72 52.03 107.05 0.7 618/904.9 5/959,381.9 11,848 9, 107.84 -9,026.24 52.07 106.99 0.6 618/913.0 5,959,379.5 11,948 9,169.31 -9,087.71 52.07 106.99 0.0 618,988.8 5,959/357.6 12,048 9,230.78 -9,149.18 52.07 106.99 0.0 619,064.5 5,959,335.8 bbl b6C. -- t.AI ~OLLUTION f~'N) 3, ~ ¡ 7::'-8" 3 ~ ID I lENGTH ! 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I dlf ¡u I ~ ~fItI 3tO - ... ~ / -, 'TQT A" Þ(IISQHHI" .;tB ISAIIC ~ I CONTRACTOR ,;t.::t I CATERINa ,c¿J~t- o//¿I I I ~~ ~/3ô ~ .:J()¿> ()¥&Jð P~CJo I .I ,.... #>.. ......-.... .- .... % 9ô ~ I .3~ f' It) g¡ I ~ r ¿) ~ I I I c, 9' 10 ~ A ô,#. / ¿4::; Øo¿Jd ¥o ':~;;?¡?..cå)-s2JÆ/c.:(.. ~/P-£ ~ I VS-) 4:L'f_"._ 2,e./i..L CcLéJ:J~ ,._ I ~ 910 ss-· Â//;O"o,-6' ~...JA/ A.s~ ~ /=¿·~L./;t/ß/ 'v;,I'tI',£S S/h.o T/A.JÓ ;C£:AA./$~ ACTMT'Y lOG 'i : ~IOEHTI "'/HI I N I POUUT1ON (v/HI I AI" ~c/. C/"è.c.//n_~¿ , C¿6A'AJ ~ P"-:'s 25,..e" ~ ,,~ /¿;J.//. / S.¿.~, L.4y 2Jc>4!...J/V Z r ~ ~r'~:~ nCk ¿/¡Ik? 7h ¿7TS £:'.7.#. (6t!:>;" /A./S,/2JE: L/A/EH-. ) .» to/ £~. 7Z> //..2.37 ?lE-s-r ¿".Il/6Æ.. LAiO ~ '1'~ Mrz:.// "72:> .3ó~6/S7. Goo~ 7""'E s r:- f...Þ7 · ., I TRBLE COST I 1= ITRU ¡COST I~~~IC WAfEA '"- IItII USEO IAYA~ lEas I ". 3 I SER't~ co. _. I / I OTHER '-' Exhibit VI - Be ---/ PBU/F.WF. DRTI ,I ,ING PROGRAM PROPOSF.O WRI J, DIAGRAM :!£ELI, W-17 (11-23-11-12) NABORS 22E CEMENTATION: ~I ~¡¡ L. Condue"" 13 3/S" CASING: .-13 3/S" 6S# L-SO Butt. /" 4128 cu ft (4438 sacks) PERMAFROST Base Pennairost 1942' JIIIIII . 3-1/2" Ball Valve 1992' ~ w/ Flow Couplings .... 13 318" Shoe 2809' 17 1/2" Open Hole 2829' ~ 9 5/S" CASING: 1 st. Stage: ~9 518" 47# L-SO NSCC Lea1 Slurry: IS90 cu ft (1000 sIcs) Class G (see program for details) _ .-XO: 9 5/S" 47# L-SO NSCC Box X Butt. Pin 5352' Tail Slurry: 575 cuft (500 sIcs) Class G (see program for details) I 280 cuft PERMAFRO~T C cement followed by dry crude downsqueeze ! . 3 1/2" 9.3# L-80 NB Mod. EUE with GLMs 2nd. Stage 9 5/S" 47# L-80 Butt. 7" LINER: Slurry: 251 cuft (213 sIcs) Class G (see program) Sliding Sleeve 11016' .. BATCH MIX ~,z TIW 9 518" Packer 11056' 31/2" COMPLETION: 3 1/8" ClW Tree KOP: 1200' , ~ I I ...... ,. ~ Lindsey Liner Hanger 11106' 9 5/S" Casing Shoe 121/4" Open Hole 11356' 11361' WELLHEAD: McEvoy 7" 26# L-80 U4S Liner 7" Marker Joint 114S0' TAILPIPE SIZE: 3 1(2" 7" Liner Shoe 11892' ~~~~~m"" S 1/2" Hole TD 11S92' RECOMENDE Iì ,p tltfJ.-..- APPROVED: ~ß- - DI ~eer Drilling En~u~r ;2.L_ _ I f ,7 COMPLETIONS ENG ~~.C4~! APPROVED: -<1'~ oJ Drilliñg Superintendent · "'-"" Exhibit VI - 6c ,-,/ 13-3/8" CASING AND CEMENTING PROGRAM WEL', W-17 (PBU/RWR) PROGRAM; 1. Install mud-line suspensio~ landing ring on 20" conductor ensuring it is level. Ensure mandrel hariger O.D. will pass through riser. Nipple up riser. Drill 17-112" hole to I~OO' TVD BKB. Kickoff and directonally drill 17-1/2" hole to 2700 ft. TVD BKB (approximately 2809' MD BKB) per directional map. 2. 3. Circulate until hole is clean. POH to run 13-3/8" casing. NOTES: a) Maintain mud temperature as low as possible (40-45 deg. F). b) Clean, visually inspect, and drift casing. c) Have HALLIBURTON perfonn thickening time tests on cement delivered to locatio!)· using mix water which will be used for the job. IT = 4 hours @ 50 (¡eg. F for tail slurry. d) Ensure 13-3/8" Buttress double pin pup joint is of correct length so that the casing head flange will be 18" above the top of the cellar. e) Notify Alaska Oil &. Gas Commission (279-1433) 48 hours in advance to witness 13-3/8" BOPE test. 4. Run 13-3/8" 68# L-80 Buttress casing as follows; - Float shoe (landed @ approximately 2680 ft.) - 1 joint 13-3/8" 68# L-80 Buttress casing - Float collar - 2739 ft. 13-3/8" 68# L-80 Buttress casing (approx. 72 jts.) - Mud-line suspension hanger assembly - 13-3/8" "Specially Cut" Buttress double pin pup joint - Landing joint CASING RUNNING AND CEMENTING NOTES: a) Place 13-3/8" centralizers 5 ft. and 20 ft. above the shoe and every joint for the next 9 Jts. (11 total). b) Bakerlok first three.(3) connections. i I c) Fill casing as necessary. d) Have a 13-3/8" buttress swage with a 2" valve and cementer connection available on the floor while running casing. e) Place two (2) 13-3/8" metal petal baskets inside conductor: one at 90 ft. BKB using stop rings above and below basket; and one on the fIrSt full joint below mud-line hanger to bottom out on casing collar (at approx. 65 ft. BKB) using a stop ring above basket. I . Exhibit VI- 6e '-" 5. Land 13-3/8" casing shoe at approximately 2680 ft. MD BKB as follows: a) Install mud-line suspension hanger on last joint. b) Pick up 13-3/8" landing joint and wash down last joint if required. Tag 20" landing ring.: Slack off weight while monitoring conductor for settlement. If settlement occurs, set slips and slack off remaining weight. If conductor does not settle, slack off all remaining weight on the landing ring and set slips for safety. ..r 6. RU Halliburton cementers. Make up plug holding head (with top plug installed) onto landing joint. Install bottom plug, make up landing joint and test lines to 3000 psi. Break circulation. Pump 20 bbls. of water ahead of cement. Mix and pump cement as follows: 4128 Cll.ft.' (4438 sacks) PERMAFROST Weight: Yield: Water:; IT: 15.0 ppg. 0.93 cu. ft/sack 3.5 gal./sack 4.0 hours *Have Halliburton perfonn thickening time tests on cement delivered to location using mix water which will be used for the job. 7. Release top plug. Displacè cement to float collar at a rate of 8 to 10 bpm. Bump plug with 2000 psi. ! DO NOT OVER DISPLACE plug by more than 112 the shoe volume (3 bah-els). Provide details of cement returns on morning report and IADC report. 8. WOC 4 hours to allow cement to develop sufficient strength to support the 13-3/8" casing. Remove the slips and slack off weight slowly and observe casing for settlement. If settlement occurs, pick up all weight and WOC an additional two (2) hours ,m.d repeat slack off procedure. 9. Nipple down riser and perfonn top job if necessary. 10. Bakerlok and make up 13-3/8" 5000 psi split speed head so that tubing head annulus valves are oriented 90 deg. to the right of the direction facing the reserve pit. Approximate torque = 14,500 ft-Ibs. However, under no circumstances should the head be "backed-out" counter-clockwise to meet this orientation requirement. 11. Install and test BOP stack as per BOP manual. 12. Install long bowl protector.' Test 13-3/8" casing to 3000 psi. before drilling out float equipment. 13. Drill out shoe plus a minimum of 10ft. new hole and perfonn fonnation integrity test. Drill 12-1g" hole per directional map. 14. Measure KB to ground level and KB to BF. Record measurements on tour sheet and telex. OTY 1 1 75 11 2 5 1 2 pails 1 box --. 13-3/8~' MATERIALS LIST AFE # 120749 ITRM I 13-3/8" Buttress 'float shoe 13-3/8" Buttress float collar 13-3/8" 68# L-80 Buttress, R-3 (3 joints extra) 13-3/8" LO bow··type centralizers 13-3/8" Metal pe.ta1 basket 13-3/8" Stop ring~, 13-3/8" 68# L-80 Buttress double pin pup joint McEVOY split speedhead system, 13-3/8" Buttress w/AB seal ring x 13-5/8" API 5000 psi. flange and 13-5/8" x 13-5/8;' tubing spool Exhibit VI - 6c '-' VOCAB N2 Howco Howco 86050070 86127408 Howco 86129493 N/S built McEvoy 86627900 McEVOY or FMC mud-line suspension McEvoy system 86627905 Bow I protector <long, made for McEVOY split speedhead. Re-use from previous well.) Thread dope - API modified Bakerlok (10 x 1# cans) McEvoy 86627913 86139010 86139001 '- Exhibit VI - 6e ~ .~ 9-5/8" CASING AND CEMENTING PROGRAM WELL W-17 (PBU/EWE) SUMMARY: I ; A. Run 9-5/8" 47# L-80 Buttress casing from T.D. of 12-1/4" hole to approximately 4500 ft. TID (4500 ft. MD). Make up 9-5/8" NSCC Box X Buttress pin XO and run 9-5/8" 47# L-80 NSCC casing to surface. Land shoe within 5 ft. of bottom with mandrel hanger. B. Cement casing with Class G cement. Note: Have Halliburton run thickening time tests on ea.:h load of cement delivered to the rig using water which will be used for the job. C. Install and test pack-offs. D. Test casing to 3000 psi. before drilling out shoe. PROGRAM: 1. Drill 12-1/4" hole to the top of the Sag River Sandstone formation and maintain control as per target map. The North Slope geologist will predict the top of the Sag River fonnation from rig site data. While drilling from 7000' to 12-1/4" T.D., the mud weight should be 10.0 ppg. Open hole logs will be run as per saddleblanket. 2. Condition hole for casing. Pull wear bushing and install 9-5/8" rams. 3. Run 9-5/8" 47# L-80 casing (set shoe within 5 ft. of 12-1/4" T.D.) as follows: - Float shoe (side ports) Buttress - 3 joints of 47# L-80 Buttress casing - Float collar (Buttress) - 9-5/8" 47# L-80 Buttress casing from FC to 4500 ft. TVD BKB (5352 ft. MD BKB) ( approx. 155 jts.) - XO - 9-5/8" 47# L·80 NSCC Box X Buttress Pin - 9-5/8" 47# NSCC casing from 5352 ft. MD BKB to surface ( approx. 140 jts.) - Mandrel hanger - Landing Joint CASING RUNNING NOTES: a) Bakerlok bottom 3 jo;nts. b) Centralize bottom 10 joints with stand-off bands. Run turboclamps on every third joint früm surface to 2700 ft. c) I" Have circulating swage with valve and cementers hook-up available on floor while running casing. d) Fill casing as neces~ary 4. Circulate last joint to bottom and land mandrel hanger in McEVOY welThead. If mandrel hangerçar.mot be run, use emergency slips and pack- off. ·~_..,..~.....I Exhibit VI - 6c -- 5. RU Halliburton cementers. Install bottom plug in casing and top plug in head. Test all lines to 3000 psi. Pump 20 bbls of fresh water preflush ahead of the cement. 6. Mix and pump cement. Cement volume based on 90% annular volume to the 13-3/811 shoe + 50 cu.ft. Lead Slurry: 1890 cu.ft. (1000 sacks) Class G cement with 0.2% CFR-3 + 8 % Bentonite + HR..7 as needed for 4.5 hour thickening time. /r" Weight: 13.5 ppg. Yield: 1.89 cu.ft./sack Water: 10.2 gal./sack ; ~: 4.5 hours* Tail Slurry: 575 cu.ft. (500 sa~ks) Class G cement with 0.2% CFR-3+ 1. % Bentonite + HR-7 as needed for 4 hour thickening time.. Weight: 15.8 ppg.' Yield: 1.15 cu.ft./sack Water: 5.0 gal./sack TT: 4 hours* *Have Halliburton, run thickening time tests on each load of cement delivered to the rig using water which will be used for the job. 7. Drop the top plug. Displace the cement with mud at 8 to 10 bbl./min. Do not over-displace by more than half of the volume from the float collar to the shoe (4.4 bbls.). Bump plug and pressure to 3000 psi. 8. Drain the BOP stack and remove the landing joint. Flush pack-off area, install pack-off and energize as per wellhead manufacturers 9-5/8" mandrel hanger procedures. 9. Test pack-off to 5000 psi. with annulus open. InstallS" rams. Test BOPE. Install short bowl protector. 10. Rill with 8-1/2" bit and drill cement to float collar. Test casing to 3000 psi. Clean out float collar, remaining cement, and float shoe. Condition mud at shoe and drill 8-1/2" hole ffi.1intaining directional control as per target map. - OTY 1 10 2 24 4 pails 143 158 '- --- Exhibit VI -- 6c '^-' 9-5/8" CASING & !:.EMENTING MATERIALS LIST : AFE# 120749 IIEM 9-5/8" Buttress float shoe 9-5/8" Buttress float collar 9-5/8" GEMOCO stand-off bands 9-5/8" WEATHERFORD stop rings 9-5/8" WEATHERFORD turboclamps 9-5/8" Top plug 9-5/8" Bottom plug Thread dope - A~I modified 9-5/8" 47# L-80 NSCC casing R-3 (3 joints extra) 9-5/8" 47# L-80 Buttress casing R-3 (3 joints extra) 9-5/8" NSCC Box X 9-5/8" Buttress pin XO joint 9-5/8" 47# Buttress pup joint (20 ft.) 9-5/8" 47# Buttress pup joint (10 ft.) 9-5/8" X 12" McEVOY mandrel hanger with pack-off for NSCC casing McEVOY short bowl protector (reuse) VOCAB N!! Howco Howco 86127415 86129494 86126831 Howco Howco 86139010 86050240 86050233 86050242 86050236 86050238 McEvoy 86627928 McEvoy 86627914 ...~ Exhibit VI- 6e ---- 7" ROTATING LINE.N AND CRMENTING PROGRAM WRLL W-17 (PßU/RWE) SUMMARY: A. A 7" 26# L-80 liner is to be run from the T.D. of the 8-1/2" hole to 250 ft. above the 9-518" casing shoe. Condition mud to a yP of 8 to 10 Ibs./100 ft.2 prior to cementing liner. B. . The 7" liner will be cemented prior to being hung from a Lindsey Completion Systems hydraulic set hanger. Note: Have Halliburton pertonn thickening time tests on the cement delivered to the rig using water which will be used for the jQb. C. If there are any doubts about the integrity of the 7" liner cement job, consult Anchorage office. PROGRAM: 1. Drill 8-112" hole to 11,892 ft. MD as per target map. 2. Run open hole logs on wireline from T.D. to 9-5/8" shoe as indicated on saddleblanket. fustall 7" rams and function test. 3. Rig up and run 7" 26# L·,80 IJ4S liner on 5" drill pipe as follows: -7" Buttress float shœ - 1 jt. 7" 29# L-80 Buttress liner - 7" Buttress float collar - 1 jt. 7" 29# L-80 Euttress liner - XO jt. - 7" 26# L-80 ll4S box X Buttress pin - 7" IJ4S landing collar (Lindsey) - 7" 26# L-80 ll4S liner with marker joint at 11,480 ft. MD - Lindsey (U4S) liner hanger c/w tie back sleeve (pinned for 2300 psi setting pressure and 50,000 lb slack off to shear running tool) - 5" drill pipe (See drawing at end of program.) . CASING RUNNING NO"';'ES: a) Ensure that 7" liner is cleaned and inspected prior to delivery to rig. b) Bakerlok bottom 5 Joints. c) Centralize shoe and every fourth (4th) joint with 7" X 8-3/8" WEATHERFORD Metal Stand-off Bands. Centralize remaining joints with 7" X 8" GEMOCO Metal Stand-off Bands. fustall a bumper ring above each centralizer on ll4S pipe. d) Have liner and drill p::pe swages on floor. Fill liner as necessary. e) Do not run liner on :HWDP. ¡ I ",,,-", Exhibit VI - 6e "'- 13. Drop DP wiper plug and S:alt displacing immediately after pumping cement. Continue to rotate and redprocate liner while pumping and displacing cement. Displace cement with mud at a rate of 8 -10 bpm. (turbulent flow) providing pressure does not exceed 1500 psi. Reduce displacement rate to 4 bpm. while picking up liner wiper plug. Resume 8 - 10 bpm. displacement rate. Watch torque closely. A torque increase may be noted when cement rounds the comer at the lir:er shoe. A 200 - 300 psi. pressure indication may be noted as drill pipe plug picks up liner wiper plug from running tool. 14. Once the cement rounds the liner shoe and has been displaced half-way up to the 9-5/8" shoe, stop reciprocating but continue rotating. In the event that reciprocation is necessary for rotation, reciprocate with 10-15 ft. stroke as needed. 15. Continue to rotate until 5 barrels before plug bumps. Slow pump rate to 4 BPM. Position liner. Bump plug and set hanger with 3000 psi. minimum. Check to see if floats are holding. 16. Slack off weight. Rotate to the right to release from hanger. paR. CEMENTING NOTES: a) If shear-out of the liner hanger is observed while running in the hole or while reciprocating, the releasing nut will be engaged. Stop rotating and continue reciprocating. b) If shear-out of the Ii fitr wiper plug is obseIVed, measure displacement of liner at that point. c) Do not over-displac;.~ by more than 1/2 shoe volume (2 bbls.). c) Measure displacemfnt using pump stroke counter. 17. After eight (8) hours minimum wac, pick up 8-1/2" bit wlo jets and 9-5/8" casing scraper positioned immediately above it and clean out to top of liner. Test to 3000 psi. after 12 hours wac. 18. Install 3-1/2" rams. RIH with 6" bit wlo jets and 7" scraper and clean out to float collar. CBU 1-1/2 times at maximum rate with two pumps while reciprocating drill pipe. 19. Pump 100 bbls. fresh water :5pacer followed by 1000 bbls. of 9.2 ppg. NaCI brine. The NaCI brine must be filtered through a 2 micron Íùter unit and contain less than 100 mg!lìter tot.al solids. Displace well at maximum rate with two pumps. Recipro(:a:e iI.rill pipe continually during displacement. Circulate until clean NaCI apve:1rs at sutface. Reverse circulate for one complete circulation for additiollal cleanup. Retest liner to 3000 psi. 20. POH. 21. Rig up and run CET/CBT/GR in 7" liner. 22. Perforate and complete well according to petforating and completion programs to follow. Exhibit VI - 6c '- ',,-, 7" LINER MATERIAL REOUIREMENTS ,ÚFE# 120749 mY lIEM. VOCAB Nº 1 7" Floatshoe Howco 1 7" Float collar Howco 7" Landing collar Lindsey 7" 26# U4S box X Buttress pin 86050400 XO joint for landing collar 2 7" 29# L-80 But.ress casing, R-3 86050375 21 7" 26# L-80 U4S liner (Cond. liD ") 86121055/50 (3 joints extra) 7" Lindsey hydro.ulic hanger c/w Lindsey tieback sleeve 23 7" Bumper rings (2 extra) 86129495 6 7" WEA TIIERFORD metal stand-off 86127417 bands 7" X 8-3/8" (2 extra) 20 7" GEMOCO metal stand-off bands 86127416 7" X 8"(2 extra) 1 cant. (25#) API 5A2 modified thread dope 86139010 1 7" 26# L-80 TC~·S marker joint (20 ft.) 86121418 1 6" Bit, API 2-1-~ Vendor 26 Seal rings 86121838 Exhibit VI - 6c '- ',,-, DRY CRUDED.QWNSQUEEZE PROCEDURE After injecting waste fluids in 13-3/8" x 9-5/8" annulus, proceed with cement/dry crude downsqueeze procedure a~ follows. 1. Notify GC-l at least four ({) hours before vacuum truck anives to pick up crude. At the same time, notify GC-3 that excess fluid will be sent at the end of the job. GC-I will provide the vacuum truck driver with a report of dry crude water content. 2. When vacuum truck anivts at site, purge truck from lower most valve into an available mud pit. Rig foreman must witness this step. Pick up water content report from driver. Dry crude must contain less than 5% water. 3. Hook cement line to side of wellhead on 9-5/8" X 13-3/8" annulus. Test lines to 3000 psi. 4. Mix and pump 300 sacks of either Pennafrost C or Arctic Set I cement at a minimum of 8 bpm. IT to exceed 2-1/2 hours. Do not exceed 3000 psi. Cement slurry properties are given below. 5. Pump 125 bbls. of 6.4 ppg, dry crude at 4 bpm. Do not exceed 3000 psi. Strap dry crude tank before and after pumping crude to insure all is pumped. 6. Shut in 9-5/8" X 13-3/8" annulus. 7. Pick up purge water from step 2 with vacuum truck and return to GC-3 with Environmental Report from Tool Service. NOTES: a) Do not exceed 300cfpsi. surface pressure at any time during this procedure. b) Do not allow annulus to flow back at any time during this procedure. c) Record dry crude tank volume before and after job. Note on Morning Drilling Report. d) Note water content of dry crude on Morning Drilling Report. e) Cement slurry properties are: Weight: Yield: Water: IT: (@50 deg F) Halliburt<m Pennafros.u:. 15.6 ppg.. 0.95 cu.ft./sack 3.75 gal./sack 3 hours Dowell Arctic Set 15.7 ppg. 0.93 cu.ft./sack 3.59 gal./sack 3 hours B. J. Titan COLD SET I 15.3 ppg .94 cu ft./sack 3.89 gal./sack 3 hours ..,.- 5. 6. 7. 8. "1~ 9. --' Exhibit VI - 6c "-' 4. Stop running liner when bottom is 250 ft. above 9-5/8" shoe. Reciprocate and rotate liner inside the casing. Measure the torque while rotating, both running in (downstroke) and pulling out (upstroke). Add liner connection make-up torque (8000 ft-Ibs) to these values to establish separate maximum torques for upstroke and downstroke. Set torque limiter to maximum upstroke cementing torque. Make up cementing manifold and plug dropping head on single. Run liner into open hole until shoe is 15 - 20 ft. off bottom. RU Halliburton cementers. Break circulation while coming down on last single. Circulate and reciprocate string with 30 ft. stroke. Note pick-up weight and running-in weight. Take care not to slack off more than 30,000 lb. while reciprocating in to avoid shearing pin in liner hanger. While reciprocating, slowly begin rotating liner. Bring speed up to 10 rpm. Watch torque closely while running in. If the downstroke torque exceeds the maximum values detennined in step 4, stop rotating but continue reci proca ting. 10. Continue to rotate and reciprocate. Circulate and condition mud for a minimum of two (2) hours at 8 to 10 bpm (pressure not to exceed 1500 psi).The YP of the mud should not exceed 8 to 10 Ibs./l00 ft.2. 11. Test cementing lines to 3500 psi. Continue to rotate and reciprocate. Pump preflush consisting of 48 ~bls MUDFLUSH + 35 bbls DUAL SPACER @ 10.5 ppg.. 12. Continue to rotate and reciprocate. Batch mix and pump cement. Ensure that the mix water is at least 70-80 deg. F. Calculate slurry volume based on 50% excess over the annular open hole volume plus 150 cU.ft. for the liner lap and shoe volwnes. Slurry: 251 cu.ft. (213 sacks) Class G cement with 0.5% HALAD 344 + 0.2 % CFR-3 + L WL as needed for thickening time. Weight: Yield: Water: TT: 15.6 ppg. 1.18 cu.ft./~ack 5.2 gaL/sack 4.5 hOtlTs* *Perfonn thickening lime tests simulating one (1) hour surface mixing and 3-1/2 hours pump time. --" Exhibit VI - 6e '"",-" 7" 26# I.T4S LINER SHOE - RUNNING ORDER '-" ~ --------- ~--- IJ4S LINER \ / - - - - - - - - - - - - LANDING COLLAR (IJ4S box x U4S pin) _________·_u_ JOINT #3 7" 29#L-80 (U4S Box x Butt. pin) \ J - - - - - - - - - - - - JOINT #2 29# L-80 (Butt. box x Butt. pin) \ J - - - - - - - - - - - - FLOAT COLLAR 29# L-80 (Butt. box x Bun. pin) - - - - - - - - - ~ - -. JOINT #1 29# L-80 (Bun. box x Bun. pin) ~ ----------..- FLOAT SHOE (Butt. box) NOTE: Joint #1 will be drifted and made up to float shoe and collar prior to delivery to site. Joint #3 will be similarly supplied made up to landing collar. \ { '~ i ( Exhibit VI - 7: K241112 Well Integrity Report , Original Completion Date: Schrader Bluff Penetration Hole Diameter: Schrader Bluff Penetration Casing Diameter: Well Status as of 9/2002: Cement Logs Across Schrader Bluff: 7/2/1970 12-1/4" 9-5/8" Plugged and Abandoned on 6/9/76 None Comments: The initial 9-5/8" primary cement job consisted of 500 sacks of cement which was to seal of the Sag/Ivishak formations. During the abandonment of this well 37 sacks of cement was squeezed at 9600'md and 50 sacks was squeezed at 9300'md. The 9-5/8" by 16" annulus has cement from 2100ft md to surface. It is unknown if there is cement in the 16" by 20" annulus. Additional Information: Exhibit VI-7a Exhibit VI-7b Exhibit VI-7c Well Diagram Directional Survey Significant Workover & Drilling Daily Reports ( \ ~ 500' Cement plugs to Surface j 2503 ' 2100 ' Circ. 104 sacks cmt. 2750' Squeezed 50 sacks 9300' 9600' \~ 'í '~ Exhibit VI-7a: K241112 9 5/8" by 16" annulus cemented to surface with ~ 1200 sacks cmt.circulated through perfs at 2100' / " 20" Csg 760' Cement Retainer 2058' Cement Retainer 2400' ~ 13 3/8" x 16" Csg. 2454' ( ..-Cement Retainer 2700' Cement Retainer 9243 ' Cement Retainer 9414' ( Squeezed 37 sacks ~ BridgePlug 11,412' , ~ 9 5/8" 43.5# RS-95- 12 y." Hole 11,713' 11,4 73 ' 13749' F Bridge Plug 13,400' Bridge Plug 13,539' ... 7" 29# N-80 - 8.25" Hole RADIUS OF CURVATURe COMPUTED BY COMP TECH " I ~1EA.sc TRUE VERT SUB SEA DRIFT 'DRIFT REcr /;NGUL¡.\r~ DOG LEC:i s¡::- "....~., r \', ... ~. '- k .J t " DEP"rH DEPTH bEPTH ANGLE DIREC COORDIN/\TES SEVER r ¡'{ DlST, _E 100 lOOðOO 32(>20 0 151 S 68 E 0008 S Or,.20 E o ö 2 :;. 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'+ ø 1 9: S 2(!61 E O~?l 2ti6J. lßOO J.79ge98 17:32~18 0 ' 15 t S 27 E 'Þ 0 71./, S 2~58 E " 0 D 2(, 2,,57 1900 1899ø97 1832~17 0 15& S 30 E 50J.2 S 2t::79 E 01'; 0 1- 2(,\ 78 2000 1999697 3.93t.~i'}17 0 5 f oS ,~ 7 V1 5 to 3 9, S 2~75 E 001.7 2 t;: 71.:· 2100 20991/J91 20321Jf17 0 5 · S 66 ',~J 5 I!J l., 7' S' '21:163 E O~O2 ' 2 r.:. 62 2200 2199&97 2132017 0 5 f S Sl VI '5¢~~' S 2tJ50 f. 0,,02 2J;:50 2300 2299~!97 223261'" 0 15$ S ûl.} I..J :; t 6 (¡ S 2~2Li· E ùù2.? ¿ç23 21.:,00 2399~97 2332~17 0 15 t S 87 VI f¡ t~ (} S\ 5 " '1 ~ eo E Ol.'lOl : 1080 2 I..:·B 5 ' 2 l: 8 L~ G 9 7 2 I:. 1 "( f,\ 1 "7 0 25' S ·1 I':) \,} 5 c 7 S~ .s\ 1(~31 r:' o ~) ;~ ;., :-.(;3J. 1,. ? ~:) 0 0 2 ll' 9 '9 I) f.) 7 2 11- :3 2 1:1 ). 7 0 l>:; ~ ¡, I t.;./j ',/J t'j , 7 1: .s 1 t. 1 ~I [: ÔGCÚ j (,,17 '.~ 2600 2~¡99"r;:6 2:)32 &~ 16 0 ' l:.5 f (" ~i:S I.! 5[J~,Ç¡ S 0.(:03 U 1~O3 "(:)0,;03 ....1 h 2°,' 00 :¿ 6 9 9 0 9 (, 263~c16 0 '+5 ~ f': 6 E 6 0 f,¡ 2. S o (': ~\:3 VJ J -; ") "",,(}c 5? .. ;, ~ ,.:.. I ¡ SIJ"'-:3-16ÔOB MOBIL OlL CORPORATION KUPARU!( 24-11~12 KUPARUK ALASKA SPERRY~SUN WELL SURVEYING COMPANY 23 JUNE 1970 N 90 E THUE , , '. H ( ~ , l j f \ ~ 't j ~ ] . -' ".1 \ \ \DIUS OF CURVATURE , , C(XI¡~'U'¡TD L:Y CO:::) TE(~¡: ?. i\ S fJ Î'RUE VERT SU3 SEt.. DRIFT D r\ 1 F 'f HE c: Y/\NGUL/\r~ [) (.~ C·, 1... C:. (} S:~C'fí(){'·~ C:Pi'H DEPTH DCPïH ANGLE DIf\EC C 00 f~ l) I ".¡ AYE S SL\/Cf\ 1 't'Y I D 1 oS -¡' /'.f'~ C F 2800 2799~91 2·' 3 2 Go 11 2 I.:. S' . N 82 E 1~'o38 ~> 1 c I¡. f.:. E 6(;'OC 1. 0 It ~; 2900 2899~72 2831~92 I..~ lS' N 63 t~~ 2,56 S 7~23 f: 2 (.\ t.: ~( 7c·2.3 3000 2999,,33 2931053 5 l¡·5.f N 52 E 2t!12 N l/..} CI :;. 7 E 169Ú 1 L,~ ~ 5 "../ 3100 3098b69 3030ð89 7 15' N 57 E Bc69 N 23079 E J ,. 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C', :~ :~ .; t;~ C 3l~. ~ 0 .~; 9800 L_ 9900 (~9ü~ (1,1.;." 691~;rf!t67 63 o 'ð (' [¡ l'r F .123~Q13 N 4922085 E o 0 ~;\O ' f;. 9 ? ;~ ~ C. f;. .') 70;~nc87 69Ô1\j07 63 0' (' r'" f 122~c04 N 5011038 E O'i['S~ :'1 () 1. 3. (, '3 "I 1.0000 ", -' :> .. 10100 . 70? ') i; 0 /~ 7007,;;~/~ 62 at s £3/t- E 121SøOO N S090~~O E 1. 1:, 71, :i :) () ~;. .:; ø ~) C, 10200 71'22010 '7 0 5 I;. ¡j. :3 e 61 I:. 5 ~ Eo (, ,- E 1205002 N S187013 [ o r,'i 93. :,~le71:>12 \:; -"> lO:"¡OO 717()~:Ô6 7J.O(D06 60 1 ~:) · S 81.;- E 119~~1~ N 5274c02 E 1 ftj ':~ ~í 2 7/;: 0 0 ? ~ ~. . .." ~ o 'u i o ~ ,~ i i ,j ~ , ! I I i { 0 0 ~ l i Ò RAr)!US OF CURVATURE (C~~,',f·'t:·[TC' ::','{ (':: ',: .{ EO, (~ ~. ~ HE/\Sc TRUE VEf~T SUB SEA DRIFi D~IFT nEe T /\! \; c; U t. Ê\ ¡~ l;(.·'<.~ i...f ('.. f~ :. .. (:.'1"' r c~.~ . DEPlH 'D E P T H DEPTH J\NGLE. DiREC COO;~[) I N¡\T [S S C \/ L~ i ~ 1. "f \' ,[\ 1. S l f",: :.~. ':,~. 10400 ·1 2 2 1 t} (, 0 7153e80 SB 30· So 8/;- E 1186c12 N 5359€-60 E 1 t;.: ~:I :.~ ;. ~'" ~': -:: (, 0 10500 7274rJ03 7206Q23 5ß lS' S 82 E 11?5G75 N 54(4Gl1 E J. (, k( !. ~j tJ;. I:. (: J. } 10600 7326028 7 2 5 8 0 I:. 8 58 '~5 · S 83 E 1164a62 N 5528065 [ o ~,' 9 SJ :\ :.~ ~:. [; t·, (~:'.' 10700 7378~35 7310655 58 30t S 81 E 11S2~74 N ~613c19 E J..1'.J72 ~~ (\ 1. 3 (: ~. r.: 10800 "/t.~31" 34· 7 3 (; '3 ~ :~ 1+ ·S7 30' S 'ß2 E 1140020 N 5097c06 [ ).. {;. ~:,O :~ () ~J '/ c (/ :; 10900 71.)D5~80 · ?l¡.lGøOO 56 30' S 82 E 1128oS3 N 5780e21 E J. /;! (\ (i :.~ AI ü 0 ('.: ). (1 11000 7 S 1~ 1 t) 9 0 7 L!r 7 I~ t, 1 0 ~I ::) 15.' S e ") E 1117~Ol N 5862&08 [ 1 (,?~:" :~; ;.~; (, ~~ ~ c.~·S . ,. 11100 759<)(\61 753J.,,81 .5 L~ 15f S 82 r~' J. ), 0:> Ij 6 ¿}: N . 5 9 t.~ 2 t· S' :", L J 1:: C,Ci t: ~', I, r., . """0 ~.. l- .,1 " ',' t:. X· } 11200 7657015 7589(35 55 300 S 81 E l09305S:N 6023ca~ E 1 (. :,i (\ (, (1 ~~:::~ ,'. . 11300 7713fl12S 76'-¡,5 e l¡·5 56 15f S 80 E l079c89 N 6105e40 [ 1~J.? (, 2. 0 :.~ 0 /;. Ü 11 t~ 0 0 -'" 6 a f; 2 6 7 7 00 t;¡ t~ 6 57 ot S ·r9 E lb64067:N 6187c59 E 1 ('. 1..? () ). ~ 1J.·500 7822036 7""51~.ð56 57 30' S eo E 1049~35 N 6270029, E o ~" s.' :~..~ .. ",. 1...' l~ 11600 7875072 1807fJJ92 58 o & S "19 E 3. (1 3 3 '0 r) 3 . N (;. 3 ~. 3 ð I.;. t..~. L o t· ~~ ~'~ (, ~'; ~ m . x 11700 ·'9 2 9 {j, 6 :1 7<-;(·1<,;83 56 l~ 5 4 S eo E lOlGø39fN G4S6~?S ( :! I~ :'~~ ::.~) ,.. I, I :r ",.,. ",". 11800 7982ô81 79).~)éOl 59 ot S -/ r} E l003t15iN 6~)J.Ç;c52 C ;,',: c I:, 3.. 0" ~...:, ~/~ ;:¡: 11900 803l~.q.87 7967f:07 58 15~ (' "'(9 t 98(;, ô 8('< N ,660:) r" ~$?, [ (J f... ..? ~~~ (. (.. ! ~ .') l?OOO 8088(,78 80201';98 56 309 .S "19 F C) 7 0 ~ 79:. N (, 6 fJ 6 f.J 0 (1 E. j" l': 'l ::,1 (: t:: 1.2100 8 l/i,l~ fj 3l'r 8 0 '7 (, () ~I'~(. 56 o t S 80 E 955v64 N 6767G7S E (! r,;. S'i.., C· "I.', .....J 12200 8201r:.16 8J..3SE:·36 :> t:~ l~::1 ~ . (' eo 1;': 9:~,"J..ð:~~) f~·j ()t~l~,S'IDUl:~1 t: 1. c ¿~ ~',:; C- ..., t. (: ':'. 1230() 82:)9~~jr:3 6 1 91 II. 7 ß. 53 l.~~)t. t' 78 E 9t.~~~ G g'( ~N 69ZG ~/i~;~ E 1. (. tt; (l ;';:.1 .~,' 1 ? 11,- 00 8319fr06 8?51ð26 S3 1- · S 77 f':'~ 90Ð047 N 1006093 E o ö '9 I;. "(0 ::> ~.. 12500 83"l9",/.¡.2 g311(¡62 52 30t S 7& ,... [1 8 9 ~ ß 6 N ""I Ü Ü !~ ~ I:. 5 E 'I t'- ,,~ 70 t:. J.. f!;' ,,'~) J.2(>OO 8/~ t.¡ 0 fI, 1 2 8372032 52 45& S 73 'F 868062 N 7161002 E 2 1i.!;·O 71. t!.:. l,' 'v'I. 12700 81~99 t) 60 8431~80 5{~ 15' S 71 t: 8 I:. 3 Ð 78 N 7 2 3 7 (; tit 7 C 2.(! ~? 2 f 2 3 "I (~ to!,' (. 12800 8 ~i ::1 7 Ii 1/+ 8 Ld3 9 RJ 3 q. 55 30· 5 ·fO E . e 1. 6 (¡ 1;,8[' N "'f 3 1 I;. iii ;j 6 [ ), {i :7 (} ...: ~. j I ( . I .:~ ,.. ,..:. .) 12900 8613e60 8 :> I~ 5 t) 8 0 . 55 l.:> . S 69 E 707.58 N 73?ltG7 E o (!! Ci e, Mf ::~ \: 1 (:, L: -I 8669 /!; "'10 8601 (~90 .56 O· .$ 68 E 757Q2~ N 746SG89 E o Ii) [:Ú 7 f¡. (:¡ G {ì e ~) 13000 .. 13100 8 ..., 2 6 Ii 3 It¡. 8658(')5/.:. 55 0& 5 66 c: -¡ 2 ':; 0 0 I,,; N 7 S ¿~ I.~ (þ 7 5 E J.!l9J ~¡ Sf} t;. ~ 7 I;. '-' 13200 87834'.31.¡. f:i 71:)" 51.;, 55 30· $ 62 [ 68900~ N 7618058 E 3c¡:3i\ {(,).8r.: :;(\ '1 :3 :3 00 8 8 If- 0 t 16 8772ft¡36 55 156 S 58 E 647c89 N 7689083 E "'"I """ t"'"\. ï (1 i;3 9 0 G Z· ,;;. !) ¿ -;.' 13'+00 8897~3l¡. 8829c>5lf· 55 0' S 55 E 602062 N 7758024 E 2 c, l:. 6 ("1:,8 f; 23 13t:-33. 8916ti15 8 8 It B (; 3 :; 55 30· 5 55 E 581t07 N7780045 E 1051 -"I 7 C 0 iì I.:. Ii' 1 3 L+- 7 t.¡. 6939«29 8 8 7 11J+ 9 55 l\·5 ~ S ::-5 ~ 567e66 N 1808511 E Oç:6j_ 7DOÜ6J.6 t'. l 13500 n953ti83 88B6(!03 56 1St S ~3 E 555e2~'N 7925002 E loS',? . 1e20(;~ß? ~_ 3600 9009(103 H9t:·l f:,23 56 l~5 , S C", ") E 505070 N 7892~O~ E 2. r:! 5 c~ '7 e ~) :< ('; e I;. ;;.t ,.. 1. :) (} J. ~, 9017Ð2;'~ 89/¡.9 (¡ ~t2 ·57 (I ð S ~ ,..) t:' 497196 N 7902Q1S E J. ~\ (. (, 7 9 0 ;?, \.! 7 Ii, .) ~~ ~. 1365:) 9039(:001 B971(\21 57 O! S r' ? r~ /.~:rl ~ ":;.1 N I' 9 ;~ 9 f! }. e E o (: f.i n ;~. t) ;.~~ ç~ ~~. J.. !,:. ..) L.. t:. ..,. . .'., "'. J ,.. ~ , ftIØ ,....~...",. J, "(.. . . r· ,r4> ~I? ,,~ r..' - . .' Y'" (rot - -, ,__.xhibit VI - 7c SUBMIT IN DUro :;" I !~thcr 111- ;~:~~~~~id~~ s. API ~L~1-Œiüc.."'L CûD~ OIL AND GAS CONSERVATION COl'M';'ITTEE , 50-029-20063 wzaI:' A~" ~-'--,-.~- ...... r')--..--.-o....___>_...._.________ \VELL COMPLETION OR R~¿Ö~~ÊTïÕÑ- REPO~~T AND LOG * 6. L:~~ D~~~:~~n{,,~'; ,LiD s::;:·::~:;· ~ŸPl:; Oy\\YLr: --'õ'¡¡,-ocy:"~GAS O--"'J - 0 --...-.~- 7. IF IXD!............... ALLOTTEE Oil. T-.:;:.io..~_~: ....,~:.~... ; WtLL IÃ.J WELl. DRY .A:.'.~ Olr.ér _ I ~ b. TYPE OF COM:rLEno~: I· :'iEW r::l' 9,'ORIC 0 DEEP- 0 WELL ~ on:R rs PLC¡; 0 DAC!\: I'I!FF. 0 t.r.$VR. Oth~r s. U.KlT,F~_ql'.r OR U::ASE x.~.r¡;; 2. NAME OF OPIRATOn. : MOBIL OIL CORPORATION Kuparuk Sté'.te 9. WELL ~O. Kuparuk 24-11-12 3. AnDRESS or OPERATOX ¡P.O.PODCH 7-003, ANCHOP~GE, AK 99501 4. LOCATIOS or WEI.L (Report location- clearlu and in accardaTtce 'lCith en:! State rf'luirer.\entA)" : AtlurfAce 1700' FSL and 600r F\VL,Sec.23,.T11N,R12E,U.M. . 10. FIELD AJ-;D l"OOL, O? WILDCAT ~ Prudhoe Bay Sad1eroch 11. SEC., T., R., ~l., (l:~OTIO:',1 liOLE OBJEc:rlVE) At top prod. interval reported below 2282' FSL and 3107' F~.JL, At tòtal depth Sec. 24, TI1N,R12E. At 13,655'M.D. 2177' FSL and 3249' ~~, Sec. 24, T1lN, R12E Sec. 24,TI1N, R12E - , 12. PER.:'.UT NO.. 70-22 ~2. DATI: SPUPDF.n h.¡. :>ATE T.D. REAC!U..!) 15. DATE cœ.IP. 5USP.OR ABA."'D. lis. ELEVA'nONS (OF. RICB. RT. GR. 13TC)· Ît7. ELEV. CASIXGHEAD Ú··2 70 ¡ ;o-~1~-70 - "'. :'-=L I 8·-26-70 ---- f 67 < 80 I K. P. ~ 1. 18. TOTAL DEPTH. :fID & TV.1Jf:: T"',T"G BACK MD &: 1VDr' . IF :'a;'LTlPLE CO:-'!.PL., 21. tSTERVALS DRILLED BY ~13 749' (9095') DEPTII 13 705(9064) HOW!v~'iY" _ I ROTARY TOOLS . CAHLt TOO"'S : ' , ------ Surface to T.D. ------ '22, PRODUCING I~TERVAL(S). OF TIllS CO:-'IPLETIC::-¡'-TOP. BOTTG:.I, KA?IE (r-.-m AND 'TVD)" 23. WAS DIKE:.:TIC~A:' SURVEY MADE ¡Top Permo-Triassic 13,433 M.D. (8928 T.V.D.) YES 24. TYPE ELECTRIC A..."D OTHER LoGS RUN ~. _ ~DIl'J SONIC, FD~, .s~-2-.f:~ ~CALI~~:ß. -~ CBl: .~~ .~At¥1~ RÞ..Y· 1'-J~UTRON 25. . CA5U,G RECORD (Report 311 str;:1f;¡; ~2t ¡':'i Wf.'~) CASŒG SIZE - W-EIGHT. L3:·~T. T GRADE 1 D¡:?TI:I SET (~!D) I HC:"=:: srz=:: I CE:',rr.......,''TIXG RECORD 30" 154# - L. P. 158 r - J 3ó" 190sx Fondu 20" 94# H-40 L750 I 2411 60üsx Fondu-F lyash 16"x13-3/8" l091fx61if K-55 J·2496' 17-1/211350sx J?ondu-Ylyash . 9-5/811 r47#&~3.¿ S-95 111,695 -J 12-1/4l~~.0~~ C1a=-s _~....\vi18'1" _ salti-----=_ æ. L1NE~ RECORD 27. TtiBmG RE:'ORD I I .!0.10r.:XT' ?t::"!.~:=:: -. TOP (:-ID) BOITO:-''¡ (~1D) f SACl<S CE:\IENT-l SCREEN (:\ID) , ¡ I : 11 , 473 13, 749 , 388 .' I _~. ..I. 1(__. --..# ....-__.o:_......~~ _::~ro~~-P--..-r..~- -~-._._--- "'--....=-........ r·....~ .~.-..~.. ..;:... ....~ '28. FERFORATlO~5 OP1.:':-; TO PRODUC-¡-iO)¡' tlnt~rval. she and number) :W. ACID, SEOT. F~~_q·~LŒ. CE~.II:XT SQU¡::::ZZ. ETC. : 13 , 544'- 13 , 590 ' (4 h ole s 1ft )", DEPTH H.."ìER V AL (MD) A:'i01.:-X-r ......,,"D Kl~D OF :-'1:,A, TEP..ÁAL USED ~13,510'-13,530' (2 holes/ft)·- 13,670' 75sx Class G ;13,444'-13,466' (2 holes/ft) 13,610r 75sx Class G ;13,638'-13,641' (4 holes/ft)· .SIZE SIZE DEPT'"ñ SEl' (Y.D) f P ACiu:a SEl' (:'>!D '7" It -. r-,..._ - ".....::......- . .. -- ......~ "(Se~ AttachëdfJell-IYístor~ir - 30. !DATE FIRST PRODUCTION PRODUcrION PRODUCTION ME'lI{OD (FIOWi1,~:g3S lift, Ji...:rnping-size and type of pump) 'Short Term Drill Stem Tests WELL STATUS (Producing o. . :;S\i-§'pended : DATil: or 'tEST, . liOI....RS TE.51LD .CH0:·(E SiZE PROD',,; FOR TEST PER!OD -> OIL-BEL. I GAS-i\lCF. WATER-BBL. GAS-OIL RATIO ¡ --:FLë)\,l TUBING CASL."\fG PRESSURE CALCULATED OIL-BBL. : PRESS. ~ 2o!-HOUIt, ~TE I J .- : 31. DtSPOSITIOS OF CAS (Sold, ~Aed for juel. lIcnteå. etc.) GAS-MG'. f WATER-BBL. OIL GRAV1TY-A.?I (COr..: TEST WIT~£sstD BY , 32. LIST O&' 4TTAClDI£srs . Well History) .; . 3;~. -t hereby certÛŸ u.at the tNcb'olno: and attach!::d Infùrmatlon Is comp!ete ~nd corrcct a.~cnillned from all-'llvaHahle rE:COrd:i SIGNED/f":Y-.~·/Ie_<· ¿.c,-· . TITLE Division OpeL E;gineer DATE 10 I 7_// /~ /[ ; - ¿-. ( . -~~.~~ : · (See Inslructiom and Spaces for Additional Data on Rev~rse Side) Date' 1970 3/1-4/1 4/1-4/5 4/5-4/8 4/9-4/12 4/12-4/14 4/14:-5/21 Exhibit VI-7c ~ ~~ .~ MOBIL OIL CORPOP~TION HISTORY OF OIL OR GAS 'ÆLL OPEP~TOR: MOBIL OIL CORPOP~TION FIELD: NORTH SLOPE SEC, 24 T11N R12E U,M, \offiLL NO.: 'KUPARUK STATE 1124-11":12 Well History of Kuparuk #24-11-12. ~his ~e11 was drilled using Pa~ker Rig #96, positioned 1700' FSL and 600' FHI., See.. 23, T1lN, R12E, U.,M., under Permit- No.. 70-22. All depths refer to K.B. 21.1 above gravel pad. (67.80' above sea level) _Rigging Up and Setting 30" Conductor Pipe. Moved rig 8:nd riggp.d l1p. Spt. 58' of 30" conðuctor pipe in 36" hole and cemented with 190 sa,cks Fondue c~ment ð -..0,,-.. -- --". .- -.- --...-. Spud; drl:!.linr; 17-1/2" to 760' and Reaming to 24". Spudded 17-1/2" hole at'11:45pm 4-1-70. Drilled hole to 1'60'. Opened 17-1/2" hole to 24" to 760'. Muè: 9.3#/ga1., vise. 245 sec.. Running 20" O.D. Casing to 759'. Ran ·18jts. 20" O.D. 94'# H-4-0 csg.. ,"/guide shoe, duplex float collar, and sub sea hanger. Could Dot brea,k circulatiç:>n 't-7ith 700 psi. 20" esg. pumped out of hole, elevators opened and casing fell fOvln hole. Recovered 17 jts 20" esg. Recovered bottom jt of 20'" esg. by scre'\.¡ing into Duplex collar . with drill pipe. Conditioned hole and fe-ran 2œ' csg. Ran 18 jts. 94#/ft.. . . . , H-40, 20" O.D.. csg. to 750'. Ceme.nted through Duplex Float Collar "lith 600 sacks ~0:50 Ciment Fondue-Flyash w/3% ~alt. ~ement in place at ll:30pm 4-7-70. pri,lling 17-1/2" Hole to 2530'. Installed 20" Hydril and tested to'1000 psî--OK.. Drilled out firm cement bet,,,een Float Collar and Shoe. Drilled 17-1/2" hò1e from 750' to 2530'. Mud: 9.411/gal.--200 sec.--14cc. Surveyed well every 200-300'. Mud: 9 .4:/I/g8.1. --165 sec. :'-13. 6cc Attempting to, L.og and Running 16" x 13-3/8" O..D. Casing. Sch1unilierger's attempt to log was unsuccessful. Log stopped at 1840'. Hud: 9.3:/1/ga.l.--150 sec.--13cc.. . Ran 45 jts. of 13-3/8" O.D. 61ft/ K-55 Buttress(1742.l6) and 18 jts. 16" O.D. 109# K-55 But~ress (746.73). Hanger-496'; Shoe at 2496'. Float Colla:r-2454. Cemented with 1350 sx 50:50 Ciment Fondu-Flya.sh w/3% salt. Displaced 16". x 20" annulus '-"/45 bbls. diesel oil. Drilling 12-l/~' Hole to 11,700'. ~aited on BOP Fla.ng~. Installed BOP and tested 'to 2000 psi. Drilled Float Colla.r and Float Shoe and Drilled 12-1/4" hòle to 26'00'. Ran Sperry Sun gyroscopic survey. Ran Dynadril1 2600'/2985'. Reaming to 2977 when drilling string reversed. Backed off drill pipe at 2655'. Recovered a.l1 of fish. Exhibit V: - 7c "- History of Oil or ~ Well Page 2 ~'trp'aruk State /124-11-12 l~/14-5/21 .Cont. Drilled 12-i/4" hole to j161'. Ran Dynadrifl 3161'/3272'. Drilled to 5013' with stif~ hook-up. Ran Dynadri1l 5013'/51l5'~ Drilled 5115'/5377' with stif~ hook-up. .Ran Dynadri1l 5377'/5423'. Drilled with Dynadrill 5423'/5483'. Drilled 5483'/566l'~ with drilling assemb ly. Ra.n Dynadri 11 566l'! 57631. Dri 1.1ed to 7306'. Ran Dynadri 11 7306' / 7449'. Drilled to 8866'. Ran Sperry Sun gyroscopic survey through drill . . pipe. Stopped at 6300'. Dr:i"llëd 12:-1/4" hole to 11,700'. . . '_. . . """""" '"'- . . '. , ....., -.. :"-. ~/21-5/28 Running 9-5/8" O. D. Casi.n·g to 11,700'.. ""+.. -Ran 180 jts. 9-5/8" 43.5ir RS-95 LT&C casing. (Tota.1 'length of 7l~9-¡ .88). Ran 47 jts: 9:"'5/8" 47:/f RS-95 LT&C (Total. 1889.20) . Ran csg. to 9387'. Picked up TIH, linèr hanger. Could not engage. thr,eads. Layed hanger dmvn ,and continued to run 56 jts. 9-5/8" 43.5# RS~95 LT&C Total 2323.22 on top" ·$i~in£.' T,and~d casing with shoe at 11,695', float at 11,609'.' Total csg. ran was 236 jts. . 43.5#:and 47 fts. 47# (11,713.60'). Could not break c:Lr(',1J.12.t;-~~ "7ith 3060 ?si~.; ·.A.ttempt--to- ~ircu1-atc:'~;ith ~0\-7e.-ll at4ûOO þEri;- Nippled up BOP's, tested to 2000 psi and drilled out float collar with . 8'-1/211 bit. Could not circulate. Drilled out shoe at 11,695, cleaned out, and esta.blished circulation, Ran retainer and set at 11,600'. Cementèd 9-5/8" casing '\-7i th 500' sx Ç1ass "e" with 2% D-:-8 and 18% salt. Ran Sperry Sun. Stopped at 11,120'. ~ 5/29-6/12 priiling 8-1/2:1 Hole 13,749' TD. Nippled up BOP and tested at 2000 psi. Drilled retainer at 11,600' an~ firm·cement to 11,695'. Drilled 8-1/2" hole 11,695'/12,385'. Drilling ·string stuck in 8-1/2" hole. Established circulation, spotted pipe lax an~ jarred string free. Cleaned out and conditioned hole.- Drilling string ·stuck while conditioning hole. Worked and jarred pipe free. Increased mud wt. a.nd viscosity. Drilled ahead to 13, 7l~9' TD. No ~ole trouble encountered, ·bet'\.¡een 12,385' /13, 749'. Mud: 10..8# - 70 sèc.--3cc~· . . , ..._' ,~...:.~_:;_:" -:.-..,.:.". '.' . .: ~:--."r~>,~::.~..<_ . "':;~:.;'~:::''''.. ::":':~.: ,:~:u~'~;-~~<.:.:.:~;~~~_~=~;:-~~~~~[~~:~":': - "-~---:-----:.. ;~ _. 6/13-6/25 Logging a.nd RunnfrÏg 7" O. D:. 'Liner i. :::' .. ~. .:\ . ..... ..:-'. .~. ':.. .::" .;' . . . ..' " , '. S.chlumberger ran 'dual induction· 1òg. $~ppped .~t· 12,800'..." . - ":.' . . . Re,.r~n in}, .,ith additic;nal weight:. Ran log . to·T. Ó:.' , :. -. .. ..,:... ... ,. ·.:1 . .~~hi.um1?·¿rge:r 'also. ra,!1' Sonic-:' ..FI;>~;· . SNP,. .a.nd, ..c~~ip.~t;':· : ".<~ - " '.;> :;" .... :"..-~:: '.- '-, :-:: o:~..." . . d .: ,:: Schlumbé~g~r stucK: ~tdèvl'a1l co.Te gün vl~~,le .ob~a¡~~Îlg·~a~p1·es..:·· .' '-:-":." . :~ . Strlpp~'d' ov~r,lj.rie arid recove~ed fi"sh... Ran ~6' jt·s...·7". 0.tf..,29if, ..N-80, sea1--· . ,:' foc~. csg.. ',,(Total. 22~7') wi th 7" x 9-:-5/8"" BroHn ~bif :Toöt.·hanger .1~L ~3' w/hy:d~au1ic:: ,... set slips. . Total length of' 7"' liner and hanger" 2276'(;·'1" shoe:' at ·t3, 749 ; top' . '; "ó'f.)iner 11;473'.;' . Dropped ball, could .not get ..ball..int~ ·.-seat· to·,.s~J ?lips..···· .; Ran' ~TTS pkr. tò '11',474', could not' ge.t into. l~~er.,··1ian:E-Z :dri:1,1 retainer' at i1~·50CY. ,'Cementécl ,.¡ith 188 sx' Class "q" v7/6~'Ge¡ ~rld 18% sait,' followed w/200' sx Class "G" w/18% salt. Drilled retainer and' cle.aned out 7" liner to float c·ollár. Schlumberger·.ran CBL, and GR-N iogs:. Re-ran' GR-N.. Ran Sperry Sun gryoscopic ~urvey. ·Displaced.·roÙd fr.om. 9:'5/8": x .16" ·?-nnulus.w/265 bbls·. die s é 1 ..' . . . ....: . -. - ...., : ~:.:; : " . - \ -' .': . i... :.i .' .-:.'~: :'. , , . ".' . '6/26-7/2 . -:.. '~a.i t on Orders. .:.--- .- --~---. '~.' . . ". . . . . . -. '. . . . .. . . . .. ". '.0 .'. :. . .~. . ~ . . ,. :..: . .. . . .. .. 7/2-7/6 - 7/8-7/9 7/9-7/10 History of Oil or Page 3 Exhibit VI - 7c ~~druk State #24-11-12 L <> -- ,Perforating and Sql1eezin~13',670' a~d 13,610'. Schlumberger perforated 4-1/211 holes 13,670', ran Hmvco E-Z dri 11 retainer.· Dm.¡ell squeezed 75 sx Class "G" neat. Schlumberger perforated 4-1/2" holes at 13,610'. Ran Howcö E-Z drill on D.P. Dowell squeezed with 75 sx Class "G" neat. Drilled E-Z drill at 13,546' and cleaned out 13,630". Drilled E~Z drill a.t 13,633' and cement to 13,671'.' Schlumberger ran CEL. Perforatin~ and Running DST#l 13,544' - 13,590'. Ran and set E-Z Drill on wire line at 13,600'. Perforated with 2 holes/ft. 13,544 -13,590. . Ra.n Halliburton DST tools and set pkr. 13,495'. Opened tool for 5 min. initial· flow period with good blo\o7. Closed.for 57 min. initial shut-in~press~~e. Reopened for 185 min second flow perio~ with good blow. Recovered 600' of oil / . IHP=4825p.si, IFP=119psi ,FFP=92p.si., ISIP~4349psi,IFP~14'lpsi~ KFP==-2.51pS.i¡,' _.'-. . FSIP=4244psi, FHP=4737psi. Recorder at 13,504'. Perforat}ng and Running D'ST#2 13,510' - 13,530'. Ran. and set E-Z Drill at 13,537'. Perforated with 2 holes/ft. 13,510- 13,530'. Ran Halliburton DST tools and set pk~ at 13,465'. Opened tool for 5 min, initial flow period. Closed tool for 65 min. initial shut in period. Opened for 120 min, second flow period and Closed for 180 min, final shut-in period. No rec~very reported IHP=4914psi, IFP=80psi, FFP=5lpsi, ISIP=88psi,IFP-34psi, FFP~27psi, FSIP=124ps~, FHP=4914j?si. Recorder at··13,479'. 7/11-7/12 _Perforating arid Runni_ng DSTfl3 13,4_44' - 13,466'. Ran and set E-Z dri 11 bridge plug a.t 13,480'. Perforated with 2 holes/ft. 13,444' - 13,466'. Ran Halliburton DST tools and set pkr.· at 13,400'. Opened tool for 5 min. initial flow period. Closed for 49 min, initial pressure. Reopened tool for 133 min. second flow period. -; Recovered'3' of oil. IHP-4715psi, IFP=58psi, FFP=49psi, ISIP=3530psi, IFP=112psi, FFP=97psi, FSIP=3000psi, FHP=4727psi, Recorder at 13,416'. 7/13 Capping Well. Set E-Z Drill bridge plug at 13,400 and capped \-lith 15 sx Class "G". Dm.¡e 11 spot ted 28 sx Class "G" at 3000'. Top of cement at 2922'. Displaced mud in 9-5/8" csg. w/diescl oil from 2922' to surface. 7/14-7/23 Standing By. Rig released - 2:00pm 7-23-70 7/23-8/17 ßtanding~~ Stood by without crCHS. Rigged up again. History of Oil or ~s .Page 4 Exhibit VI - 7c Kcrparuk State #24-11-12 8/18-8/22 Picking Up Drill Pipe and Running in Hole. Picked up 5" D.P. Installed B.O.P. and tested to 2000psi. Displaced dieset from 9-5/8" csg. w/mud. Drilled out bridge plug at 3000:. Drilled out retainer and cement at ~3,400', 13,537', and 13,600'. Ran bit to 13,698'. Perforating and Running DSTff4. P~rforated 4 holes/ft. at 13,638' to·13,641'. Ran Halliburton test tool~ and set pkr.at 13,617': Opened for ini tia.l flm.¡ périod at 10: 35am for 10 min. Began 30 min. initial shut-in period at ·10: 4·5am. Began final flow period at 11:15am. Shut tool in at 5:18pm. Tool open 6 hrs. 3 min. Gas to surface at 11: 38am. Flm.¡ed gas at 190psi on 1/2" choke. $urface pressure decreased to 10psi at 4:05pm. Mud to surface 4:50pm.. Oil to surface 5:10pm. 99.8% oil O.2%b.s. Gravi ty 24.3 a.t 60 OJ;' . ---- .-.--.--- IHP==4729psi IFP=555psi ISIP==4352psi FFP::=2244psi FSIP==43~5psi '~8/25-8/26 Capping Well. -Set Hm.¡co 711 E-Z Drill bridge plug a.t 13,539' Set E-Z Dri 11 bridge p lug at 13,400' and capped '\V/ 50' cement. . Spotted 35 sx cement at 3000'. Rigged dm.¡n and relea.sed rig at 10: OOam - 8-26-70. JJB:bf lO-14~70 "-... Exhibit VI - 7c KUPARUK STATE 24-11-12- "-'" ABANOOt-MENT OPERATIONS May 5, 1980: Checked wellhead for pressure. Rem:>ved tree and tubing adapter tlange. Cemented 10 cu.ft~ (20' plug) to surface. Installed marker p:>st extending approximately four feet. Top of marker" post sealed and the following information bead-welded on: SOHIO P.B.U. KUPARUK STATE 24-11-12 1700' NSL, 600' EWL, Sec. 23, TIIN, Rl2E, UPtví 'All . fOssiþle fi 'ttingsw~re removed and all o:penings welded ·~..hut. Location cleaned. ~ '~ . .~:;¿i:::.;~;·=· :t, . /:.·~~:f~"::·~:· . :)~~{f~~f: ' See Ins tructions On Revar5ß Side. DATE Trrl_E AP.JP.0VEO BY CON()ITlONS OF APPROVAL, IF ANY: .. -- --- (T his ~þ).s':f' for StClte offlc.' use) --=-:-=:=.::;.---=--..._- June 14 r . ·~.97~ DATE )6. I f\~reby certify thê\t the)7901ng I~ true and c·orrect ///,.// .. "'~~"~" Area Engineer /// "," / . /,. , . SIGNë:.D J _ . '. " '._. ..._._ ._~ . _ TITLE . , ~ -- . ~~-'. - . .' .~:-'~~::.: ~{:- '~:.."'!_~:.-. , ...0(';:'.;...: -"::_~~__~ . :"'::.'~... .:: .::.:~ '- P. K. .Paul discussed this ·change. of plan with Mr.. Lonnie c~ Smith on June 9, 1976 at·l:OO~p.m. (Denver time}' on 'the telephone and obtained a verbal a.pproval~ The· subsequent report of suspension of the' well is attached. Noti~e .of in tertian to abàndon this 'well was submitted on, April 5r 1976. H01.-1eVer, \-,hile \-lorking on this ·Hell the annulus 16" x 20 H flo\.¡~ç1 slightly ~ince 9-5/811 casing 'vas' per forated at 2750' and the flow stopped prior to cementation of 9-S/8~ x 16" annulu.sr . The .flow from 1~" x 20"· annulus was possibly d~e to heat. gained from hot mud circulated inside· 9-5/811 casirig~ To make sure that the flow from this annulus· was not from. any other sourceE we like to . monitor the \-lell for some'time and so the wellhead. is not removed <> - . (NOTE: Report resuHs c.·f multiplecomp:cticm on WslI Compl2t.ion or Recomp:etlon"Rcporlëlnd Log form.) -15. DESCRIBE PROPOSED OH COMPLETED OPERATIONS (Clð3rlysta.te all pertinent details, and give pertinent dates, including estimate6 dale or star:-i"9 any proposed work. (OtM') ,25.- ----: REPAIRING WELL ALTERING CASING ABANDONMENT~ ,- FRACTURE TREATMENT SHOOTING OR ACIDIZING (Other)8uspenc1ec1 CHANGE PLANS TESt WATE·R SHUT-ÛFF' FRACTURE T.REAT SHOOT OR ACIOIZE REPAI R \'/E:LL - ~ .WATER SHUT-OFF PµLL OR ALTER CASING _ MULTIPLE COMPLETE ABANDON· --- . . ~UaSEQUENT REPORT OF: NOTiCE'OF'~NTENT ION TO: -- - -... ~ ~, 68' K.B.70-22 Check 'Appropriat~ Box To Indicate Nature of NotiCe, Report, o~ Other Data ·4. 12. PERMIT NO. 3. ELEVATIONS (S~ow wl'leUier OF. RT. GR. etc..) See. 24-TIIN-R12E,. U . l"-¡c;·f Alask. ~. WELLEO- - ') "\ K\lpa . 24-11-1~ .... 10. FIEL Ar>IDfvvt:, urt" WILDC.\ r . Prudhoe Bay Sadlerochit 4. LOCATION OF WELL . At\ur170.0' FSL and 6..00' F~vL, Sec. 23-TIIN-R12E, UoMo1 Alaska Xl. SEC., T.. R.. M., (BOTTOM HOLE.OBJECT I~~J AOO~ES\Pcf,?P~~4~~ Denver, Colorado 80217 8. UNIT. FARM OR LEASE NAME. Kuparuk State OIL F{l c.r..~ 0 '-:ELL L-I WELL o.THER X -- NAME:. o;:~Y~~TIOðIl Cor¡Jora tion 1. 7:-ïf?ïr:¡UIAN.ALLOTTEE OR TfUUE. NAr...1E- 1 -~- -;-ï~'!:-hE~:GNATïoN 1\£'10 SERIAL NO. 1\01. 4'7451 SUNDRY NOTICES AND REPORTS ON \rVELLS «(JII nflt u·.c thl:; 'orm for proP:)i:\ls to drill or to t.:.:~?...n U~e "AP¡:>~IC^T ION FO~ ~ë:.HMIT-'· for such proDo!';!I:..) ~5r '29~2!:Ö068oE' Exhibit VI - 7c .-. I .. STATE OF OIL AND GAS CONSER --------- - - .\ Schlumberger ran 9-:5/8 Ü EZ drill cernen..t 3.:-etainer and set at 11;412( (Schl..· tagged '7"· liner top· at 11,461' - 17' les~ than DP measurement). Ran 4!21t drill pipe C'.nc1. sta.bbed- into CCj~tent retainer 0 Pressu~ed to test liner lap to 2000 psi for 30 mins~- OK. Spotted 45 ßX Class G cement ~lug on top of EZ drill"plug (noted DP measurement 11,422' for EZ dr'ill) r . Tagged top of plug a:'c 'li, 3 ~ 2 I It Pulled O\.l't.. of hole, .' 6-S-76·to 6-6-76: Ran.6n.bit, '65' joints' of 3?:,2" drill. pipe and 9-5/8 II .casing s'çraper on 4h If drill pipe. to 12,840' and noted obstruction..' Washed out:'· to. EZ drill bridge plug at 13,4111 (could not find good harà cement cap expected to he at 13,350').: Circulåted 'out- 9..5 ppg r¡~ud( 300 see/qt. viscosity. Weighted up mud tó lO.l) ppg \'7ith 600 's>: harite.. . SpottecY'ceTJent plug in 7" liner at 13,411' \.¡ith 18 sx class G and ~ 003% HR7. Pulled 3 stan<ls and r~versed auto P~11ed out of hole~ 6-3-76 t~ 6-5~76: Ran 8~iu hit to .1650 r and noted obst.ruction t Washed nnd reamed 250r and circulated out gu'mV1Y mix of oil and müd ~ Ran- further t:o. . 2200' and circulated out diesel.. Tested 9-5/811 casing to 10.00 ·psi for 15 T!tin...... Of<t. Ran·fu1:ther to top of c~ment plug itt 28751 and drilled hard cement plug f~om 2B75' to 2975'. Ra~ further, breaking circulation ever~' 15,001 f to top of línE!r at .11,478 ( t .Circu¡ated out lO~2 ppg mud with lO~6 ppg mud.. Pl1lled ou·t of bole ~. . 6-27-7£ to 6~3-76:- 5-29..:.76 tö 6-2-76: . Skid rig frÓm Kuparl1}~ 22~11-12 drillinçr well to Kuparuk'24-11-12, a.dis~rince of 150';; 1t'." ?1.: t.rs ~ Riggéð.. up. . Te-st~d BOP and cho!çe rnaniföldto--SOOO psij and annular 'preventer to 2000 ·psi. 5-26-76 to 5-28-76: Noted casing preSS1..~re of 1!10 psi ilnd .9-5/0" x 16" annulus 'pr(Ù:i'~;~l1-e of 205 pSí. Bled casing pressure toO psi and recovered 9 gallons. o~ diesel. 9-5/8" ~"- 16 U annulus ·pre:=;ßti.re . dropped to 185 psi.. HIed annulus to 0 p~í and recovered 3 gal1QT1s oÍ diesel~ Removëd biind flanqe and installed OCT spool with tesi plug. Blind £l~ngc had pressure built up to 50 psi in 12 hour~~ REPOnT OF SUSPENS·IOi-j KUPAHUK S'l'jVfE 24-11..:-12 .~ Exhibit VI - 7c (, - "'-..- 'P'" . .(~ ~ ~ '- , Hcport of Sl1Spens<=,-, Kuparuk 24-11-12 -, contd. Exhit. '1 - 7c - -2- 6-6-76: Schlumberger perforated 9-S/8rr casing a.t 9600' and 9300', with ~ shots at each,depthr Schlumberger ran 9~5/8 rr EZ dr-ill cement r·e~a.íner to 9410' {EZ Drill stopped at this depth} and set. Ran 4~" drill pipe, stabbed into cement retainer and attempted to establish circulation. Could not break circulation . up to 2600 psi pressure. Formation .broke at 2600.psi and could pump at 5~4 BPM at 2300 psi. Squeezed perforations at 960Qf. ''Ii th 87 sx clé1.sS G cement \-Tí th 2 3 ~~ HR7~' Pumped in at 2400 psi and final' squeeze pressure was 3400 psi~ 50 sx of cement was squeezeð into formation leaving 37 sx inside · - . 1, . , . oj t · caslng~ Ño C1rcu a~~on wni~e cemen· ln~~ Pulled oüt of hole~ . 6-7-76: Ran 9-5/8-" EZ drill. cement rei:ainer on drill 'pipe and set at 9243!~ Broke down perforations at· 9300" at 2800 psi. and pumped i11 at 4,.5 BPM at 2500 psi. C~mented vlith 91 s:x: class G -- 50 sx of cement \vas placed into formation - . leaving 41 sx'inside casíngr Spotteà:41 sx class G cement on top of 'EZ drill plug~ Tagged firm solid plug- at 9110fe 6-7-76: Schlumberger perfora:teð. ~-5/81t -célßing at . 2750' with 4 shots.. - Openeð. 9~5/8 trx 16 fr and 16" 'x 20 tJ annuli C' Diesel oil'· flo\<¡ed to surfac'e from .both annuli., J?umpeð. diesel ~. out of 9-5/8" x 16H annulus and recove'red 195 bbls ~f~otterir stinking ge3 .ppg mudr Recovered from 16~f x 20 fr annulus a.pproximately. 3. bbls diesel~' .' 6-7-76: Ran 9.-5/B" EZ drill cement retainer on drill· pipe' and set at 27ÙQ'e Cemented outside 9-5/8" casing through perforations ~t 2750' 'with 104 sx Permafrost cement (left 23 sx' --.. inside casing) 9-5/8ff x: 16(( and ).6ux 20'~ annuli ·,verc open \vhile cemen·ting.. Had good . .return to surface through 9-5/8 (( .»: 16 u annulus and 1/211 strea.m of diese.l· on 16 nx20n annulus .. .: .. . ~. .' <>:;= '- ~~ ., .. ( ... ;.. __..a..: _ -3- Ext,-,l VI - 7c ~ Report of Suspension Kuparuk 24-11-12 - contdo 6-7-76: 6-8-76: 6-8-76: 6-8-76: " 6-8~76: 6-9-76 to 6-12-76 ' p . 1{ Paul 6/1i/76 , . Schlumberger perforated interval 2503.'" 25.04.1 (3' correction on J~!J due· to' rig changes) ,·¡i·th 4 spf using 4 H Hyper jet gunn Pressured up. on 9-S/81f cas·ing through fíll up line with blind rams closed to .380 psi~ Required 3 cu. ftft to fill c~sing~ Pressure '.. dropped in 5 ·minD. to .320~ r 15 min to 29.0*,.' _.. 30 min. to 260#, 45 min to 235#, 3 hr~ 30 min~:' to 160#' and 9 hrs.. 30 min. ~o 90#.. No "flow >, ";~,.. - to ,surface through 9-5/8 ff x16u annulus and' .......... Slight flo\'T from 16 It x 20 u annulus (3 to 4 gallons per hour)... . Again pressured up to 480 psi ''lith 2 cu.' ft.. mud.. Pressure dropped in 10 min. to ·'(YO# and 3û' min.- . to <290~" No return t.o surface. tJ)xough 9-5/8 If x l~ If . annulus and 16" x 20u annulus flowing steady stream o~ diesel at 3 ~allons per hour~ " ~ . - Ran 9-5/811 EZ. qrill cement retainer'and set at 2400'0 Capped. with 42 sx class G cement with . ~% ·CaC12. Tagged ce~ent cap at 2325Jo.· Schlumberger perforated 9-5/Su casing at 2100' \-lith 4 shots.. Pressured up keeping 9-5/8'~ x .16u and 16" x 20" ~rinulí open - circulated with less than 100 psi pressure~ Flow was through 9-5/8" x 16u annulus' a1;}.d 16" x 20u annulus had no flowø . . Set, 9-5/8~n E!Z drill cement retaíner. 'at 2058 r . and cemented 9-5/811 :>.~ 16 H . annulus \ÿith 1200 ~Permafrost, circulated out 25% excess. 1611 x 20" annulus was kept closed dúring cementation 0 sx . ; -..:. ~"o . " . Placed cement' plugs of 56b' lengths .from 2058' to surface with 850 sx Permafrost~ . Nippled down BOPo 'C¡osed valves in the wel~head~ -. - . Rigged down from 1 a~m~ on 6/9/76 . -~." -.: ~;;:·;~;~i ~~. .~.. . . -. ~..~ ?'~:':::-~'~:~-':'. . . ." -.' ..., ..? -. .: ~:~:_¡~. :=-~ _- _~·:·.··-~7_·-:-- .¡~ ~.~:-, '~::.:~: ~~:~:':- : -_;~-:;;. ~t. ~~. . ".....'\,. ,", ·0" -: ," ~_.. .-- .:-_ .. OF' . . .- ......:.~ . .. .. -. -: --.;': . ~: j\~1~~i~: ·····~~~·f::.:~· ;: - . .---~. -. ".-- . /J;!f~}ir> Exhibit VI-8: S-03 Well Integrity Report Original Completion Date: 3/1/82 Schrader Bluff Penetration Hole Diameter: 12-1/4" Schrader Bluff Penetration Casing Diameter: 9-5/8" ( Well Status as of 9/2002: Cement Logs Across Schrader Bluff: Flowing on Gas Lift None Comments: The 9-5/8" annulus was pressure tested at 3000 psi for 15 minutes and held, on 2/11/82. On 2/13/82 the 9-5/8" x 13-3/8" was downsqueezed with 280 CF cement, plus Arctic Pac, and tested to 3000 psi. Exhibit VI -8b Exhibit VI-8c Well Diagram Directional Survey Significant Drilling Daily Reports ( Additional Information: Exhibit VI-8a -- TREE = W8...LHEAD = A GfU«\ TOR = KB. ELEV = BF. ELEV = KOP= Max An~e = Datum MD = DatumlVD = 4"CIW FMC AXELSON 67.10' 38.50' 2000' 57 ~ 6100' 12010' 8800' SS 113-3/8" CSG, 72#, L-BO, 10 = 12.347' H 2694' Minimum ID = 1.93711 @ 1024811 ALPHA TBG PATCH ITOPOF7" LNR H 6789' 19-518" CSG. 47#, L-BO, 10 = 8.681" H 7302' 13-1/2" TBG, 9.3#, L-BO, 0.0087 bpf, 10 = 2.992" - 11257' I TOP OF 2-7/8" TBG - 11257' ITOPOF 4-1/2" LNR H 11321' 17" LNR, 26#, L-80, 0.0383 bpf, 10 = 6.276" H 11840' I ÆRFORA TIOO SUM'v1ARY REF LOG: SWS BHCS 02/22/82 SWS CBL 02f27/82 A!\K3LEA TTOP ÆRF: 39 @ 11855" Note: Refer to Production DB for historical perf data SIZE SPF IN1ERV AL OpnlSqz 06.1E 2-1/8" 4 11855-11909 0 03114/89 2-1/8" 8 12042-12122 0 07/22/90 I FEID H 12730' I r 4-1/2" LNR, 12.6#, L-BO, 0.0152 bpf, 10 = 3.958" H '.2.860' I 06.TE 03,Q1/82 07f25/92 03,Q7/01 03/12/01 09f21/01 REV BY COMM:NTS ORIGINAL ooMJLETION WSW LAST WOR< OV ER SIS-MH oof\NERTED TO CANVAS SIS-MD RNAL RI\VKAK CORRECTIONS DATE g ~ I r--4 RBI BY Exhibit VI - 8a 5-03 e L I I I ¡'.U:: J..'.' ~..~. I ~t .íi¥ Ii I \ .at I] ~ ~ "- SAFETY 001ES 1997' H3-1/Z' OllS OBESSSV LANONG NIP,IO= 2.75" I ~I , 2600' H 9-5/8" DV PKR GA S LIFT MANDR8...S lVO ŒV lYÆ VLV LATCH 2915 28 CAMCO RK 5211 53 CAMCO RK 6405 52 CAMCO RK 6905 45 CA MOO RK 7394 48 CA MOO RK 7796 49 CA MCO RK 8135 45 CA MCO RK PORT Ol\ TE ST rvD 7 3039 6 6594 5 8558 4 9316 3 10008 2 1 0632 1 11132 10248' HALPKö. lEG PATCH TO 10268 I 11191' H3-1/Z' OTISXA SLDINGSLV I 11237' HBOTSBRTBGSEALASSY I 11257' H7"BOTA<R,10=3.813" I 11257 H3-1/2"X2-7/8"XO I 11313' H2-7/8" 011S X NP. 10 = 2.313" I 11347' H2-7/8" BOT-80S TBG TAIL, 10= 2.441" I 11335' H8..rvDTTLOGGED01/01/93 I r I 11950' HMA.RKERJOINT I -, ., m~ COM'v18\ITS 12206' H SlO GL V I 12209' HTB... RNGER I PR\J[)iOE BAY U\lrr WB.L: S-03 ÆRMT I'b: 81-1900 API f\b: 50-O2~20695-00 Sec. 35, T12N, T12E 8P Exploration (Alaska) Well S-03 Directional Survp~# - ~--- '-' Well: I~~~~h.. Exhibit VI - 8b ... . .... - ...~"..... - >_on ..., ..............._........__.........._____._.___.____._---···----.-_--___0- ----.--------- API/UWI: 500292069500 Survey Type: GYRO Company: Gyrodata Survey Date: 09/09/89 Survey Top: 0' MD Survey Btm: 13,133' MD __" __. _ _ ___. .._ . _ n__ _____ _ . --'-~------- ---. ---- -- --- MD TVD SS INCLINE AZIMUTH DOGLEG ASP_X ASP_Y 0 0.00 67.10 0.00 0.00 0.0 619,139.1 5,979,855.2 100 100.00 -32.90 0.27 126.53 0.0 619,139.3 5,979,855.3 200 200.00 -132.90 0.42 157.43 0.2 619,139.6 5,979,854.5 300 300.00 -232.90 0.43 155.08 0.0 619,140.0 5,979,853.8 400 399.99 -332.89 0.42 153.22 0.0 619,140.2 5,979,853.4 500 499.99 -432.89 0.32 144.03 0.1 619,140.6 5,979,852.7 600 599.99 -532.89 0.27 126.32 0.1 619,141.0 5,979,852.4 700 699.99 -632.89 0.18 112.21 0.1 619,141.2 5,979,852.4 800 799.99 -732.89 0.18 106.41 0.0 619,141.6 5,979,852.0 900 899.99 -832.89 0.22 97.79 0.1 619,142.0 5,979,852.0 1,000 999.99 -932.89 0.20 95.54 0.0 619,142.3 5,979,852.0 1,100 1,099.99 -1,032.89 0.23 95.99 0.0 619,142.7 5,979,852.0 1,200 1,199.98 -1,132.88 0.23 84.01 0.1 619,143.1 5,979,852.0 1,300 1,299.98 -1,232.88 0.13 84.01 0.1 619,143.5 5,979,852.0 1,400 1,399.98 -1,332.88 0.93 298.28 1.0 619,142.8 5,979,852.4 1,500 1,499.93 -1,432.83 2.50 318.38 1.7 619,140.6 5,979,854.5 1,600 1,599.67 -1,532.57 5.78 345.79 3.7 619,137.8 5,979,860.7 1,700 1,698.90 -1,631.80 8.37 340.39 2.7 619,133.9 5,979,872.4 1,800 1,797.74 -1,730.64 9.12 333.42 1.3 619,127.8 5,979,886.2 1,900 1,896.52 -1,829.42 8.80 325.01 1.4 619,119.5 5,979,899.6 2,000 1,995.27 -1,928.17 9.33 323.57 0.6 619,110.2 5,979,912.3 2,100 2,093.66 -2,026.56 11.23 323.18 1.9 619,099.3 5,979,926.4 2,200 2,191.46 -2,124.36 12.85 322.31 1.6 619,086.5 5,979,942.6 2,300 2,288.76 -2,221.66 13.83 319.29 1.2 619,071.5 5,979,960.3 2,400 2,385.62 -2,318.52 14.95 318.05 1.2 619,054.9 5,979,978.7 2,500 2,481.91 -2,414.81 16.37 317.25 1.4 . 619,036.3 5,979,998.6 2,600 2,577.64 -2,510.54 17.25 314.97 1.1 619,015.9 5,980,019.1 2,700 2,672.95 -2,605.85 17.97 313.09 0.9 618,993.8 5,980,039.6 2,800 2,767.36 -2,700.26 20.52 310.33 2.7 618,968.8 5,980,061.2 2,900 2,859.91 -2,792.81 23.93 312.01 3.5 618,940.1 5,980,085.6 3,000 2,950.12 -2,883.02 27.17 312.27 3.2 618,907.6 5,980,114.0 3,100 3,037.65 -2,970.55 30.65 310.93 3.5 618,870.9 5,980,145.3 3,200 3,122.38 -3,055.28 33.48 311.41 2.8 618,830.5 5,980,179.8 3,300 3,204.45 -3,137.35 36.20 310.84 2.7 618,786.8 5,980,216.8 3,400 3,283.58 -3,216.48 39.18 310.26 3.0 618,739.7 5,980,255.6 3,500 3,359.53 -3,292.43 41.97 311. 50 2.9 618,689.9 5,980,297.3 3,600 3,432.63 -3,365.53 44.08 311.37 2.1 618,638.0 5,980,341.8 3,700 3,503.30 -3,436.20 45.97 311. 72 1.9 618,584.4 5,980,387.8 3,800 3,571.56 -3,504.46 47.93 311. 82 2.0 618,529.1 5,980,435.7 3,900 3,637.92 -3,570.82 48.92 311. 64 1.0 618,472.4 5,980,484.5 4,000 3,703.27 -3,636.17 49.48 312.68 1.0 618,415.6 5,980,534.5 4,100 3,767.87 -3,700.77 50.03 312.27 0.6 618,358.5 5,980,585.2 4,200 3,831.95 -3,764.85 50.27 311. 46 0.7 618,300.4 5,980,635.6 4,300 3,896.05 -3,828.95 50.00 311.45 0.3 618,242.1 5,980,685.2 4,400 3,960.87 -3,893.77 49.18 312.62 1.2 618,184.8 5,980,735.5 4,500 4,026.25 -3,959.15 49.17 312.42 0.2 618,128.2 5,980,785.5 4,600 4,091.85 -4,024.75 48.83 312.57 0.4 618,071.8 5,980,835.9 4,700 4,157.76 -4,090.66 48.72 311.18 1.1 618,015.0 5,980,885.1 4,800 4,223.58 -4,156.48 48.95 310.12 0.8 617,957.1 5,980,933.3 4,900 4,288.62 -4,221.52 49.92 311.97 1.7 617,899.0 5,980,982.1 5,000 4,352.61 -4,285.51 50.50 310.83 1.1 617,840.6 5,981,032.1 5;100 4,416.14 -4,349.04 ~0.62 310.97 0.2 617,7" 1 . 3 5,981,081. 7 lop 5,200 4,479.49 -4,412.39 --,0.77 311. 99 '___'7 5,981,132.0 5,300 4,542.22 -4,475.12 51.52 310.50 3 5,981,182.3 5,400 4,604.19 -4,537.09 51.90 312.17 Exhibit VI - 8b 5 5,981,233.4 5,500 4,664.82 -4,597.72 53.45 311.80 5 5,981,285.5 5,600 4,722.95 -4,655.85 55.47 310.75 L.L 0.1 1,'to.L.5 5,981,338.3 5,700 4,779.24 -4,712.14 56.03 313.45 2.3 617,419.3 5,981,392.6 5,800 4,835.11 -4,768.01 56.03 312.76 0.6 617,357.9 5,981,448.4 5,900 4,890.71 -4,823.61 56.42 313.65 0.8 617,296.4 5,981,504.2 6,000 4,945.80 -4,878.70 56.72 311.14 2.1 617,234.0 5,981,559.6 6,100 5,000.59 -4,933.49 56.85 313.59 2.1 617,171.2 5,981,615.0 6,200 5,056.16 -4,989.06 55.63 312.57 1.5 617,109.6 5,981,670.7 6,300 5,112.90 -5,045.80 55.23 311.59 0.9 617,047.7 5,981,725.0 6,400 5,170.32 -5,103.22 54.68 312.39 0.9 616,985.9 5,981,778.6 6,500 5,228.86 -5,161.76 53.67 309.95 2.2 616,924.1 5,981,831.1 6,600 5,288.49 -5,221.39 53.13 312.10 1.8 616,862.7 5,981,882.9 6,700 5,349.01 -5,281. 91 52.38 310.60 1.4 616,802.1 5,981,934.6 6,800 5,410.61 -5,343.51 51.57 310.82 0.8 616,741.6 5,981,984.9 6,900 5,473.53 -5,406.43 50.45 309.94 1.3 616,681.6 5,982,034.5 7,000 5,536.89 -5,469.79 50.92 308.63 1.1 616,621.0 5,982,082.3 7,100 5,599.75 -5,532.65 51.18 309.84 1.0 616,559.9 5,982,130.7 7,200 5,662.11 -5,595.01 51.67 309.39 0.6 616,498.9 5,982,179.6 7,300 5,723.73 -5,656.63 52.25 307.99 1.3 616,436.6 5,982,227.6 7/400 5/784.61 -5,717.51 52.75 308.26 0.5 616,373.4 5/982/275.7 7/500 5/845.00 -5/777.90 52.95 308.25 0.2 616/310.1 5/982/324.1 7/600 5,904.55 -5,837.45 53.95 308.51 1.0 616/246.3 5,982,372.9 7,700 5/963.54 -5,896.44 53.75 308.28 0.3 616/182.3 5/982/422.1 7/800 6,022.15 -5,955.05 54.48 307.95 0.8 616/117.7 5,982/470.9 7/850 6,051. 52 -5,984.42 53.58 309.23 2.7 616,085.7 5/982,495.6 7,875 6/066.46 -5,999,36 53.07 312.16 9.6 616/070.2 5,982/508.6 7/900 6/081.59 -6,014.49 52.43 314.07 6.6 616/055.5 5,982,521.9 8,000 6,142.78 -6,075.68 52.13 317.41 2.7 615/999.5 5/982/577.8 8/100 6/203.69 -6,136.59 52.83 316.46 1.0 615/944.4 5/982/634.7 8/200 6/263.85 -6,196.75 53.20 318.57 1.7 615/889.5 5,982/692.8 8/300 6,323.47 -6,256.37 53.60 318.62 0.4 615/835.5 5/982/752.0 8,400 6,382.79 -6,315.69 53.63 319.33 0.6 615/781.6 5/982/812.0 8/500 6,442.63 -6,375.53 52.87 319.47 0.8 615/728.6 5/982/871.9 8/600 6,503.80 -6,436.70 51. 70 319.86 1.2 615,676.5 5,982,931.5 8/700 6/566.55 -6,499.45 50.57 318.79 1.4 615/624.7 5/982,989.6 8/800 6/630.63 -6/563.53 49.72 318.96 0.9 615,573.4 5,983,046.7 8,900 6/695.53 -6/628.43 49.35 319.67 0.7 615,522.9 5/983,103.7 9,000 6,761.53 -6,694.43 48.05 317.27 2.2 615,472.2 5/983,159.0 9,100 6,828.72 -6/761.62 47.53 317.88 0.7 615/421.4 5/983/213.1 9/200 6,896.79 -6/829.69 46.68 318.42 0.9 615/371.5 5,983/266.9 9,300 6,965.87 -6/898.77 45.92 317.50 1.0 615/322.3 5/983/319.5 9/400 7/036.07 -6,968.97 44.92 318.95 1.4 615,274.0 5/983,371.9 9/500 7/107.42 -7/040.32 44.03 317.80 1.2 615/226.7 5/983,423.9 9,550 7,143.43 -7,076.33 43.83 317.85 0.4 615/203.0 5,983,449.1 9/575 7,161.53 -7,094.43 43.42 320.07 6.3 615,191.5 5,983/461.8 9,600 7,179.70 -7,112.60 43.33 321.25 3.3 615,180.3 5/983,474.8 9,700 7/251.94 -7/184.84 44.17 319.14 1.7 615,135.2 5/983,527.5 9,800 7,323.11 -7/256.01 45.08 320.60 1.4 615,089.1 5/983/580.2 9,900 7,393.09 -7/325.99 46.10 319.96 1.1 615/042.6 5/983/634.4 10/000 7,461.75 -7,394.65 47.18 321. 72 1.7 614/995.8 5/983/690.1 10,100 7/528.91 -7,461.81 48.45 323.21 1.7 614,949.7 5,983,748.3 10/200 7/594.60 -7,527.50 49.42 323.82 1.1 614/904.0 5,983/808.0 10/300 7/658.88 -7,591.78 50.57 322.56 1.5 614/857.2 5,983,868.8 10,400 7,722.11 -7,655.01 51.00 323.84 1.1 614,809.7 5,983,929.9 10/500 7,785.38 -7/718.28 50.50 324.00 0.5 614,763.1 5,983,991.8 10/600 7,849.32 -7,782.22 50.00 323.38 0.7 614/716.6 5,984/053.0 10/700 7/914.17 -7/847.07 49.15 323.81 0.9 614/670.5 5,984,113.8 10/800 7/979.90 -7/912.80 48.65 323.93 0.5 614/625.1 5/984,173.8 10/900 8,047.09 -7/979.99 46.92 323.17 1.8 614/580.2 5,984,232.4 11,000 8/116.12 -8,049.02 45.77 323.60 1.2 614/536.1 5/984/290.0 11/100 8/186.31 -8,119.21 45.07 323.47 0.7 614/492.9 5,984/346.4 11,200 8,257.45 -8/190.35 44.23 323.77 0.9 614/450.3 5,984,402.5 11/300 8/329.53 -8,262.43 43.53 324.71 1.0 614/408.8 5,984,458.2 11/400 8,402.43 -8,335.33 42.88 323.55 1.0 614,367.9 5,984,512.9 11,500 8,476.40 -8,409.30 41.70 324.35 1.3 614,327.4 5,984,566.8 - --. - . - . - . - . -------- 11,6UU ~,~~1.34 -~,4~4.L4 41.LL 3L~.I· ~~.3 ~,9~4,6LU.U 117700 8,627.24 -8,560.14 '10.03 326.0! ~f).7 5,984,673.3 11,800 8,704.17 -8,637.07 .~9.38 326.9: Exhibit VI - 8b'-.-i.6 5,984,725.8 11,900 8,781.53 -8,714.43 39.28 330.1 ~ 30.6 5,984,779.4 12,000 8,859.51 -8,792.41 38.25 331.86 l.=:> b14,149.4 5,984,833.9 12,100 8,938.19 -8,871.09 37.97 333.28 0.9 614,120.1 5,984,888.0 12,833 9,516.04 -9,448.94 37.97 333.28 0.0 613,911.0 5,985,287.5 12,933 9,594.87 -9,527.77 37.97 333.28 0.0 613,882.4 5,985,342.3 13,033 9,673.71 -9,606.61 37.97 333.28 0.0 613,853.9 5,985,396.8 13,133 9,752.54 -9,685.44 37.97 333.28 0.0 613,825.4 5,985,451.2 ·~' Exhibit VI- Be ~' WELL HISTORY WELL 8-3 Spudded well at 0900 hours, January 18, 1982. IhstallErl diverter system. Drilled 17 1/2" vertical hole to 1404', then drilled directionally to 2695'. Ran open hole logs. Ran 70 jts. 13 3/8" 72# L-80 Buttress casing to 2694'. Cerænted with 3720 cu.ft. Arcticset II cement. Installed and teste::1 BOPE. Cleaned out to 2652', tested casìng to 3000 ps-ì,' okay. Drilled out to 2730'. Ran 1eak-off test to 0.82 psi/ft.. gradient. Directionally drilled 12 1/4" hole to 11840'. Ran open hole logs. Ran 191 jts. 9 5/8n 47* L-80 Buttress casing to 7302'. Casìng run stopped at 7302' (4300 '+ above the program setting depth). CerænteïP with 862 cu. ft. Class G cement. Tested casing to 3000 psi, okay. Cleaned out float equìpænt and dìrectionally drilled 8 1/2" hole to 11848' . Ran 129 jts. 7" 261 L-80 IJ4S liner to 11840'. Cerænted 1ìner with 2300 cu.ft. Class G cement. Dc::Mn squeezed 13 3/8" x 9 5/8" annulus with 280 ~...:. ~"'.:..·Ãi~èticsèt :t canel"1tfoliOWed bY 120 ~. Arctic Pack. Pressurè t~si:ed-=';:-':::':"'-~;: Imer lap,. Droke down at 1300 psi. Set EZ Drill at 6725'. Squeezed lap with 230 cu. ft. Class G ce.rœnt. Cleaned out to 6789 t and tested lap to 3000 psi, okay. Cleaned out to 11796· arrl pressure tested liner to 3000 psi, okay. Cleaned out float equìpnent and dìrectìonally drilled 6" hole to 12860'. Ran open hole logs. Ran 52 jts. 4 1/2" 12.6# L-8Q A/B :rrod. Buttress liner to 12860' . Cerænted with 360 cu.ft, Class G cerœnt with 18% salt. Cleaned out . cement to liner top at 11320' arrl pressure tested lap to 3000 psi, okay. Cleaned out to 12730' PBTD and tested liner to 3000 psi, okay. Changed well over to NaCl. Ran ŒL. Ran 347 jts. 3 1/2" 9.3# L-80 EUE 8rd tubing to 11348'. LandErl tubing with ball valve at 1987'. Installed and tested tree. Displaced tubing to diesel, set packer at 11237'. Tested tuning to 3500 psi, okay. Released rig at 1600 hours, March 1, 1982. "...-' ..,- I ------' I I 11 SUMMARY OF OPERATIONS 0' ðoI: - c? ~ · 1'ó /.I t· u Y þof.,UV·· i3 HA ¿' 5"r~p' cv r T lVð CN4,vf;G) D7l.f6 -:. 6r~() - ·e.,eA/J. t:("ðo/Z., 1" /?'1 uf 7'0 '70 'Z~.u /"5 ~~/~ b ~ $b- , ':-' ~ 1Z u,v . .1 'S. '318 . (7 () :rot-oS.) I"~ - 17ðV ¿¿J,)tJ.. 13~ I C./~(;u,-"T/~.~ .----:...._ 17«>.1'110 HIXffUIM! 4ðDCJ S~ 41l.rlc. ~t:,'r iÏ :'5."2 PP~. /1t11o... Z0'Jo ÞI!fl.A~6 uJt· ~'1 f?(JAMf ~ 8CJ~ ¡tJlt/t;: ,~ Zií~ pSI .' c /r' è1? 26'30 II~.: zOJó- ,I 1.( ~US~ P~~J.s. - . CK ¡::¿0it/.'0 1(",1' j.DOW~ I' DowG¿l, I 'L.II.S"' - "Z~~O 1.f.tJc~ o~'" ¿14¡()ÒI.u, :rr;.. ~/1 'Do'f.µ.</, or#/.¿If t5?t.I!¡p tUl6tf.)T.- "Z z 'to -ð Z&o All ¡:;¡;t..';' I>OW...u 1)1f/ê12:R:IZ' ! T" ,\ ...,'" r'''''' OZo-o - 0400' I/VS-r~t.¿. /3.0/; ?t.Jt - ¡::-A1~ ~1Z7iAJ($ WE¥ 'f -rStG o/'CO~ ,- o4co- O~6-0' tVlfJl'~ . tlþ 8 ó?t , ~ <.. . . , !. t . - ÁiorS ,'. NAb GOOD IC€'MeAJT /2ér~I'¿A/..r, ~ ~C(~ =30 8bt-s, + c.J..fí. ¿-8d BV1r/lê!.- ,'9"9 .2:3 "Z.~,'Z.... 2' z.,~!.. '2.s '/3 ~/A: : rJ 7..."t 'fÞ11'ð.fJ. <i) ~JJ:JE 't'~f ~- F.. .cÞ~'r¿ lOp ~ 9 BIT NO RT HflS . t-1E I GHT RPM ; 10 SV NO COMDEP AN-Gi-DIR TVD _ h kß~ 73F - 'Za~O ~B~ GL. '3~~O . - _ __ _.'~" ._A~" 'SECT ..-.. NV;5ëo~.:. . E/WCO DLS GRADE /-,' ~; PS~:';:;;<;~: LNR SZ ~PM - . "... ! DEPOüt FTG !.i I:: . TYPE . .SR NO JEfS MAY.E 8 BIT NO SIZE · 5 PH SAND SOLIDS 'HT:-~P CHLOR RM'F ,75:1" . ..... ': 6 "JELL COS,!: INTANG TANG TOTAL (Z9~41 . /74/30" .. ~:t)~~71 7 DRLG ASSY BIT NO. SUPVR ~~N4.0/Œ ¿:... 2 MEN BEDS FUEL WATER A/F/D .. . BO,P -.-' t1 5'2.. . :;¿;?,4 . I C:>O ~ , ~ CURRENT OPERATIONS NlfPLt . . 3 ufo gDPt. ~ I ¡. 4 NUD/Wi VIS PV-YP GELS TEMP FÜ 'CA1<E . I' WEATHER ......--.........--....- A- B C D E F,'¡ G ."." q ~ .. .. ~ . 1 DATE WELL RIG DAY NO DEPTH 21!HR FTf I-Z.Z-~~ 53 '2'-£ 4 -z..r..q 5 .-~ H .. . ~ . -.- ~. -:.;-.:.~..~::¿~~~~~~~~~:; - - . - . . r { ~ ~ ~:;,Üt~~iff-·:.:?:þ·:;~;~}~~~~W.i)}~~i:~h ¡bit VI -. Be. :;~?~~!}0;.i~f~~~t' '·;·;r\f.;·~~,~~p~{~~gt.2~:}~,;,~Y~f ' :,......\::~..... '-- . ·""··:.·:'·SOHIO/BP .DAILY· DRILLING ~ORT . . _. , _ A . _ .. ~ ~-~~--~---~---~--~-~~~-~-~---~-~ ~- ! --- ¡ ~I ~ u IP 1S ö P€ '"" . íGSf .ßo1'E.- . íC-5í Kt?"¿y CoCK.~ t CUOCI<.G M~J.)I FD¿,Q ..- 1>1 ~~ "8 H A. V o;¿IEJ.JÎ 13 Ii. - . '.j íê/ H' - ïA~ CMr @ Z~3~" 1)~'(,t..fAJ(j c.J.fr 1'"0 US'z.J -rE~ 1.3 ¥A ~6r -rc:;) ~ooo:PsZ ,1:;1 TJI2/t..L/J.lJ OuT Ft..OAr/ C,"17;' ~1-I4G .J:. j CU2. C,U ~í".IA./G . t)JI2..I ¿,-,A./t; -1"0 Z 7.30. ~4K:. ..0"F,. ~..' 76.$f.7' ..:$~ ~4 t:."tf' . ·f'-r~~~..~~ .·..··8 7 ~ ?,sI ûn.l~':~:r,::,,::,,\,S:dÆ.~jY·:1:~·~1!I/,)G±..,\.·· . .. :..... } ! ~ , i .ò à(,.C;76 - IZ1,Ç" 124$'- Ir4~ _ I $"4 S - 11 csq 17Ct1J-/Q'$O I ./'3D. 'Z.o1~ 2,04 ~ - %/ tx:> I 7./()ð 1,1/ ~ -Zl/~ - 2.14~ -zt4S- ZZo:r:> "2.. '2.ðO "Z. Z I ~. t.?../ .f 2. "2-4 S-: z'24~ - 0 Goo '.13O"Æ ?CST «/I'TA/£-~.s ~y Mr. ~.W" 5IfP~., Tr< AúdSkd 0 ':~c:.c. ,.,qK oE'F7ë~~·'273S(2"77V~).=_giP3 PST./Pr &'ZADt€J./T &"~ r/5.7 ?f'G t:qUlfl. MV!:J. . 11 SUMMARY OF OPERATIONS . ,- 133 3ZC 32~ ~.'~lf4 G 177. £.:: 2ð.!J ~OJ "L'Z .3 2¡~ß .1 ZS~ zç~ '. 3,2/ \8Ý-a.N44tAJ 2"73.r· , ~/f...,v~ðlV ;."~~' . 'z'f'/';¡P '/7JJ ·~:Jlo , . . DLS TVD . -:'-sEëT~7'·· ·N{#tO-=.:. .<"I/weo eOMDEP AN-G/nIR .:l'"1V c.... " 9 BIT NO RT HRS WEIGHT RPM 1- ! PS ~ <;~;:,;:;:'. i.kR SZ GRADE SPM --~--"-1 Z73Ç z~z.3 .295 z. -I/: ; r+ -# _ ,6 _~ /4 SV NO : 10 ·1 7 DRLG ASSY BIT NO. -# 1 «" 'i3/ Ng/· ><"0/ MJoIIZlé..U":/· Z 1V1./'S7""A!Ò/ ,M I 54( / Z lJc./ :~ræ/7:j"411$ ,xó/ Hw/J~ B BIT NO . SIZE MÅIŒ: " TYPE ..5R NO J:r;TSDEPOUT FTG . 4- 1~~Y1' Hí< osc.-1A1" ,--F ~~~ ..~,-?~" rOTAL 8~ (5'1 'Z- RMF 7S'F" I .. FL ;CA1Œ I 'ð'..' . . :J.. . , S UPVR . "FERN41\i Dt""L- EQ? .. \ ,~'-'" ~2.· WEATHER 2.lfHR FTC; . -:,30 H G 4 t-tüD/WT VIS PV-yp GELS TEMP tf·,('" . ~n' ) -:i. ~ ?'-.'i' . .s-7J '5 PH SAND SOLIDS HT-HP CHLOR q Tt')<¿ ~. , - 460 '.6 ~]ELL COsr INTANG TANG - 0~'74b~' 17.4'~O A/F/D 7 WATER 14-b<) DR. lLLING FUEL '3~ 2.1 3 . CURRENT OPERATIONS . , 1 DATE WELL \ . "Z.~ - <¿'Z. ~·3 , 2 MEN BEDS 1-0 52- ! 'DAY NO DEPTH 5 ';025 RIG ~Z.é .-". . ,"I . E 'F . D c . .-....þ..--"..... '. -.. - . . -.. : "." --~~-~~~--~----~-~~-----~~-~-~-- . . . . .- ~.~/ :.::,~'.~~~~~~~~~~:; ~ - . - ~:. ~ ~ . . B A . .2i'ii~f;~'i:..~~:;'r:~W~;~~~?E!r~p~:~~t . ~~.:::NG ':f::Y' '·";?j,~\B::-;f.s¿fI.$;{~~N.:~~:~~*~~;I· : ,i!~~~?T:~:~>:':::·~·:.·~;~:;:¡·::?:~r~1ç~~.;K:&~:~ '.~~ ~f' Exh ibit V, - Be ;~~:':~:!'~:':3(;-~:: :,.::...~~. ;.:..:.:::::{-.'.;.::." . ":':":":':501110'.. .'·.DIÙLY· DRILLING' r ÙìT ,.. . -."" . ~:::::::~:P¿~~~~~~~~~~~::::~::: MEN BEDS FUEL WATER /1 - sz- - ,J 7.1 ..:;>~ '1 ï' '. 70'()' CURRENT OPERATIONS Wð¡Lt¿/^'í 4 NUD/\~T VIS PV-yp GELS TEMP /0. ;3 f. 37' 17:9 3-." .' 7G. '5 PH SAND SOLIDS HT.-HP CHLOR q,S" D II -. S-e>o A' ¡3 .'1 DATE . WELL' ,;2.-\1 '81.. S-3 2 3 · '":' '.::."" ," '.. ·i:~·i0~~~~;;S\!'!~m'.·;1'f,~\ .:~'/!;: '~.'. . , ". ._--..~--.........- "... , c .. D ',' E F G H ' . I I DEPTH 2111iR FTG WEATHER I 1,840. -e- A/F/D BOP S UPVR :;J&?' 1.-"2..-'ß"Z S77U...L~ U:-- S7Z!-C£ C 42f' / /1Æ7 nIG 22t: DAY NO 24 FL' L¡./~, . t I ' ÇA¥.E ) ,'I RM·:" !75: F:~ ¡ . :.- , ;l. .1 '. '1 . t~TAL ~ 1 J-~.!"Í 3. . . . 6 \oJELL cOsr I NTANG TANG . . 1779.J@·3 7 DRLG ASSY BIT .NO. 9· BIT, NO RT 11RS·. ~'¡EIGHT RPM ; lØ SV NO COMDEP AN"QI'DIR TVD '. ...:....." . ~'. B BIT NO .SIZE ~. 11 SUMi'1ARY OF ¡Ç)6t?~._ - tJ ft:Jo o 7tJð.. - (()f2. 0' oý.:7() ¿' lOt) 0 /4 I/cJ . /~ /t.p.(). 170,,=, ~ .. .' I¡ /7G:1o - /t.3o / g3u'_ I 'ýOC> ¡f(),~ - :)D2ð. ";¡O.?n -=-.23ðo .þ_'__ ð ~ 0 o-:;.JL'3:J _9.. 0110- 0600 --------- ------- , '74-i..~ò·:.';~. , . I . -1 MAY.E . TYPE . .SR NO JETS I DEPOUT FTG L '. PS :.. ? ;J.~~~~~. . L~n S z s rM GRADE .... . ...:.. .........' ~.,.-I,. -..:-: . 'SECT .-.'... ti/séo -::. . Eiwco DLS ! . . ..---. :!' 1.1 -\ .OPERATIONS . /I .\ /~(Ç ki.-P/h/2 .':. i»J#K . ~~ 7J/2,4~;().IÎ-(J '..7<::> MÐïD¿ (!OuPu,v; / CI~. R. /. 7/';0 ir~ /' f,fn~ ~. ¡ .~:-~ ' . Wqr~. fõ jJTM ! A/il ß /..L. " j)Æy)1~ JJ ;:? O.ì/, ; b., vt~~ ¡?:7/:,tJ..- _ .,;'~ ¡ ~\ "c'U7'b1 P{Qt)"-, c,if,f-A.6t" 7:> qf(¡- RM,J1!. ; &( (/? 1/Vl:-rrrL f3"J#/~ I2v-AP/~t"j 1'ó~(, .f,. '. ,; ïæ:y 13?Ul..( (.,I/f-?r¡Z í]vfl:f//t4':,:Pu:a.,^/j.Ðor err' ïJlIf/'///'"c¡ IY1 6J K í?c..K.·~vp Í/l.¡. t//17f., .s-,z>~Ì'"~ ./)/:-M·IN1,~;:t/Jf/I¡t1 l' ¡"/v¿( tJ(,¿~ tJK ær7 75 ~~ ~~ cS'/V7. -. ¡. . \\ . ~~¡VIPIÍ C¡k/ll.t7 I , /' . ~.J j L' 7J. A' T ,-I)-(/.~:j..._;;-~-¡¡-//pr~) 7 T /9 / /l~"-..2 ¿ /;/$ ~_ /1 ~l/ P : ,/'JJ:O -.. ·-J?17:.o 'Ct'/lv ..., CIj¿~¿¿4~/x..¡ ·-¡úJ~.~"~í ~~«, e ; . ?,,~[. '-- P~'-~n -7:õ . J~;,ÓDO ~ Á.ø~- /,( "-¿t-C:-1¿N,.. I ~. -ì"&.· ,: :. . " . .". ~ :T· i' .'. -. . . . .." . .: i .. . ..,:}' . , --------- ~-_._._----- ----- ·t.··. . -L.·-: ~I'I .... -~ A .1 DATE . WELL '2-11 -g1. S - 3 .1-;"_.. it...__...."::!-.~:,..~.._.' ~. :'~ .~~; '(I:·~~.~~f·-··-· :~ Exhibit VI - C$C .... ........:-..~..~...~.. ~ ~:- :__".:.'-'~"'>:'.:'. ....-:... ~·;-";·:"'"~·~t:~ --:'-;_~"~:~. -'."-' .. :.- ... .. ..' . . SOH~O/BP.DA~LY ~R~LL~NG ~~~T .. --..... -..- -..... - --.. - -- --........ - -- - - -:- -.. B BEDS .f~ SAND o COMDEP - - . . - ...' -'. ~ ~ : - ø 6 ø 0 . f¡ 0 ~"RS : . . . - - . _. . - . . . ~.._---~~-~-- ." "0 ~ C D .- . #1/1 .. _ .. .. .. .. .. . .. ... H E ¡G F ¡. i RIG 1.1. t: 'DAY NO DEPTH 24HR FTC:' ¡ '2~ '1/54-~.·; ð- . ~ WEATHER 2 MEN 1£ FUEL "1 8~"2- CURRENT OPERATIONS WATER ØðO 3 4 twtUD/WT VIS /O,C) 3~ . . 5 PH i'.tJ '6 \·lELL COST 7 DRLG ASSY 8 B1T NO . SIZE µ?T/~tS Pv-yp 1¥-7 GELS .,2-'/ SOLIDS HT-HP lb' INTANG I øJ"E 7/4- BIT NO. MAY.E . TYPE 9 BIT NO RT HRS WEIGHT RPM . lØ SV NO AN-GrDIR TVD A/F/D '<'7 BOP Z· J~.. ß"'t- ¡ I I SUPVR ~~t!t.E 7-- D. R ~7.:"i?<:J:::.. ~ TEMP CAKE '/ FL $"..~ CHLOR j,"V u " RÞ1F .75' F ~~..!.:... I ~ TANG 371830 (:/. j - T·OTAL .2.2_ 3 7 () 2-3 I SR NO JETS DEPOüT FTG / . PSI E· ~ LUR SZ .SPM GRADE - --SEéT'~' 'N/:3ëO E/WCO DLS ...... t?,.1~" c.fµJ !Ji--'7,4IL. - /~ 191 Jo;A.71' Rnrr ~Ñt;r /9-7 'l3¡'-z-' P4n4 "7 C e:x..UI}A ¡¡.. 7 '1 '2- b) , ß'f' P«5 '/~ 14-,. '1~-'' ' .$ JlvT cJN= /1-'1' 118(P , OF OPERATIONS Ci~t.,.I ., lA.)(,;-,Ùc In,t..CIt' fJ'h~" C("~/ I~ ~r' Jr If 192- 1.-' r - -. I: 7'\,A-nd ~ jC11; ",p rÞ C~;H~ i /.c-TI ¿I',A...~-S '.. "",---,.. /.IT,..., p¿t(~ M/)( ..z.rD {"J;j Ct./Xt;'~'- tv/r~' FA!!~I ~U()u..id:> R'T JÒó) r~{ ( (.../x t; <f .. /\I t:¡4 7: - I::> ~ ð1'" ;Þt.1Ii t"j J)'1j>Un.t-- C.£:-7U~7t-T ~/~t) PÛJ:'1'p, 7JtI~ø 'P1..tl..i ,,^ lAJ/ 7"",c)~ ¡2h~;'; Cf:"J#t"Yr&-Y2-J 'þ/2,4'N 13',O·¡::J/r~,tlI·IP-i'::Þ¡.·r· þ;'(.&.JIV To ¿~J. ~~AJ~ ,.." '5t../ P!. . . I" 11 L/fÑF)~). 1 rJ¡ -Cf~i I&t ,r;¿,{J.s tJ/2!(;t::)/tJtJD f' ¥II ð'\A r¿ ¡pS . - Cot.<. r ðrr : ?~:. ". . Y . I ?'~ S J'i:¡7J, OqT, ÞIPPt:~ d~~ ~tqM $O~.I S77b£/J &;H.ié: /1.0/; ! p~ 'Iff.J '" ~.fr"a .sf4~)I'172'Ý ~~NV1".$ ~ 1 p...e7NfTn.·J..L r",ß,,'" tj .$~aø'- {r~r ev-,1-oøo.r: - þIPPJ-t"';p ¡;r,c:-';:?~ 4,.... 7 t!"fr ?"U~(," I r f:-"T r P: éJ .?!, f T tk-It: . ; I ! i 1 SUMMARY ()~ - _j 3~O I~ 10 .. /.1 ~r 134J-." 1'10- I L//.1- - I j-/J- 1.1-/.1- - 14""10 ./ 1 I~JO - 21()(2ð ) t){;() - f) ~l:JJO C~)() '. (J{,dtt> . " : 1" ~'/;... t11f Iv g~' ßtJTra<-Sf ¿ I" . I. [; I ,.12. , . ~ ¡ I v " . I ...._....~_...... t... _ t::XnlDll v I - O. (j ::~~.;~~~1~t~.;.>~::·~·~·;· ~ : :"':~':';;"~~,: <;:~.~.::'~.:~.~~..~;~.~'.[\.~.:;.~.?:.;.:,~.;{:.j~_~Þ~r.?:;.:1 ';'¡~·.~.!Sf~(:0:::>:~·~"::~~}~fr~fr~~i~ BPDA!LY DR!LL!NG '~0f!T ..' ······1 .0 .. _ ..........._.... __ _ -._.. ....__.......... _... ..._í.. _ _... . ... - ... .:. .':.:.~..:'.~ Ø6ØØ· ftO~RS : . . . . . . > ;. . . . . ------....--.......... .--................6',. A 13 C D E F G H . 1 DATE . WELL RIG DAY NO DEPT~ Z4HR F'TC::~ : WEATHER 2.-J~'t¡,1.. Ç·3 1..-~J:Ç Z~ . I/¡ S . £' 2 MEN BEDS FUEL WATER A/F/D goP : SUPVR 3q 5"1- :::27.g.o 2o¡) ? lÐ· ¡z - ,/ 7 - i3 ~l- 577¿U/jL£' 3 CURRENT OPERATIONS (tJ,,& lJ I F/ CA.- /·jl~·1 ( I"r i; 7" t / A/¡:7¿ .' ,! : I CAKE / 4 NUD/WT VIS PV-VP GELS /0..:2..' '/2 . 17~8 Z. -1>-' .' '5 PH SAND SOLIDS HT-HP /d·S- T/( /,).. -'. WELL COSr INTANG TANG TOTAL li3f4/.~a- .3/~.3..0~.~J·-. ii:<. 72- 44~- DRLG A5SY BIT NO~ Jt"/~. .. lIlT f RMliti?+s qf j)(.7·5 of .'2' /l) ( +- 5 + Y¿; i~ J/Jll f.¡- /d {,(/ DP. - BIT NO SIZE MAY.E . TYPE . .SR NO JErfS DEPOUT FTG ~. 1,$ t31~ i2.e7> ~ II~ q 3c;C¡ I q ~"~(r( ? . .. c·( (-r/t'v C ,>;- ··6 7 8 TEMP FL: SÔ CHLOR RMF 7S'F .!::. ë::> c.) i..-.. I .. 9 BIT NO RT HRS t.¡'E·! GHT RPM PSI .~# ~. L~Fl SZ ¡SPM GRADE =-:".;;, "~';:' - - . . -........ . : lØ SV NO COMDEP AN-G/DIR T\7D ":""SEêT'-':- - N/5CO -::;-: E/WCO DLS - .. .', i .~ - ...?"" I - ¡Ç> ~cç () -¡ Po 11 SUMNAny OF OPERATIONS ?t"r r ï? 0 P, (" ,"7JC J:: I )7¿.LL( :·'/J;!7' ·küL7 1./ h.5T(rt.L ~ /A'tJ)/ ,- I I tÞ 1J..o - 0 if ¿?C> 0ttø - /34J- IJt!J- - /¡)'/J- /t/LfJ-- IJí/- ¡[iF - 171J- 1"1"( - ~o t/J- :b4.j- - ;J.( ~ ,7,30 - ;;L(vo ~~ - oO/J- (/)tP/j" -. IP/Po .' (J)'~fcJt) ~ 19136 ø13o. - (p6CJ~ 4,10')11 í3//{;-f/M'7 ·'AtJ.K.-UP . 2'0.... ß-;/rJ . ..¡t, % II, .,; h/6"tJ Co IAI"/)J' / 'bO 1I1PJ.fJ. i j)/ZL? C 11'/7 í.:::> 770"J ' /2 j I4Pl?ld l¿~µ ¡?-t1Ué:-/l,iA,t(1~ dðl-£-:.~/ f)/2L 7 C MT 7ó Rf77"1 ~I ·(CJ{...(·dlt ~ It··(í ~"'rA£] 2,1)"~o;r· D ~ ær, /ZtPt:Jllt I tic/I--- l¿t/UílJ.AJ/{k',' . ---,...:t l}/2L7 9Úr1ú / /0 rf[:' /It/1' _Y?t-7¿JW . ç~--&, / /'Ù<A..J/lIu J ::~r,Ji.·) (.~K, /¡?.~ II ! tu4:!./I- I~fdô Îe) 1/,11-0 75rßrlt,,, éJf:::-,~ .1)d./~L {' ;V-(;;~c..u-.:~ Æ:~¿p-,- . {Ó ,A/,!t1£:.:... _ '. ·~<-;f::;;;t~..~~;:<=/~.~:7JQ/ d~ 0sJ~è-P1 ~u= CLt-ìt~ 1 ;- . -m-t7 (¡LIT 1/78 ' k it J. . -. A B . 1 DATE . WELL 'l... -IJ-- g"L ,Ç-t . '.'- .... ,:..,: ".:: '.:..>J:~~.~.:~. . j..._. .-;..'~"..-:t:!~'":':' .,. I. .: .~ :::.~,:~~~.:''''i:''~''._~ :. '.' ~ ~ ':(~':'-'~./:' . ;-. Exhibit VI - Be . ". .... :':;~~.:~.'/: '~·~~;¡.i:)~·\.::::":··:·:::; '. . , ~ ~ ". ·~···;:r.:::" .... . .. '--- . . SOH~O/BPDA~L~ 1?R!LL~NG~ORT -~~---~---------~-~~~-~~~~-~~--- . .- .. - - - -' - ~ -.- 0600 - flOURS: - - . - . . ,-. - . - .. ~~----~-~--- . I: . .- ... - .. - # . ... .. - .. ... .. C D E .-!; t I H F! RIG ~"2.I::.- DAY NO DEPTH 24HR FTG~ ~ ~ I~ß~S: ~ WEATHER 2 MEN 31 ; FUEL WATER A/F /D ~{jp :; ·1(P t"2.-' 1000' .21 . i-/1. -182-·!0: ¡ ¿! CURRENT OPERAT~ONS ¡WII¡(¡M¡ vp E-Z DR.,'-&. ç 7êJoLS. SUPVR '5íJ2v (j L 1.- - 3 BEDS J~ . ; 4 MüD/WT VIS Pv-yp GELS TEMP FL' /û~/ /II IS-- Ý 3-1 4;J(. , 5 PH SAND SOLIDS HT-HP CHLOR RMF /...).j T/2 /2 - . 500 ; INTANG 2a:;'!f t::/ ~J-I DRLG ASSY BIT NO.4-2KÆ '8/1--t C~~ ~GtpPt=H +. -z. 1>c rJ #P r ~ .ò. /Y _. B BIT NO SIZE NAKE . TYPE· .sit NO jttrS 'Ø¡}/1Vl Ì(ÝL- f2a1) $11 J 73011" ;ðtJT 9 BIT NO RT HRS WEIGHT RPM . 6 "'ELL COST 7 CAKE ./ 7StY'. ¡' '. TANG tOTAL .: ;i r ! ;{..\ Ie, 'Z- :2-4- .~ !" 4-7/317 - (: >" g.:! i ~EPOüT FTG :! c. £..f-~ () vi ¡ ! ¡I ! I ! I I I I I I .. PSI .1..NR S Z S PM GRADE j . ... L.'·L SECT N/ZCO p/WCO DLS . "." ,,·:-~¿·I. -.... /;;9 .d~·n\ ~ ? ,I -;:2 h~ /<1 ¿¡I .w I, lØ SV NO COMDEP ANGiDIR TVD 1"- Llk/:-'71 Òk-?+~'- - /~ HÆJ;v(;.,c)( #7 &> 7 8 t!j , A". ¿ÂJ'.-I)~~ /ñú/.fH /1/ h ~ ",. Hø7+-7' ~ II~ 7~7 I h~'" J"HtrG" Ii! 4-'0 ' - . ~, ¡ . ~ I ~ I· 11 SUMMARY OF OPERATIONS o ~oo - otP70o R. /.,) wi [/ÑBl. b70c:J - .~ 1:3 If' øe; 10, ¿J9iJ - .-!Þ.!1~J ".... I' ð ð //1J0 - {FIJ- I ~ I /I fJ - I ¿'dtJ '''40 - II, 30 1(,2" - I?')o 113() - J 7S'o /1fo- I t/J- . I tIS - ;¡ ~O<) - ~ - l!:!1:7D <J/Jo - o~co p 2-ø~ - eJ'.rJo- ... r-? h . '" ¿, '" ,.., C (If (.... 1)r;u.$ ~p - .,¡. .-' . 7b-T T £..//&/1:'-5 - 3 ~ DO ð r, dx . l~~ ,S/(J CUr.:f) 'I;" U7J /) rL'fltè 'r ~.I}-{ P~7I Pttc6dA-l.. /Gt..£.~....:> ÚJi7P Ij-OO r,K.f ClMf '(7" tH +-~Llc.41tr; p~·ø t1~4""'. ~ (, /. p. J/4.rlvJ, 7)1 J P¿';.}C.(:#" w / Il, f P U .." P ~ })/¡) ¡tf~? ð:p.t'"k' ~ E S/,!£»rl (JuT -' 13vM A ! f>L«{¡ ;,., -¡;Mc- - ~530~ 7ð' ~.7 ~..:ii,~. 14'l",,ff'D VK, . j '? 0.1/. - t~'r' Þ'lJ)¡!4J .{ 0#/0 S-¡/3 J'- 'ÞJ~ if.. _ ·'ltc.., uP CFMé"~r u~ T..ø t=1I/1(.tl.S71f71.:rt·~ I,c~-;/ - ¡;LL ¡?:A;NIA..V}S I /¡vJlc.r .711I0 "61 ~rt7L - IAJ7i~~ ß/}· 7tJfJ PlI .-ç/Æ-()/J 7a buo pII. . ¡t/¡ x 101") ~/~J /Î12~rtc"- .ft.-., r - r: 6ocdr: I ; I íJ'SRAa- C~T tu/rH 120 JI/;/$ ;f)ÇT''- P,q.. - ¡:¡",,~ 'PÆÆ$f~A.f-- hooPSI! W, (). ð.. - / jJ. !f"~l ì ? "~41~Á6. - ~ /)~ r'(J)IIJ::-é.0 2-¿- (Jail ¡2 ./.I'/- ~ / ! ~ If /J ff rf 5C/2~l:n. 7lI6 .~,4 b ^,~-n. "hD (~ï. - ! rifT LIJlHl ÚP,' '&.t# dtJ-l4V t1J /'1oo;~I/NJlrr 1~ Ilðo # -~f'BP"'. (,t/U. ÀAr Api: f J=! ¿'J.;/. 70 s¡q~-'Z'4f ¿,A,,~?t..~, f'J.. 01 ,.n yjö,. In Ln j:-? 7')4" ~ ~- ...... ", ",., ·1: .' . I .. ~I. . . . '.... ,.-. '..1 ·~···:.::·;::;r>·. ..:~. : Exhibit VI - 8c ... '" . ..I·.·...'. I. .......( .' ..... ..... ~ :~':<:'I;'~" . . r ì ¡ i, SOH~O/BP DA~L~ ~R~LL~NG ~ORT ------~-~~~~--~--~---------~~~-~ - . -.' '- . .60>...."'...._....___ .. . - u ...-: - - 06ØØ- fiO~RS: -.. - . ·;r· H -~--~-~---~- ~ . A B D E C . 1 DATE . WELL RIG 2-/b,SL f-J . ~ z: ~- 2 MEN BEDS FUEL 41 S7- J17.1- 3 CURRENT OPERATIONS DA.Y NO 21 DEPTH It ~~.¡ WATER #-~O . AIFID ~ð ? 0 Ii, 4 NUD/WT VIS J tJ" / 'I),' '5 PH SAND 1:).5 7£ '6 "IELL COST PV-yp GELS TEMP I ~...- /() 1'-9 SOLIDS HT-HP CHLOR ;1,.. - .S;') 1..) INTANG ;;¿-'4- ~ 7+2... TANG C/r¡ I 11 7 ;' 7 DRLG ASSY BIT NO. 1J:./1 ]3/T-r jU/VJ(JtJ~ t-Xo T .5': Dc- ~ J~s ~ -pp,. BIT NO SIZE MAIŒ . TYPE .SR NO ~ Ie¡ ~ï.{.'J ~tEt. rl4-#..J 92 '1792- 8 9 BIT NO RT HRS "IEIGHT RPM PSI . 10 SV NO COMDEP AN-G/bIR TVD SECT F G H 2;4HR FT G 9- WEATHER BOP 'I ! ~1-/2-~i..; 5 UPVR [r.eu.. f$¿ E . !1 F.~ ~Þ.' . . ~ CAKE I RMF 75' F. ~.:, - ' I ~.:~ .TOTAL . t I (i í :?-f:. 20139 tJETS pctr þEPOUT FTG r j)d/~ {.... 0 ~ T 1. c.,ui, ~ . 1 Lf:q SZ i ~ i ~ I N~~ÓO_ . './'.' I --. SPM GRADE E/WCO DLS I' .: .1 I ): !~. 11 SUMr-!ÁRY OF OPERATIONS I, ð?:er~ 'Ö?Oø ~f' ~J ¡'P¡Uf 'vp [-] ..ðdlJ. 7óDf. {'. () 1 ()f) - ~ J Ii' ll, 'í ~p¡4 ,If. / rl'4z r?- P1/2 L/Nt o l¡[' (),,3o ~ I /1 ¡µ / E-z. ~,,- -12$~'O -/ol/.J-· /'7,? ¡; 4 UF/-o Z£.,I t'.fif.~r ~~Æ-' ¿)ft:! r r;C, ,04,J- - /)0,) - fiT'" ¡; "z. lJ/2..JL t--srMl/JIJ /A..,J{"~T,i)~··7;¡Z~.-rJlI/k-:I' - /IOt/1 q..! 4. g;'1I /"/P Pa« .ø~l E':; lJ~,- Pv",,~ 28 ~\¡ /I"1.ð J "O~ ZC8 I'~ j {¿/X~ '(;" I. ~Mr , /)¡t,p ~/,(}~h PLvtf rI /)IJP{~cr 10 ~ I~ ÏilJI I/. c.,) I).T ,ððLð/~ II1D -. bJ'ð PI' /,...~ dtOKE; 51M'! ¡:-'''' r. ,L,r ~ b",¿. f >qu<l-~~ - : (~n 1~7i/tl. pM--rr,,¡t!r fûa "-I RU1Lð/A/ 7õ ,~:.:t(), PL..tlií 111J~~ ¿ 'rkø ðt 1.2--0 - "I) ?u..q ¡tjf./ T '20ø / ¡I' ~1¡ILc- " £.'-~ï:ht. :~f~'="· L'''~i-3" . - C. I, P. /14J.-h,¡. : ( 3p-.. !S IJ~ PO.r! I..rf).,.. d,u-;- /1 .c). tu. ~ / ~n'\'.S I ' , ~' ~ I / [I)() -).0 30 0.0.€. - ~~J ;1<: ! ~o3.0 -1-'1..)¿)" 11c£vp !?17 / .kfl.~ ~15/ 7)C.r .{ ¡¿·r(/. , ~ CM r ¿¿;,r b 708' I 11. ~ -.0 ]Oð /}tlu- IJ(J ë (' MT, G -2 l>~/ll. ø é/j.ú4 c;",j, r r,:) 1'óP LJAdlt t.:t-(/J'}ß,,1 l>"3cd . 04'0 (,~e.. I~ It.I, . D~ -o1/J- 'Íerr Li-itl-1t. ¡tAli Jøo1l () K.. n41r - Ð hr1n. - 1)£)v P,/.1t· ð P. D ,I. / I I /1 Exhibit VI-9: S-24A Well Integrity Report Original Completion Date: S-24A: 9/7/99 (S-24: 6/5/90) Schrader Bluff Penetration Hole Diameter: 9-7/8" Schrader Bluff Penetration Casing Diameter: 7" ( Well Status as of 9/2002: Cement Logs Across Schrader Bluff: WAG Injector, currently on MI None Comments: S-24 was originally drilled in 6/90. On 4/27/90 the 13-3/8" casing was tested to 3000 psi and held. On 5/6/90 the 9-5/8" casing was tested to 3000 psi and held. The original well was abandoned in 8/99 by setting a bridge plug in the 9-58" casing at 3020', cutting and milling 9-5/8" casing to 2739' and cement plugging back. Final PBTD 2669' pressure tested to 2500 psi and held. On 8/28/99 the 7" intermediate casing of the new well was tested to 4000 psi for 30 minutes and held. ( Additional Information: Exhibit VI-9a Exhibit VI-9b Exhibit VI-9c Well Diagram Directional Survey Drilling Daily Reports lREE = 4-1 I£!' CW WELLHEAD = McEVOY ACTUA TOR = AX8..SON KB. ElEV = 64.77' BF. 8..EV = 35.43' KOP = 2782' WaxAngle= 97@12411' '~tum fvI) = 10430" ~tum 1V 0 = 8800' SS I TOP OF CEMENT H 2669' 113-318" CSG, 68#, ~80, 10 = 12.415" H 2668' '-, Exhibit VI - 9a S-24A SAFETY NOTES: 9-518" CSG cur, Pl1.LB> & MILLED FROM SURFACE TO STLB @ 2739' HORIZONTAL LNR 70° @ 10383' AND 900 @ 11758' (9 l 2195" H4-lIZ' H:S SSSV NP,ID = 3.813" I ~ PERFORA 1l0N SUvlML\RY RB= LOG: ANGL EAT TOP PERF: 97 @ 12377' t-bte: Refer to Ffoductbn œ for historical perf data SIZE SPF INTffiV AL Opn/Sqz DATE 2-7/£!' 4 12377 - 12597 0 09199 PBTO H 12599' I 4-lIZ' LNR,12.6#, L-80, 0.0152 bpf,lO = 3.95£!' H 12687' 9941' H4-112" X NIp, 10= 3.813" I 9952" H7" BAKER 5-3 A<R, 10= 3.875' I 9975" 1-14-112" X NIP, 10 = 3.813" I 9996' H4-1I2" XN NP, D = 3.725" I 10004" H8..MDTTLOGGED09/24/99 10008" H.4-1/2"W/LEG, 10= 4.00" I Minimum ID = 3.725" @ 9996' 4·1/2" XN NIP PLE 19-51£!' EZSV H 3020' 10LD 9-5/8" CSG I ITOP OF 4-1/2" Lf\R H 10003" I 4-lIZ'1BG,12.6#, L-80, 0.0152 bpf,ID= 3.958" H 10008" I 7" LNR, 26#, L-80 rvoD, 0.0383 bpf, D = 6.276" H 10180" I DA.TE 05/12/00 09107/99 03/14/01 03/15/01 03102/02 SI5-~ S IS- fvI) RWTP CO~ENTS ORGlNAL COt\oPLETION SIDETRACK COMA.ET10N CONY ERTED TO CA NY AS FINAL CORRB:;TIONS DA.1E REV BY COMfÆNTS PRlDH:>E BA Y LNrr WELL: 5-24A PERMrr No: 198-2450 AA No: 50-029-22044-01 SEe 35, T12N. T12E BP Exploratbn (A las ka) REV BY Well S:'24A Directional Surv-'f ~ Exhibit VI - 9b '--' Well: I~~~~~. . .-. ..... .-_.-.-~...-, ._..___.....m..u..._....... ..........---...--..-......-..--.....-..--.........--.--.-.-------------.----------..----- API/UWI: 500292204401 Survey Type: COMP Company: Schlumberger - Anadrill Survey Date: 09/02/99 Survey Top: 0' MD Survey Btm: 12,700' MD .. -- - - ----_.-. - --- -- ----"---------------------- ----------_._----------- -~~---- -.- --.-.---------- ------.-- --- -- ------ --- - ---.+ MD TVD SS INCLINE AZIMUTH DOGLEG ASP_X ASP_Y 0 0.00 63.77 0.00 0.00 0.0 619,212.3 5,979,854.9 6 5.88 57.89 0.42 116.35 0.0 619,212.3 5,979,854.9 14 14.38 49.39 0.42 110.28 0.5 619,212.4 5,979,855.0 24 23.78 39.99 0.30 94.68 1.6 619,212.4 5,979,855.0 33 33.38 30.39 0.17 74.68 1.6 619,212.4 5,979,855.0 45 44.58 19.19 0.15 30.16 1.1 619,212.5 5,979,855.0 56 55.98 7.79 0.17 342.01 1.2 619,212.5 5,979,855.0 67 67.33 -3.56 0.18 328.07 0.4 619,212.5 5,979,855.0 79 78.73 -14.96 0.15 326.52 0.3 619,212.4 5,979,855.0 90 90.13 -26.36 0.12 335.52 0.3 619,212.4 5,979,855.0 102 101. 53 -37.76 0.10 347.61 0.3 619,212.4 5,979,855.0 113 112.93 -49.16 0.08 348.69 0.2 619,212.4 5,979,855.0 124 124.43 -60.66 0.08 324.81 0.3 619,212.4 5,979,855.0 136 135.88 -72.11 0.07 288.77 0.4 619,212.4 5,979,855.0 147 147.38 -83.61 0.08 259.82 0.3 619,212.4 5,979,855.0 159 158.78 -95.01 0.10 236.88 0.4 619,212.4 5,979,855.0 170 170.18 -106.41 0.13 219.89 0.4 619,212.4 5,979,855.0 182 181. 58 -117.81 0.15 209.80 0.3 619,212.4 5,979,855.0 193 192.78 -129.01 0.17 206.95 0.2 619,212.3 5,979,854.9 204 204.08 -140.31 0.18 204.10 0.1 619,212.3 5,979,854.9 215 215.33 -151.56 0.20 194.91 0.3 619,212.3 5,979,854.9 227 226.63 -162.86 0.22 183.42 0.4 619,212.3 5,979,854.9 238 237.93 -174.16 0.23 175.17 0.3 619,212.3 5,979,854.9 249 249.23 -185.46 0.25 166.64 0.4 619,212.3 5,979,854.9 261 260.53 -196.76 0.27 155.87 0.5 619,212.3 5,979,854.6 272 271.83 -208.06 0.27 144.10 0.5 619,212.4 5,979,854.6 283 283.03 -219.26 0.28 130.55 0.6 619,212.4 5,979,854.6 294 294.33 -230.56 0.28 117.01 0.6 619,212.4 5,979,854.6 306 305.53 -241. 76 0.28 104.30 0.6 619,212.5 5,979,854.6 317 316.83 -253.06 0.27 89.78 0.6 619,212.5 5,979,854.6 328 328.03 -264.26 0.23 76.95 0.6 619,212.5 5,979,854.6 339 339.28 -275.51 0.22 68.01 0.3 619,212.6 5,979,854.6 351 350.58 -286.81 0.17 59.42 0.5 619,212.6 5,979,854.6 362 361. 88 -298.11 0.12 49.69 0.5 619,212.6 5,979,854.6 373 373.18 -309.41 0.05 27.29 0.7 619,212.6 5,979,854.6 384 384.48 -320.71 0.03 290.86 0.5 619,212.6 5,979,854.6 396 395.78 -332.01 0.12 206.77 1.1 619,212.6 5,979,854.6 407 407.08 -343.31 0.17 199.57 0.5 619,212.6 5,979,854.6 418 418.33 -354.56 0.22 191. 68 0.5 619,212.6 5,979,854.6 430 429.58 -365.81 0.23 184.15 0.3 619,212.6 5,979,854.6 441 440.88 -377.11 0.23 175.67 0.3 619,212.6 5,979,854.6 452 452.18 -388.41 0.25 161. 59 0.6 619,212.6 5,979,854.6 463 463.48 -399.71 0.27 145.86 0.7 619/212.6 5,979,854.6 475 474.78 -411.01 0.25 129.96 0.7 619,212.8 5,979,854.2 486 486.08 -422.31 0.23 114.24 0.6 619,212.8 5,979,854.2 497 497.33 -433.56 0.20 99.89 0.5 619,212.8 5,979,854.2 509 508.63 -444.86 0.15 85.09 0.6 619,212.9 5,979,854.2 520 519.88 -456.11 0.10 66.36 0.6 619,212.9 5,979,854.2 531 531.18 -467.41 0.07 41.78 0.4 619,212.9 5,979,854.2 542 542.43 -478.66 0.05 350.03 0.5 619,212.9 5,979,854.2 554 553.73 -489.96 0.5 619,212.9 5,979,854.2 565 565.03 -501.26 '~ Exhibit VI - 9b 0.6 619;-· ?9 5,979,854.2 576 576.33 -512.56 0.5 619,~~.9 5,979,854.2 588 587.68 -523.91 0.3 619,212.8 5,979,854.2 599 598.98 -535.21 0.17 205.50 0.3 619,212.8 5,979,854.2 610 610.28 -546.51 0.17 191.58 0.4 619,212.8 5,979,854.2 622 621.53 -557.76 0.18 173.02 0.5 619,212.8 5,979,854.2 633 632.83 -569.06 0.18 154.60 0.5 619,212.8 5,979,854.2 644 644.18 -580.41 0.17 135.37 0.5 619,212.8 5,979,854.2 655 655.43 -591.66 0.15 116.19 0.5 619,212.9 5,979,854.2 667 666.73 -602.96 0.15 91.98 0.6 619,212.9 5,979,854.2 678 678.03 -614.26 0.12 62.50 0.7 619,212.9 5,979,854.2 689 689.28 -625.51 0.08 38.17 0.5 619,212.9 5,979,854.2 701 700.58 -636.81 0.08 9.56 0.4 619,212.9 5,979,854.2 712 711. 78 -648.01 0.07 333.95 0.4 619,212.9 5,979,854.2 723 722.98 -659.21 0.07 298.27 0.4 619,212.9 5,979,854.2 734 734.23 -670.46 0.05 255.33 0.4 619,212.9 5,979,854.2 745 745.48 -681. 71 0.08 222.57 0.4 619,212.9 5,979,854.2 757 756.73 -692.96 0.10 200.54 0.4 619,212.9 5,979,854.2 768 768.03 -704.26 0.12 176.75 0.4 619,212.9 5,979,854.2 779 779.33 -715.56 0.13 157.09 0.4 619,212.9 5,979,854.2 791 790.58 -726.81 0.15 138.58 0.4 619,212.9 5,979,854.2 802 801.83 -738.06 0.17 120.10 0.5 619,212.9 5,979,854.2 813 813.13 -749.36 0.18 102.52 0.5 619,212.9 5,979,854.2 824 824.43 -760.66 0.17 85.26 0.5 619,213.0 5,979,854.2 836 835.73 -771.96 0.15 69.91 0.4 619,213.0 5,979,854.2 847 846.98 -783.21 0.15 55.37 0.3 619,213.0 5,979,854.2 858 858.28 -794.51 0.12 34.21 0.5 619,213.0 5,979,854.2 870 869.58 -805.81 0.10 15.55 0.4 619,213.0 5,979,854.2 881 880.88 -817.11 0.07 2.09 0.3 619,213.0 5,979,854.2 892 892.18 -828.41 0.02 330.32 0.5 619,213.0 5,979,854.2 903 903.38 -839.61 0.02 266.23 0.2 619,213.0 5,979,854.2 915 914.58 -850.81 0.05 186.32 0.5 619,213.0 "5,979,854.2 926 925.88 -862.11 0.10 137.70 0.7 619,213.0 5,979,854.2 937 937.08 -873.31 0.13 126.13 0.3 619,213.1 S,979,854.2 948 948.28 -884.51 0.15 116.31 0.3 619,213.1 5,979,854.2 960 959.58 -895.81 0.17 98.94 0.5 619,213.1 5,979,854.2 971 970.83 -907.06 0.18 78.21 0.6 619,213.1 5,979,854.2 982 982.13 -918.36 0.17 59.94 0.5 619,213.3 5,979,854.2 993 993.43 -929.66 0.13 41.64 0.6 619,213.3 5,979,854.2 1,005 1,004.63 -940.86 0.12 23.01 0.4 619,213.3 5,979,854.2 1,016 1,015.73 -951.96 0.10 2.32 0.4 619,213.3 5,979,854.2 1,027 1,026.83 -963.06 0.08 345.03 0.3 619,213.3 5,979,8~4.2 1,038 1,037.98 -974.21 0.05 341. 72 0.3 619,213.3 5,979,854.2 1,049 1,049.13 -985.36 0.02 44.27 0.4 619,213.3 5,979,854.2 1,060 1,060.28 -996.51 0.07 107.26 0.6 619,213.3 5,979,854.2 1,071 1,071.43 -1,007.66 0.15 105.68 0.7 619,213.3 5,979,854.2 1,083 1,082.58 -1,018.81 0.22 98.64 0.7 619,213.3 5,979,854.2 1,094 1,093.68 -1,029.91 0.25 90.86 0.4 619,213.4 5,979,854.2 1,105 1,104.78 -1,041.01 0.27 84.15 0.3 619,213.4 5,979,854.2 1,116 1,115.88 -1,052.11 0.28 75.15 0.4 619,213.5 5,979,854.2 1,127 1,126.92 -1,063.15 0.32 64.96 0.6 619,213.5 5,979,854.2 1,138 1,138.02 -1,074.25 0.32 58.19 0.3 619,213.5 5,979,854.2 1,149 1,149.07 -1,085.30 0.32 52.12 0.3 619,213.6 5,979,854.2 1,160 1,160.22 -1,096.45 0.30 48.97 0.2 619,213.6 5,979,854.2 1,171 1,171.37 -1,107.60 0.28 49.23 0.2 619,213.8 5,979,854.2 1,183 1,182.52 -1,118.75 0.27 51.36 0.1 619,213.7 5,979,854.6 1,194 1,193.72 -1,129.95 0.27 56.40 0.2 619,213.7 5,979,854.6 1,205 1,204.87 -1,141.10 0.27 64.14 0.3 619,213.9 5,979,854.6 1,216 1,216.02 -1,152.25 0.27 78.19 0.6 619,213.9 5,979,854.6 1,227 1,227.17 -1,163.40 0.32 92.31 0.8 619,214.0 5,979,854.6 1,238 1,238.32 -1,174.55 0.40 96.44 0.8 619,214.0 5,979,854.6 1,249 1,249.47 -1,185.70 0.47 94.76 0.6 619,214.1 5,979,854.6 1,261 1,260.62 -1,196.85 0.52 94.10 0.5 619,214.2 5,979,854.6 1,272 1,271. 77 -1,208.00 0.55 93.08 0.3 619,214.2 5,979,854.6 1,283 1,282.92 -1,219.15 0.55 89.09 0.3 619,214.4 5,979,854.6 1,294 1,294.07 -1,230.30 0.55 85.33 0.3 619,214.5 5,979,854.6 1,305 1,305.12 -1,241.35 0.53 81.42 0.4 619,214.6 5,979,854.6 1,316 1,316.22 -1,252.45 0.53 77.11 0.4 619,214.7 5,979,854.6 1,327 1,327.27 -1,263.50 0.52 74.53 0.2 619,214.9 5,979,854.6 - . - -. . - - --- --. - 1 33~ 1,33~.37 -1,274.60 0.2 619,214.9 ~,979,~~4.6 , . 1,349 1,349.47 -1,285.70 _~xhib;t VI - 9b 0.2 6191 -.~ ~.O 5,979,854.6 1,361 1,360.57 -1,296.80 0.3 619,~.1 5,979,854.6 1,372 1,371.77 -1,308.00 0.5 619,215.2 5,979,854.6 1,383 1,382.87 -1,319.10 0.58 68.81 0.0 619,215.3 5,979,854.6 1,394 1,394.07 -1,330.30 0.58 69.71 0.1 619,215.3 5,979,854.6 1,405 1,405.17 -1,341.40 0.58 71.53 0.2 619,215.5 5,979,855.0 1,416 1,416.37 -1,352.60 0.60 72.49 0.2 619,215.6 5,979,855.0 1,428 1,427.51 -1,363.74 0.62 71.80 0.2 619,215.7 5,979,855.0 1,439 1,438.66 -1,374.89 0.65 72.33 0.3 619,215.8 5,979,855.0 1,450 1,449.86 -1,386.09 0.70 74.59 0.5 619,216.0 5,979,855.0 1,461 1,461.01 -1,397.24 0.78 74.40 0.7 619,216.1 5,979,855.0 1,472 1,472.16 -1,408.39 0.82 72.64 0.4 619,216.2 5,979,855.0 1,483 1,483.31 -1,419.54 0.83 72.32 0.1 619,216.4 5,979,855.0 1,495 1,494.51 -1,430.74 0.82 71.74 0.1 619,216.6 5,979,855.4 1,506 1,505.56 -1,441.79 0.83 70.19 0.2 619,216.7 5,979,855.4 1,517 1,516.61 -1,452.84 0.83 66.24 0.5 619,216.8 5,979,855.4 1,528 1,527.76 -1,463.99 0.82 61.61 0.6 619,217.1 5,979,855.4 1,539 1,538.85 -1,475.08 0.77 57.74 0.7 619,217.2 5,979,855.4 1,550 1,549.95 -1,486.18 0.72 55.54 0.5 619,217.2 5,979,855.4 1,561 1,561.10 -1,497.33 0.68 56.03 0.4 619,217.3 5,979,855.8 1,572 1,572.25 -1,508.48 0.67 58.33 0.3 619,217.4 5,979,855.8 1,583 1,583.45 -1,519.68 0.65 62.59 0.5 619,217.5 5,979,855.8 1,595 1,594.65 -1,530.88 0.62 66.70 0.5 619,217.7 5,979,855.8 1,606 1,605.75 -1,541. 98 0.62 70.25 0.4 619,217.8 5,979,855.8 1,617 1,616.95 -1,553.18 0.62 73.93 0.4 619,217.9 5,979,855.8 1,628 1,628.15 -1,564.38 0.62 77.03 0.3 619,218.0 5,979,855.8 1,639 1,639.30 -1,575.53 0.63 80.61 0.4 619,218.2 5,979,856.1 1,650 1,650.45 -1,586.68 0.72 84.73 0.9 619,218.3 5,979,856.1 1,662 1,661.65 -1,597.88 0.80 85.57 0.7 619,218.4 5,979,856.1 1,673 1,672.85 -1,609.08 0.83 85.13 0.3 619,218.5 5,979,856.1 1,684 1,683.99 -1,620.22 0.85 86.11 0.2 619,218.8 5,979,856.2 1,695 1,695.14 -1,631.37 0.87 86.20 0.2 619,218.9 5,979,856.2 1,706 1,706.24 -1,642.47 0.90 85.27 0.3 619,219.1 5,979,856.2 1,717 1,717.34 -1,653.57 0.92 84.18 0.2 619,219.3 5,979,856.2 1,729 1,728.49 -1,664.72 0.92 83.61 0.1 619,219.4 5,979,856.2 1,740 1,739.59 -1,675.82 0.88 84.69 0.4 619,219.6 5,979,856.2 1,751 1,750.69 -1,686.92 0.85 86.73 0.4 619,219.8 5,979,856.2 1,762 1,761.88 -1,698.11 0.85 89.09 0.3 619,219.9 5,979,856.2 1,773 1,773.08 -1,709.31 0.85 91.09 0.3 619,220.1 5,979,856.2 1,784 1,784.28 -1,720.51 0.83 92.59 0.3 619,220.2 5,979,856.2 1,796 1,795.48 -1,731. 71 0.80 95.84 0.5 619,220.4 5,979,856.2 1,807 1,806.48 -1,742.71 0.80 98.54 0.3 619,220.6 5,979,856.2 1,818 1,817.53 -1,753.76 0.83 99.49 0.3 619,220.7 5,979,856.2 1,829 1,828.58 -1,764.81 0.82 102.37 0.4 619,220.9 5,979,856.2 1,840 1,839.58 -1,775.81 0.80 106.54 0.6 619,221.1 5,979,856.2 1,851 1,850.63 -1,786.86 0.82 108.94 0.4 619,221.2 5,979,855.8 1,862 1,861.62 -1,797.85 0.82 109.55 0.1 619,221.4 5,979,855.8 1,873 1,872.67 -1,808.90 0.80 111.14 0.3 619,221.5 5,979,855.8 1,884 1,883.72 -1,819.95 0.85 113.66 0.6 619,221.6 5,979,855.8 1,895 1,894.72 -1,830.95 0.93 114.68 0.7 619,221.9 5,979,855.8 1,906 1,905.67 -1,841.90 0.92 114.96 0.1 619,222.0 5,979,855.8 1,917 1,916.62 -1,852.85 0.88 115.54 0.4 619,222.1 5,979,855.5 1,928 1,927.62 -1,863.85 0.83 116.50 0.5 619,222.2 5,979,855.5 1,939 1,938.57 -1,874.80 0.83 116.08 0.1 619,222.5 5,979,855.5 1,950 1,949.51 -1,885.74 0.82 115.52 0.1 619,222.6 5,979,855.5 1,961 1,960.51 -1,896.74 0.75 115.89 0.6 619,222.7 5,979,855.5 1,972 1,971.56 -1,907.79 0.70 114.72 0.5 619,222.8 5,979,855.5 1,983 1,982.61 -1,918.84 0.68 113.23 0.2 619,223.0 5,979,855.1 1,994 1,993.61 -1,929.84 0.65 111.02 0.4 619,223.1 5,979,855.1 2,005 2,004.66 -1,940.89 0.57 108.70 0.8 619,223.2 5,979,855.1 2,016 2,015.66 -1,951.89 0.50 109.47 0.6 619,223.2 5,979,855.1 2,027 2,026.76 -1,962.99 0.45 113.18 0.5 619,223.3 5,979,855.1 2,038 2,037.76 -1,973.99 0.38 114.60 0.6 619,223.5 5,979,855.1 2,049 2,048.76 -1,984.99 0.32 113.88 0.5 619,223.5 5,979,855.1 2,060 2,059.86 -1,996.09 0.25 113.08 0.6 619,223.6 5,979,855.1 2,071 2,070.86 -2,007.09 0.13 . 113.71 1.1 619,223.6 5,979,855.1 2,082 2,081.91 -2,018.14 0.05 179.17 1.1 619,223.6 5,979,855.1 2,093 2,092.91 -2,029.14 0.12 215.66 0.8 619,223.6 5,979,855.1 2,104 2,103.86 -2,040.09 0.17 184.55 0.8 619,223.6 5,979,854.8 - .... .. """', ... nr-... ^,.... ,..... ^ ........... ,.. r- n..,n nr- A n ¿,.L.L:> £,.1 .1'+.00 -¿,U:>.L.U~ U.£ 0.1~..£¿').0 :>,~ I ~,o:>'+.o 2,126 2,125.81 -2,062.04 0.8 619,:?")~.6 5..979,854.8 . 2,137 2,136.81 -2,073.04 ",-,EXhibit VI ~ 9b 1.4 619",.6 5,979,854.8 2,148 2,147.81 -2..084.04 1.7 619,2L:3.6 5,979,854.8 2,159 2,158.81 -2,095.04 U.""tL 2.0 619..223.7 5..979,854.8 2,170 2,169.91 -2,106.14 0.62 356.29 2.2 619,223.7 5,979,855.1 2,181 2,181.01 -2,117.24 0.77 349.15 1.6 619..223.6 5..979,855.1 2,192 2,192.01 -2,128.24 0.87 345.53 1.0 619,223.6 5,979,855.5 2,203 2,203.10 -2,139.33 0.92 343.22 0.6 619..223.6 5,979,855.5 2,214 2,214.15 -2,150.38 0.93 341.50 0.3 619,223.5 5..979,855.9 2,225 2,225.20 -2,161.43 0.93 340.13 0.2 619,223.5 5,979,855.9 2,236 2,236.25 -2,172.48 0.93 339.31 0.1 619,223.3 5..979,855.9 2,247 2,247.30 -2,183.53 0.95 338.54 0.2 619,223.3 5,979,856.2 ~ 2,258 2,258.35 -2,194.58 0.97 338.06 0.2 619,223.2 5..979,856.2 2,269 2,269.40 -2,205.63 0.97 337.87 0.0 619,223.2 5..979,856.6 2,281 2,280.44 -2,216.67 0.97 337.68 0.0 619,223.1 5,979,856.6 2,292 2,291.44 -2,227.67 0.98 336.52 0.2 619,222.9 5,979,856.9 2,303 2,302.44 -2,238.67 0.97 330.51 0.9 619,222.9 5,979,856.9 2,314 2,313.44 -2,249.67 0.90 326.00 0.9 619,222.8 5..979,857.3 2,324 2,324.34 -2,260.57 0.85 327.45 0.5 619..222.7 5..979,857.3 2,335 2,335.34 -2,271.57 0.85 329.39 0.3 619..222.7 5,979,857.3 2,346 2,346.34 -2,282.57 0.83 331.86 0.4 619,222.6 5,979,857.7 . 2,357 2,357.38 -2,293.61 0.83 333.98 0.3 619,222.4 5,979,857.7 2,369 2,368.43 -2,304.66 0.87 335.13 0.4 619,222.4 5,979,858.0 2,380 2,379.43 -2,315.66 0.90 335.91 0.3 619,222.3 5,979,858.0 2,391 2,390.48 -2,326.71 0.90 336.78 0.1 619,222.3 5,979,858.0 2,402 2,401.53 -2,337.76 0.88 337.69 0.2 619,222.2 5,979,858.4 2,413 2,412.58 -2,348.81 0.87 338.95 0.2 619,222.2 5,979,858.4 2,424 2,423.58 -2,359.81 0.85 342.32 0.5 619,222.1 5,979,858.8 2,435 2,434.58 -2,370.81 0.83 346.75 0.6 619,222.1 5,979,858.8 2,446 2,445.67 -2,381. 90 0.83 349.97 0.4 619,222.0 5,979,859.1 2,457 2,456.67 -2,392.90 0.85 352.04 0.3 619,221.9 5,979,859.1 2,468 2,467.67 -2,403.90 0.93 352.66 0.7 619,221.9 5,979,859.5 2,479 2,478.67 -2,414.90 0.98 352.79 0.5 619,221.9 5,979,859.5 2,490 2,489.67 -2,425.90 1.02 353.85 0.4 619,221.9 5,979,859.9 2,501 2,500.57 -2,436.80 1.02 354.52 0.1 619,221.9 5,979,859.9 2,512 2,511.57 -2,447.80 1.02 354.06 0.1 619,221.9 5,979,860.2 2,523 2,522.56 -2,458.79 1.03 352.78 0.2 619,221.8 5,979,860.2 2,534 2,533.51 -2,469.74 1.05 351.12 0.3 619,221.8 5,979,860.6 2,545 2,544.46 -2,480.69 1.03 351.16 0.2 619,221.8 5,979,860.6 2,556 2,555.51 -2,491. 74 1.02 352.10 0.2 619,221.8 5,979,861.0 2,567 2,566.56 -2,502.79 1.00 352.29 0.2 619,221.7 5,979,861.0 2,578 2,577.60 -2,513.83 1.02 353.48 0.3 619,221.6 5,979,861.3 2,589 2,588.60 -2,524.83 1.05 355.12 0.4 619,221.6 5,979,861.3 2,600 2,599.55 -2,535.78 1.10 356.17 0.5 619,221.6 5,979,861. 7 2,611 2,610.40 -2,546.63 1.13 357.12 0.3 619,221.6 5,979,861. 7 2,621 2,621.30 -2,557.53 1.18 358.67 0.5 619,221.6 5,979,862.1 2,632 2,632.19 -2,568.42 1.25 359.83 0.7 619,221.6 5,979,862.4 2,643 2,642.99 -2,579.22 1.30 0.45 0.5 619,221.6 5,979,862.4 2,654 2,653.89 -2,590.12 1.37 1.31 0.7 619,221.6 5,979,862.8 2,665 2,664.69 -2,600.92 1.42 1.74 0.5 619,221.6 5,979,863.2 2,670 2,669.85 -2,606.08 2.20 5.20 15.2 619,221.6 5,979,863.2 2,700 2,699.79 -2,636.02 5.09 354.30 9.9 619,221.5 5,979,865.0 2,730 2,729.62 -2,665.85 6.92 356.00 6.1 619,221.2 5,979,868.3 2,760 2,759.35 -2,695.58 8.47 354.45 5.2 619,220.7 5,979,872.3 2,782 2,781.07 -2,717.30 9.84 352.16 6.4 619..220.3 5..979,875.6 2,818 2,816.62 -2,752.85 12.17 351. 60 6.4 619,219.2 5,979,882.5 2,849 2,847.08 -2,783.31 14.07 350.62 6.1 619..218.0 5..979,889.4 ""- 2,880 2,876.94 -2,813.17 14.91 348.84 3.1 619..216.5 5,979,897.1 2,911 2,906.50 -2,842.73 15.24 340.88 6.8 619..214.3 5,979,904.8 2,942 2,936.36 -2,872.59 15.51 337.60 2.9 619,211.2 5,979,912.4 2,977 2,969.52 -2,905.75 17.58 331.84 7.6 619..206.9 5,979,921.1 3,004 2,995.59 -2,931.82 17.56 331.91 0.1 619,203.0 5,979,928.4 3,035 3,025.52 -2,961. 75 19.27 329.59 5.9 619,197.9 5,979,937.1 3,068 3,056.07 -2,992.30 19.17 328.16 1.5 619,192.2 5,979,946.1 3,099 3,085.48 -3,021. 71 21.39 325.08 7.9 619,186.2 5,979,954.8 3,132 3,115.57 -3,051.80 23.48 323.68. 6.6 619,178.7 5,979,965.0 3,163 3,144.04 -3,080.27 23.35 322.13 2.0 619,171.1 5,979,974.7 3,193 3,171.78 -3,108.01 25.30 320.17 6.9 619,163.2 5,979,984.5 3,225 3,200.45 -3,136.68 28.49 319.38 10.0 619..153.5 5..979,995.3 ~ ")1::7 ~ ")")R ~O _ ~ 1 h.ð. h") ")0 .ð.") ~10 C:::1 ")0 h10 1.ð.~ ~ I:: ORn nnh 0 -',c-..., , ..,¡,IIII..&"'-'--'-' ..",...""'~-""&" "'.....,t.L·....,·..., '-',."....,"""t"''"'''''''·.." 3,288 3,254.65 -3,190.88 6.8 619,:1 ~3.1 5,980,018.4 . 3,320 3,281.61 - 3,217.84 Exhibit VI - 9b 8.4 619'c..5 5,980,031.4 - 3,351 3,307.55 -3,243.78 2.0 619,fcr'9.8 5,980,044.8 3,380 3,331.24 -3,267.47 37.14 319.09 8.4 619,098.3 5,980,057.8 3,473 3,403.49 -3,339.72 40.02 319.33 3.1 619,060.1 5,980,100.7 !i~~ 3,567 3,474.37 -3,410.60 42.05 315.74 3.3 619,017.6 5,980,145.4 3,660 3,542.38 -3,478.61 44.39 314.12 2.8 618,971.7 5,980,189.7 3,754 3,609.57 -3,545.80 44.25 313.41 0.6 618,923.6 5,980,234.4 3,848 3,677.47 -3,613.70 42.93 312.73 1.5 618,875.7 5,980,277.9 - 3,941 3,747.35 -3,683.58 40.48 313.33 2.7 618,829.5 5,980,319.6 4,034 3,818.22 -3,754.45 40.09 314.59 1.0 618,785.6 5,980,360.7 4,128 3,889.88 -3,826.11 39.72 314.63 0.4 618,742.2 5,980,402.1 4,220 3,960.48 -3,896.71 39.76 317.92 2.3 618,701.0 5,980,443.5 4,311 4,031.01 -3,967.24 39.89 318.95 0.7 618,661.3 5,980,487.2 4,403 4,101.62 -4,037.85 39.20 318.33 0.9 618,622.1 5,980,530.1 4,496 4,173.05 -4,109.28 40.41 319.65 1.6 618,582.3 5,980,574.5 4,591 4,245.32 -4,181.55 40.63 319.97 0.3 618,541. 7 5,980,621.1 4,686 4,317.36 -4,253.59 40.03 320.56 0.8 618,501.9 5,980,667.3 4,778 4,388.79 -4,325.02 39.34 . 319.83 0.9 618,463.3 5,980,712.5 4,872 4,460.47 -4,396.70 40.80 320.02 1.6 618,423.6 5,980,758.0 4,965 4,531.07 -4,467.30 40.90 319.47 0.4 618,383.5 5,980,803.8 5,059 4,601.90 -4,538.13 40.76 319.98 0.4 618,343.2 5,980,850.0 5,151 4,672.01 -4,608.24 40.28 320.43 0.6 618,304.1 5,980,895.2 5,244 4,743.44 -4,679.67 39.71 319.64 0.8 618,264.8 5,980,940.7 5,338 4,814.50 -4,750.73 40.83 319.57 1.2 618,225.2 5,980,985.8 5,431 4,884.86 -4,821.09 41.04 319.32 0.3 618,184.7 5,981,031.7 5,524 4,955.26 -4,891.49 40.61 320.17 0.8 618,144.7 5,981,077.5 5,619 5,027.81 -4,964.04 40.63 320.17 0.0 618,104.0 5,981,124.5 5,713 5,098.94 -5,035.17 40.17 319.08 0.9 618,064.2 5,981,170.0 5,807 5,171.22 -5,107.45 40.03 317.68 1.0 618,022.9 5,981,215.1 5,894 5,236.65 -5,172.88 41. 75 316.85 2.1 617,983.9 5,981,255.8 5,987 5,305.93 -5,242.16 42.34 316.09 0.8 617,940.2 5,981,300.5 6,080 5,375.07 -5,311.30 42.07 315.44 0.6 617,895.7 5,981,344.8 6,173 5,443.80 -5,380.03 42.01 316.61 0.9 617,852.0 5,981,388.4 6,266 5,513.13 -5,449.36 42.03 316.61 0.0 617,808.3 5,981,433.1 6,358 5,581.19 -5,517.42 41.99 315.92 0.5 617,765.3 5,981,476.8 6,452 5,651.14 -5,587.37 41.95 315.89 0.1 617,720.7 5,981,521.5 6,546 5,721.23 -5,657.46 42.02 316.90 0.7 617,676.0 5,981,566.5 6,641 5,791.49 -5,727.72 41. 74 317.28 0.4 617,632.9 5,981,612.0 6,733 5,860.57 -5,796.80 41.32 320.35 2.3 617,591.9 5,981,657.1 6,828 5,931.92 -5,868.15 41.08 320.33 0.3 617,551.2 5,981,704.7 6,922 6,003.38 -5,939.61 41.06 320.27 0.1 617,510.7 5,981,752.1 7,016 6,073.75 -6,009.98 40.93 320.48 0.2 617,471.0 5,981,798.3 7,108 6,143.69 -6,079.92 40.82 320.02 0.4 617,431.6 5,981,844.2 7,201 6,213.82 -6,150.05 40.73 319.26 0.5 617,391. 7 5,981,889.7 7,295 6,285.12 -6,221.35 40.70 320.13 0.6 617,351.2 5,981,935.9 . 7,389 6,356.10 -6,292.33 40.71 320.01 0.1 617,311.3 5,981,982.1 7,481 6,426.48 -6,362.71 40.09 320.11 0.7 617,272.1 5,982,027.3 7,574 6,498.47 -6,434.70 38.40 320.56 1.8 617,233.8 5,982,072.1 7,666 6,571.48 -6,507.71 37.28 321.10 1.3 617,197.3 5,982,115.4 7,762 6,648.47 -6,584.70 35.19 321.53 2.2 617,161.4 5,982,158.8 7,855 6,725.02 -6,661.25 34.42 321.22 0.9 617,127.5 5,982,200.0 7,948 6,802.00 -6,738.23 34.20 322.05 0.6 617,094.3 5,982,240.8 8,041 6,878.96 -6,815.19 33.83 321.88 0.4 617,061.6 5,982,280.9 8,135 6,957.75 -6,893.98 32.98 321.97 0.9 617,029.0 5,982,321.4 8,226 7,033.72 -6,969.95 33.03 323.25 0.8 616,998.3 5,982,360.1 8,319 7,111.71 -7,047.94 32.43 323.24 0.7 616,967.7 5,982,399.9 8,418 7,195.86 -7,132.09 31.98 324.47 0.8 616,935.7 5,982,442.2 8,507 7,271.25 -7,207.48 31.42 324.72 0.7 616,908.2 5,982,479.5 8,599 7,350.23 -7,286.46 30.81 324.58 0.7 616,880.0 5,982,518.2 8,693 7,430.82 -7,367.05 30.21 325.00 0.7 616,851.9 5,982,556.6 8,787 7,512.05 -7,448.28 30.03 325.77 0.5 616,824.6 5,982,595.0 8,881 7,594.03 -7,530.26 30.03 323.72 1.1 616,796.7 5,982,633.0 8,973 7,673.10 -7,609.33 30.24 325.01 0.7 616,769.3 5,982,669.9 9,066 7,753.45 -7,689.68 30.87 324.43 0.7 616,741.4 5,982,708.3 9,161 7,834.47 -7,770.70 31.23 325.26 0.6 616,712.5 5,982,747.7 9,254 7,914.79 -7,851.02 30.57 325.53 0.7 616,684.7 5,982,786.8 9,347 7,995.03 -7,931.26 29.68 325.65 1.0 616,657.8 5,982,824.8 9,441 8,076.86 -8,013.09 28.69 328.13 1.7 616,632.2 5,982,862.5 a £:;':lA Q 1 ~7 01 -ROQ4_14 29.94 325.45 2.0 616.606.6 5.982.900.2 9,62v 8,239.15 -8,175.38 0.7 616,579.6 5,982,937.8 . 9,721 8,320.84 -8,257.07 :=xhibit VI - 9b 0.9 616 ~.4 5,982,975.8 9,814 8,401.51 -8,337.74 -...-' 0.1 616,'::n6.3 5,983,013.8 9,909 8,483.04 -8,419.27 ..:5U.UU j Lb.44 0.5 616,498.4 5,983,052.2 10,002 8,564.24 -8,500.47 28.75 327.49 1.5 616,472.8 5,983,090.3 10,094 8,645.27 -8,581.50 27.63 328.29 1.3 616,449.1 5,983,126.9 10,106 8,656.17 -8,592.40 27.39 327.55 3.4 616,446.1 5,983,131.6 10,169 8,712.17 -8,648.40 27.55 327.55 0.3 616,430.0 5,983,155.9 10,198 8,737.84 -8,674.07 30.91 324.64 12.4 616,421.9 5,983,167.4 10,229 8,762.94 -8,699.17 38.06 321.63 24.1 616,411.2 5,983,181.2 10,260 8,786.09 -8,722.32 45.38 318.57 24.5 616,397.6 5,983,196.7 10,289 8,805.56 -8,741.79 51.77 315.46 23.1 616,382.4 5,983,212.6 10,321 8,823.48 -8,759.71 59.21 312.46 24.8 616,363.4 5,983,230.6 10,352 8,837.77 -8,774.00 66.50 308.34 26.0 616,341.8 5,983,248.2 10,383 8,848.74 -8,784.97 72.16 305.65 19.9 616,318.3 5,983,265.0 10,412 8,857.83 -8,794.06 70.65 298.86 23.2 616,295.3 5,983,279.3 10,447 8,869.65 -8,805.88 69.96 289.20 26.1 616,265.0 5,983,292.0 10,477 8,878.63 -8,814.86 75.09 283.79 24.3 616,237.6 5,983,299.7 10,513 8,885.28 -8,821.51 83.47 283.22 23.5 616,203.3 5,983,307.5 10,540 8,888.22 -8,824.45 84.16 283.28 2.6 616,176.8 5,983,313.4 10,570 8,891.17 -8,827.40 84.68 287.36 13.5 616,147.5 5,983,320.6 10,603 8,893.83 -8,830.06 86.02 289.28 7.1 616,116.3 5,983,330.7 10,634 8,895.60 -8,831.83 87.43 290.42 5.8 616,087.0 5,983,340.5 10,663 8,896.94 -8,833.17 87.29 290.45 0.5 616,059.7 5,983,350.3 10,697 8,898.57 -8,834.80 87.19 289.84 1.8 616,027.8 5,983,361.6 10,728 8,900.08 -8,836.31 87.22 289.98 0.5 615,998.5 5,983,371.4 10,757 8,901.49 -8,837.72 87.26 289.68 1.0 615,970.9 5,983,380.8 10,789 8,902.94 -8,839.17 87.43 290.98 4.2 615,941.3 5,983,391.3 10,819 8,904.62 -8,840.85 86.33 292.04 5.0 615,912.6 5,983,402.2 10,848 8,906.51 -8,842.74 86.23 292.72 2.4 615,885.6 5,983,412.8 10,882 8,908.68 -8,844.91 86.29 292.55 0.5 615,854.8 5,983,425.1 10,914 8,910.81 -8,847.04 86.13 291.98 1.8 615,824.8 5,983,436.8 10,943 8,912.81 -8,849.04 86.02 292.46 1.7 615,797.5 5,983,447.3 10,979 8,915.35 -8,851.58 85.81 291.22 3.5 615,764.5 5,983,460.0 11,010 8,917.64 -8,853.87 85.89 291.38 0.6 615,734.7 5,983,471.2 11,036 8,919.47 -8,855.70 85.92 291. 38 0.1 615,710.9 5,983,480.0 11,073 8,922.41 -8,858.64 85.02 291.42 2.4 615,676.1 5,983,493.0 11,105 8,925.52 -8,861.75 83.58 288.58 10.1 615,646.6 5,983,503.2 11,132 8,928.64 -8,864.87 83.40 288.35 1.1 615,620.6 5,983,511.6 11,164 8,932.27 -8,868.50 83.30 289.57 3.9 615,590.9 5,983,521.0 11,198 8,936.35 -8,872.58 83.06 289.59 0.7 615,558.6 5,983,532.2 11,223 8,939.54 -8,875.77 82.51 288.61 4.4 615,534.7 5,983,539.9 11,260 8,944.59 -8,880.82 81.88 287.55 3.3 615,499.5 5,983,550.7 11,292 8,949.11 -8,885.34 81.67 287.86 1.2 615,469.6 5,983,559.8 11,318 8,952.93 -8,889.16 81.61 288.77 3.4 615,444.7 5,983,567.4 11,352 8,957.98 -8,894.21 81.30 289.40 2.1 615,412.8 5,983,577.9 11,383 8,962.57 -8,898.80 81.26 289.20 0.7 615,384.4 5,983,587.4 11,412 8,967.17 -8,903.40 80.92 289.18 1.2 615,356.6 5,983,596.8 11,445 8,972.51 -8,908.74 80.46 288.18 3.3 615,325.5 5,983,606.6 11,477 8,977.83 -8,914.06 80.40 288.20 0.2 615,295.4 5,983,616.0 11,506 8,982.58 -8,918.81 80.33 289.18 3.4 615,268.8 5,983,624.7 11,537 8,987.87 -8,924.10 80.15 289.06 0.7 615,239.6 5,983,634.2 11,568 8,992.98 -8,929.21 80.94 286.96 7.1 615,210.2 5,983,643.2 11,598 8,997.22 -8,933.45 82.75 288.49 7.9 615,181.9 5,983,652.0 11,630 9,001.02 -8,937.25 83.54 288.02 2.9 615,151.7 5,983,661.4 11,664 9,004.36 -8,940.59 85.33 288.60 5.5 615,119.0 5,983,671.5 11,691 9,006.41 -8,942.64 85.95 287.72 4.0 615,093.4 5,983,679.5 11,723 9,007.71 -8,943.94 89.31 288.93 11.3 615,063.3 5,983,688.9 11,758 9,007.85 -8,944.08 90.24 290.25 4.6 615,030.0 5,983,700.1 11,784 9,007.62 -8,943.85 90.75 288.26 7.7 615,004.8 5,983,708.5 11,820 9,005.98 -8,942.21 94.60 288.93 11.1 614,971.2 5,983,719.0 11,851 9,003.23 -8,939.46 95.49 289.45 3.3 614,941.7 5,983,728.8 11,878 9,000.66 -8,936.89 95.35 289.97 2.0 614,916.1 5,983,737.6 11,912 8,997.61 -8,933.84 94.87 289.29 2.4 614,883.8 5,983,748.4 11,944 8,994.96 -8,931.19 94.80 289.72 1.4 614,854.1 5,983,758.6 11,972 8,992.51 -8,928.74 95.01 289.80 0.8 614,827.1 5,983,767.7 12,006 8,989.56 -8,925.79 95.11 290.81 3.0 614,795.6 5,983,778.9 12,038 8,986.61 -8,922.84 95.49 290.46 1.6 614,765.7 5,983,789.4 12,065 8,984.05 -8,920.28 95.39 291.01 2.1 614,740.4 5,983,798.6 12,097 8,980.99 -8,917.22 95.39 291.23 0.7 614,710.0 5,983,809.8 12,12S 8,978.00 -8,914.23 614,680.9 5,983,820.7 .12,158 8,974.99 -8,911.22 Exhibit VI - 9b 614 ~·-?.9 5,983,830.5 12,190 8,971.57 -8,907.80 --..,./ 614;-3.1 5,983,840.7 12,224 8,967.73 -8,903.96 :;10.....' 614,590.8 5,983,851.5 12,252 8,964.59 -8,900.82 96.49 290.40 2.2 614,564.6 5,983,860.7 -- 12,284 8,960.93 -8,897.16 96.56 289.28 3.5 614,534.4 5,983,871.2 12,315 8,957.40 -8,893.63 96.66 289.76 1.6 614,505.4 5,983,880.6 12,345 8,954.06 -8,890.29 96.32 288.38 4.8 614,477.6 5,983,890.1 12,377 8,950.45 -8,886.68 96.60 288.93 1.9 614,447.3 5,983,899.5 12,411 8,946.41 -8,882.64 96.77 289.66 2.1 614,414.5 5,983,910.3 12,440 8,943.05 -8,879.28 96.63 288.79 3.0 614,387.4 5,983,919.4 12,474 8,939.61 -8,875.84 95.15 286.06 9.2 614,355.4 5,983,928.8 12,505 8,936.74 -8,872.97 95.29 286.14 0.5 614,325.1 5,983,937.2 12,531 8,934.28 -8,870.51 95.53 286.38 1.3 614,300.0 5,983,944.1 12,625 8,925.34 -8,861.57 95.46 287.67 1.4 614,210.7 5,983,969.8 12,644 8,923.51 -8,859.74 95.53 288.54 4.6 614,192.5 5,983,975.4 12,700 8,918.10 -8,854.33 95.53 288.54 0.0 614,139.2 5,983,992.5 '.- ~ Exh ¡bit VI - 9c - . ; ,ì 1: : . 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TIME DATE ':. : I D§fT!1 I TVO I FTG 1/ S ~:oo 4· ?S-qO ~~"Xoo "3'-SO 1000 I:~ 1-Z:Z..-4q Ig~~ "11~ 15~ ~=~G '"Z' 12-·~ I ~s/ß 1n.4t "" ~ f1 FIT IS,~ ppg PIT ;' . DAILY ." CUM. bbl VOL. (,.,~.~,:: bbl MUD. $ I_';~ (" ~ U MUD ~ 11 Ì .2 Y. I pH tf!., I HTP I 0 10 ml.~ ...... 9 ... ~; 1 J if cc FL -. 100.1 - 500. . I Ca '. j WD SOUDS .- .t.; 'Í C'1 ÞØm . _~Cì'l ppm T t:.. ~ ~ ~ L ~ .. MUD [I TEMP 7 g OF . ,~1 GPM AVDP AVDC I TRBLE -r COST I WATEF 7,... / J ÞÞI USED I ~ V t>~ I' AVA:. 8 BEC, ï='fJ-;= I = !"'3 ~ oC\ /"") .. FLUID ~ INJ ?:,! I OTHER 'Ii, I 3860 I AI' IH'I POLLUTION (YIN EJ.W DLS EJ.W DLS EJ.W DLS EJ.w DLS I / SHALE DELTA DeN TRIP CL Ii 12 II 9 ., e 11, 3 $ï4 ~ ../ "Z.. be-. J $1"'4 ß f1 LENGTH 00 ITEM ID S ì<? S.c::: SHA NO. 52.5 ~ IO~ PIU '\:'1000 WT HOI..RS CONO I 0..,) I C. Z. x1000 ~NR + ~ x1000 SLACK x1000 O!<F 'NT SERIAL NO x1000 WELL NAME - NO. 1'80 .( _ 2.'" ~:S~N 'Df'Z., (..1..1 N G- FORMATION 1ft C\ I .... L!-.. I SUPV. ~ ...t.~\l : 10 "" St¡N~: 10 ~ ...... ~ "" INIT. ïr MUD , to . ..1 CHECK ~ HOLE TYPE . ~..stH'~ DEPTH .~Sol, Fi:lVOL MW '1, lot øøol FV ~~ ~ Me I PV r I YP I 0 Fe Fe Pm PI loll API 2.. m/ 1m' ... f.!2/ - I I I I S- OIL J WATER ")l.t "" I MBT , "7 '¡ z... PUMPS ., MAKElMODEL HP '2 MAKElMODEL .1rl '" I SERV~~J ,CO i I TRBLE COO~ I TEt.''' t:2 I In + -, OF 1 I CONTRAC'TOR ""3 ~ I CATERING I i TRBLE I TRBLE CODE COST WIND I BAROMETER ".. $ 1'3 ~nts ~9 .3S TOTAL PERSONNE, '54 I SAPC I -- I~~~~:i. ~ ó SEc.... (.; TRBLE COST .. PR TRBL M:r oeoo TO 'HRS oìoo I o ,3D '/1. o CXOD 'It. D "2.. s ~N. ~ A c.-t... HR. SINCE INSPEC. DRILl. STRING , aHA AIAWT. SUAVEY , SURVEY , SURVEY , SURVEY , TRIP BAS OPEMnNG SUMMARY - L . I .o"J I; ~j ::) MD 1.40 1.40 10 MD '\!. IT" 1 ^'ß :rJ1as. ~ IIHAI :ü . . I PORE ~ Ii DX PRESS ~ ()PEIZATI61\/4L.~ t( BKGO GAS 5QU,PM'€).)T ITEM BHA CHANGE (YIN) ru.s I NI.s NI·S 00 10 LENGTH ITEM OD ~TÅ&... M.. X.O .11 2,EL H, " ,.., w ðP . II 5 II e II 11 ANGLE A2. TVD SECT ANGLE A2. TVO SECT ANGLE A2. TVO SECT ANGLE A2. TVO SECT 1)]" 1211 1 ru·S ¡ ;1 S"T~'ß I ID ¡] LENGTH ... < g 8 Z~ S Tc::. ¡; I'''S c..o r lOX> ~ 15'/, 1/Q 2St/f'l/Ü3 10RQ OFF TORQ ON BTM BTM BIT' SIZE MAKE - l ,; i ~ Arctic 'mlllll!.:{~'I'UI. ~.;:.: I PUMP . ~ I RPM ! PRESS IODO ' x1000 I :fZ' DEPTH OUT 'FC(JTAGE JETS TYPE TFA I~B SPM.... 1 , ," ·I'TORQ MAX 2C¡O F , ()()r..) f /'t',s Go '3MAKElMCX!§L HP '-I9ç I GELS ì 10 aecl ICI Î Exhibit VI - 9c '.-.-' - ""- -- ..-..._-;... ........."..... . '" Exhibit VI ~ 9c '-"..' ,'. . . ' ". " " . ,; ~ ' A.~rctfIilllc "; :,'. .'-. ~ .-' .. . J IHIIIlI[" =t~IIIIf' . i I ! ~ a /2. RIG /V);btJ....~. "JaG' AIG PHONE 4~ oc¡ WELL NAME - NO. ;::a.it. :5 _ ':J,"'¡ I ~PTd ·k :00 DATE.s: ~ ¿"J. q tJ DE2J A 47 I ND I F1G N!/1- ~:~~N ks'¡" . ð'tf /!¡;:..::fíJs~A1L¿ tI/ð'R 12 R, iv.t:¡:t~; I~;; /3s; qs.~ ~~~ //;)9'1 S~9 FORMATION I ~ I ~: ~ I ~N~~' IE D¡q I ~:~G III n- t-.·.~. SG q ~¿ In.«r 9 ¿ 1:3. 4/'b..- FIT.. PPO MUD I CHECK .flU HOLE 1/0 I PIT ' . . I DAILY . ~ I CUM. ,¡ ~ :=:> _ ..,- TYPE DEPTH Fll VOL tltIl VOL r-. tlbI MUD $ ''7' If (j MUD S r ~.;>ã;> 'ó , .,.. ~ MW CIØOI FV lec I PV I VP I GELS 10 NC I 10 mln ~. !' I " œ I ~ ,00.1 ... ~ OIl:' J...;;t r. ~f~l~ 1M¡ I ~qfJ -4a (f^,dIO ~j,<;'" tJ' .. ;:'. : PUMPS " MAK£/MODEL HP '2 "'AK£/MODEL HP .3MAK£/MOOª, HP . GPM AVDP AVDC ¿ I??J (:.0 ~ j t)Cb ~ ,sl¡z X¡Þ2~ ~'n1(I(::tJ TORQ OFF I roAQ ON !IN BTM lIlT. BIZE MAKE TYPE e YrlSeo ~ 10.0"0 SPM I I PUMP i " I APM .;. PAESS o. I Ac:t: %1000 wn DEPTH OUT FO:JTAGE 11000 BHA NO. -"A UP PIU _. .. ·%1000 wr HOI!(IS COND JAR , x1000 DN SLACK "'000 OFF WT SEAIAL NO 11000 1:;0 I~B JETS TFA 1/ /2~'¡ ~tf(. -rx 31'1 t. /6 10 /0 ::<797 CJ8t./7 .~)l 14. .3' é ,¡::. /Y17~-flJ/ , TRIP I ~~N. BKGD I POAE ---;r:,x ::AAT1NG /7 / ~ '""" GAS PAESS I, 11 : ,,""- " 7" L-L. é.¡oJ' Ì' o/.:,z '" I. ò "'..;> I. '( C¡Ø?"~~9 ~N ..87/'MC? /.S36 H~ . .5-:'jr~ 9D ; . 9$/~// Ce~eN..r /AI //~/,p(~) /&30 #~ .-5: s--9o oeoo TO 'HAS PA TABL Þcr ÞcrIVlTY LOG . 1· I: 'ACCIDENTS (VI"'} I !\II POLLUTION (YIN, IN /.5309~.3 0 P. 4 v.Ø' q.. /"tNN,}"1 9S~q 0~7 . 47-- J. ,ft!- jl/scr ," h'¡( ~~~ I~ :F'/-.$ . : ¡ /630 I ð 0 ð3 CJIJ-C- ('~7 gftð Ø~117 J ;i'¡ ,. 'j' I /8c~o ;;. b ð 13 C!JJI. 9~J/ Ç;9' .,.4-7~Ea ~U~~)I~ a.I.t<?Q /86ð ¡/æ. .ð'l~ ér/ '::4¡ u.../ 3OL~O {f~, .£. Ó~I.' 4k~d ð~Ø~ J W,/!/;. t'. IcoN F¿ Of'"> P, I'; _ . '. ~~<'G I Sð bb/.!!Þ rnu d 7'7:?.. 9 §ií'~ x/3..f1 ~N^;l~ ¿ , <. ::rN.s'¡'~¿¿; ~ckc-/'.// L(J~ú Ic.J~~."l" f. c$'¿-.;J 1- ¡q/j I.. ~ ß¿,..¿ss C!3J /"'1' ø-rI1J ~ ~.N Ry;,'; II~ t -h.rr ß4r?E: ~5"¡'f' d ß()¡C?PJ :;. / .J' ¡:l~7-1 ~~ J.;,).<t;-/~/( ~r~d (1.h""ð/'/ (40 ~n) Mel'lë r/dtJ,J . Iodo,.17bp &C't L- -rAl.~ÙL-¿' ~CH ð ¡r./ -k..s -I I"n ~ ¿:J().I"' ~ ~z ~ ¿J6()() / 5 () 1< j::J/t':~ tI¡~ -f.d f.f (4~Jt i,;7P:; 1!if6tj.., ~1J!c,e .4,,, d k ~ ~ J ~<,..JA t. L 1I / jf~"'" .Br~ h /^1' . BHA CHANGE (Y/N) IItW HA. SINCE INSPEC. Df\ILL ~ING' BHA AIR ¥fT. 10 :UfMY~'/ MD Cé SURVEY MO 7 , SURVEY MD , SURVEY MO /9~o I 0 C> /.3 ;¿ 6 60 J 6 0 ¿h ~~ ()o I~. ~ () Z/.o rJ/{)(J .:~ ~ () 1'5 I !1 <'IJ() Lj 5 () J~ ABLE 1 TRBLE ~E co~ ~ND.5 ,if knlS1BA!r9:F¡o ::1TAL PEASONNh;:5:/ I &APC. .3 /::.( ~ L?;: I /'Î ITEM OD ID ITEM OD OD ID LENGTH ID LENGTH LENGTH ITEM " 2 ft 3 ! ! ft :'8 ft 5 " 8 ,,'1 9 CG~/E ~ ANGLE AZ ANGLE AZ ANGLE AZ " II " ,~ N9~¢3,l/2.m;r he:; @97l5" EJ.v;LMÀ.J't!~~ /}A.9 =3 NO SECT w-s· EJ.W DLS iVO SECT ~ ~~ W-S EJ·W DLS NO SECT W-S EJ·W DLS I SHALE ; DEN DELTA TRIP CL I TABLE COD~ ",TEMF /1 OFI I CONTAACTDR ~ I CATERING I TRBLE CODE I TRBLE r.O~ I WATEI1 ......, ¿ \ bbl USED ð "-/ Þ¿: '" ~'I AVAI~ 11 BEt': I ? .:'., TRBLE CO~ p'. ~ ;. SERVICE~CO . II ¡;;~ I FLUID INJ ¿ I ~HER ¡ I ,- ¿ I - - -- - - - -- - - -. I ~RBLE COST J, þþl ~;~~¡; ~/d¿) Þl>' , 1 AVAI~ / BED! <0 1/ POLLUTION ('fIN' DELTA "mIP CL DLS DLS DLS OLS hi I-/w//¡O LENGTH ID. çg /¥,ð9 JAR xl000 DN xl 000 SLACK / 7. - xl000 OFF WT .::> YI000 SERIAL NO BHA NO. "F ~ 500' L~! r' ~BLE I TRBLE I TABLE ~E COST COO~ lNO , ~ I BAR0J:4QER I TEMP I r- . <::; I /0 kIllS ci(cr,.,.g 1ft 1'7 "~'~f9 Y JTA~ER$ONNE'::s" t SAPC _ 5 'CONTRACTO¥ ( I CATERINþ FLUID INJ ~CfTMER I SERVICE.;t; f200 2 () ð al- 12.':¡/J Ý-r.- t1 ð /..4 /,? /)1') ~7 ð ð ~2.. /3:3'0 ~ C> ð ()S c?J?-t1'l /~ ð /) ðl. {f 6t?('I Í" 0 ó ó5 1010 MD MD 10 1010 ß· f:' 1C,r11 bo BHAI :1 fJ,.., IL . ' ! - '''¡' rz- ...,.",oJ 1· (ì~~lol~ .5~)S.L chI< "P /' Kt2, ¡(.6'7~Ø':<56 P5Z"~ ..c.z¡ ;..-.R ¿fSc<'~' 7'5ðPrJ. HI\. SINCE INSP~ Df\JLL STRIN,9 , BHA AIRWT, SURVEY , SURVEY , SURVEY , . SURVEY , TRIP I CONN. BKGD I PORE ~ OX OAS GAS GAS PRESS ~ I ~~::::' ;41..1. q"r· 'YGjÛI-¡'·Oµ~ L- . I ~íë I D,ftpïl1ltJ, '-IZ$ C(\WIf'úk~ C.') t7:dL~ó J-/!?~ 5- 7-9D DflCt 8J/-z.." /-Io/ë (i2 <:J<fL/-¡J <ø '3.30 H~'6.s: ~~~ 0 oeoo TO 'HRS PR TRBL b ACTIVITY LOG I ~CIOENTS (Y.N) 07()() / 00 /6 P/fI 8/119· cJff30 1!1 0 () 06 ,ê/.r:/I. '/SoSo !~~j (j9txJ ~ 0 t7 (15 h// ~E "/. /ðð/J I /J tJ./A ¿~J./" 7M~ Çhë; I d/hr-<f 97~~ ~ ßJ'¡f. CirCa. /..e~ f C'aYf- *. .3CMt\ ¡:?5':Z-. 'f*" -1 / "or//I ~~I ~v¡¡o Q.I ~"Ýr)~ ~ <;!/7¿, ~f o~ ""'<0 <.3'('00 /Pf..z.~ 9770 /Jr/// (lm-l ~/tp77t, J -r/9~:ý3 :. CI;"C.. ~ Cd"-' d. ff/ v" Cà> !~c;"'5 h 0 c5' _ L?r"//'AJ!J ~/9~o/7 ¡-/ lð~f(z~ ,~O" CiTe: 0- ~f'lÑ t'f.. hr (L ~ J.,+ ~r";t' ~I, I I TRBLE, CODE . , TABLE COST 00 I 8MA CHANGE (YIN) Lil lH . . I IÝI I SHALE DEN I i '.' ·.1; NI-5 EJ·W NI-5 EJ.W ! NI-5 EJ.W NI-5 EJ·W II 5 II 8 II 11 ANGL.E A2. ND SEer ANGI.£ A2. ND SEer ANGLE A2. TVD SEer ANGLE A2. TVD SEer ITEM I PUMP ç-:;..... I RPM I~ JAR PRESS o~D It\'; UP 1 WOB Jr I RC1I' 2 -. PiU-.7 l~ r'lOOO wric ( ~··:rtooo WT I., :> ð 0 TFA DEPTH OUT .Fô?TAGE HOL·RS COND JETS 8¥z. gEd )/f7¿I.:fY /tf U2r> BIT' .--.. Exhibit VI- 9c /;? TYPE BIZE t. ·9 ,. .8 r;r. ,)/~bll ~ 3[b ~h 'J( 1'/; -719/1$ 1:,3 :</:¡ OD LENGTH 10 MAKE ¿;; yYJ~ t:. 0 ;:::-'/ () t:. u E ¡4'1.$ Cd ~ I (!)b C> ~ER ~~/o.ð~XI() 3 ~M/ZO ::OFF SSO I:OON 67~ 1::°75""0 PUMPS OIL 7;-. JI:llmllllle..{~ IIIHt " ';., A~ ...... . .-...-....-... ITEM -10 '.. I.£NGTH 00 ITEM I ~ , 9},f¡"/ /t1¥l8~" I / .~, , (DIi /3 RIG tltJßQÆ·~ J/?~ RIGPHONEJ/6ð9 WELL NAME - NO. .:¡.,; /.2 Ii _ <" ,." I , RPT,) I /1 !1'1E DATE ~ ~.' 90 ~~PTH I' ..J TVD I FTG ~8 I ''-J." ~-~ï 1/ ..., <lla..:oo -"-,,- ¡' ·/CJ...,ZKl ~, I PRESErn'~ -. (i _I ~ I,· ~ ; ~:, DAlLV"¿:;-1 0 22 IleuM,! ~ . ~=N -j("~. 4- :(!'J~ Ç1.. "t11? ~.. ':i¥sUP.'.'~/~~~RS.· ;~~.ASf CO~ ¡II ì -;;/ .Ob COST 1- FlT8,57./ , ~, - ~ , ~IINIT, I;J.)¡-:' IORLG 110 J-cSG 1'% In.c9BL/3 'I. øpg MUDG¿=L I CHECK l? .121HOLE / 71 PIT ,,~ DAlLY U7 I CUM. - 'ð TYP. E 'I;,!....tJo!f DEPTH 16 :::> () ~VOL fO þbl VOL. ~(li) i,'.".. ÞÞI MUD $ ,7 ~ 7 MUD $ ;;J 0 Ó 70: IoIW C FV 3 / I P.' l:!' I YP....I GELS.] pH FL / I HTP Z, / t'J , q DØQ tee c..7 ? 10 see I 7.? 10 "':1\1·. / () ¡ /" I:> cç Fl t::> 10Q1 Fe 1 I Fe I Pm 'PI 3£ 'M. -:.- , CI ' ", 'c. '&AND -?' $OUDS L I API '- f3~ HTP 132 ' , .s~ c3 () û ¡~m 0 øøm /'J2... ~ ' 7'" JWATER'?6 ~IMEfT I{ I I::" l :~p . ., IoIAKElMOOEL HP '2 MAKElMOOn HP ,3MAKElMoOEt ;tp GPM ~VDP AVDC ". g:;6',!/~ 2&~ LA ,~ '-- TRBLE TRBLE I TRBLE TABLE rAB!. F" I TABLE CODE COST COD~ COST .. CODe COST WIND I BAROMETEF. I TE"'~ .~ . ~ FLUID I WATE"'4crc:> c,- I kntS In INJ tltIl USED co!" 10TAL PERSONNE. !:;" 5 I SAPC "2... CONTAACTOF. ..q I CATERING " SEFlVIC:f.co (; :OTHEI'I I AVA,. ; rlì e£c~ "?_,...,-r-::. _ I A 1'\)1\,..... I i r I r=, );:: , ! ~ """"..c.'- , #;.1 ¡,I ¡ 1 p~ I f~ ..!~ ail 2.$ D(¿"..l... .- OtJT c.}.(T 1=/. 18 íC-sT lAP ïO 3000 Z~ Del Lt.. ouT c.Lfr 'Fl , 1'61-1 ~ -e, f.l ¢ TÂ~ C.~T ~ 10 'U:~ ' "lS VtlL' c.1-{T f=! IO'2.'~.... \O~O,' I Dí2.LG L-c::. ~ 10 sO, tt C ^'iT ïO '0.1& ,g -reçr ., " LI />lEI?- I LIJ.f t q !;/s. ~s:~.. To 3oCIO 7!T.- S' C.~ANr:Æ ouEIL 10 e.~ #. ~~1CIZ" ; 18 TE$r 7 It t.''''lE./2.. I i.Af f <?S/~ ~~ -rc., \ 3000 Pa s ~e(J&l,~ <:'112<:'. , *P614 ,I-) -4 '3/4 DC.. II Ru ~('I-4LU.l{ßEIZ~&Z.. 'i<.vN I.!: cõfy cET, Gr2../ eCL " Q'2.6 "Pa..- G'-32. -. Gq,q, POLLUTION (YIN I ,.,L.,"''''S(¡'''' ~. q" ~ '2. .'~- ,i Y'%. 10 0 1/1... 10 0 112. '0 0 2.. 10 0 2. 100 b¥z.. 10 Q '/2. 10 0 "2.. 10 0 '/2.. 10 GJ 'Z.~ 16 0 ~ /(;) 0 z.x 10 0 o,~o 01110 o~30 1030 123,0 ,qðO Ict30 "2.130 '2. z.öc:. °9~ ci '350 /0 f.:.ðo ACTIVITY LOG PR TRBL N::r ·HRS oeoo TO DELTA TRIP CL I~ I!DX pþg' DPéElUJi/ON4L- PORE PRESS 8HA CHm~E (Y/N) ITEM OD ID 8HAI HR. SINCE INSPEC DRJu' STRING . aHA AIRWT. 10 SURVEY MO ANGLE I\l. · SURVEY MD ANGLE I\l. · SURVEY 1040 ANGLE A2. · SURVEY 1040 ANGLE A2. · TRIP I:;N. Bl<GD GAS GAS OPEMflNG ~ ÁLL lS~U I pA.i1E1JT SUMMARY DLS -~-- SEer E/·W DLS OD ID LENGTH 1'1 \ 3 " 3 ; II ,e 101 '~1 It .9 Ie ~ i 11 1:2 SeCT (-J NloS SECT i.: NloS SECT '-------w:š-- E/·W DLS E/-W DLS E/·W LENGTH ITEM ID OD ''''i ~3QÔZ- ~~1 ~¡ 'J;- .1000 BHA NO. PUMP :, . I RPM PRESS I Ci () IAOT x1000 vJr~i DEPTH OUT I iFÇOTAGE .1000 JAR .1000 DN SLACK .1000 OFF WT SERIAl. NO JAR UP PIU :11000 wr HOURS COHD fc 72 Il.cï 4103 .~ MUD TEMP AVDC HP '3MAKE/MOOEL AVDP GPM LENGTH ITEM ft 2 " 5 " II II 11 TVO TVO TVD TVO 6 ,0 E N ~-1 1-I'T't:.. <; 13 TF" JETS ¡; MS c..o F 1000 :iR 15~". 10 :26Y:z. ~/O 3 1ORO OFF I TORQ ON 8TM 8TM sry, 81Z£ MAKE TYPE WOB ¡: fot S (..() ~M78 1ORQ M.&.X 278 r 1000 HP .:2 MAKEIMOOEL I~ %IMBT HI' Fe API OIL 'DAi /J '" RIG N~ßþ~ \g~ I RIG PHONE 4bö'1 I RPT. ì TIME DATE II!' ... ... a D~F'TH \" ßTD I ND I FTG /I I ~:OO ;;>./é):....,O \03a~ I I~~I~ ~~18~ I~~~ 151ì 723 :LAST ì". \042,.0 I FIT l CSG . In. at 0 It . . I DAILY , ,\ CUM ISO-, bill MUD S '0 I ~ 06 MUD ~ 5 c.¡ 4 7 2- _I þH I FL I HTP 10 mir; ¡ 0 CC I'L 100.1 : C'1 I SAND SCUDS ør;-m I:~ øøm % WELL NAME - NO t'8lJ ~:S~H U:>GGIN~ . FORM~ I : ~I MUD ~ I CHECK TYPE ~I:A Wit ìl.ll DEPTH 10 '3 B ~ MW I FV I Pv AI (p DØQ lee FC pm 132 HTP 132 JWATEFI " MAKE/MODEL .,., 5000 øØ9. 8.mIIIII..:f::!III].. A~rctlTillic at '( 5-"2Jf 10 lee I ICI HRS. DRLG. I PIT bill VOL PUMPS IM' 81~ GELS % ~ HOLE FLl VOL I YP SUPv.. ar % INIT m $- 24 Exhibit VI - 9",- - Facility PB S Pad Dateffime Duration 01:30-02:00 1/2 hr 02:00 02:00-06:00 4 hr 02:00-03:00 1 hr 03:00 03:00-06:00 3 hr 06:00 GG;GQ-a~:30 1/2 h.- 06:00-06:30 1/2 hr .. . 06:30 06:30-08:00 1-1/2 hr 06:30-07:30 1 hr 07:30 07:30-08:00 1/2 hr 08:00 08:00-14:30 6-1/2 hr 08 :00-1 0: 30 2-1/2 hr 10:30 10:30-11 :00 1/2 hr 11:00 11 :00-13:00 2 hr 13:00 13:00-14:30 1-1/2 hr 14:30 14:30-15:30 1 hr 14:30-15:30 1 hr 15:30 15:30-03:30 12 hr 15:30-17:30 2hr 17:30 17:30-18:30 I hr 18:30 18:30-23:00 4-112 hr ..--. 23:00 23 :00-0 1 :00 2 hr '"--' Exhibit VI- 9c Progress Report Well S-24A Rig Nabors 9ES Page Date 2 08 September 99 Activity Retrieved Hanger plug Equipment work completed Pull Single completion, 4-1/2in O.D. Pulled Tubing on retrieval string to 24.0 ft MIU landing jt and BOLDS. Pulled tubing to floor. UD landing jt and tubing hanger. Completed operations Laid down 4512.0 ft of Tubing UD tubing at report time. Installing thread protectors to salvage tubing. 107 joints laid out Recovered 107 jts tbg plus XN nipple plus 20.50' cut jt. . -. ··Ptlll-Single'cûmpletiûn; 4~H2in O.D:-C¿-ont...) Removed Tubing handling equipment Equipment work completed Test well control equipme.nt Tested Bottom ram PIU testjt and tested lower pipe ram to 250/4000 psi. RID equipment. Pressure test completed successfully - 4000.000 psi Installed Wear bushing Eqpt. work completed, running tool retrieved 4-1I2in. Drillpipe workstring run Ran Drillpipe in stands to 3020.0 ft PIU EZSV bridge plug and RIH. At Setting depth: 3020.0 ft Installed Bridge plug Set and released form EZSV. Set 25K down to confirm set. Equipment work completed Circulated at 3020.0 ft Pump 30 bbls water spacer and displaced to 9.6 ppg mud. 10 bpm, 375 psi. Mixed and spotted 18 ppg milling pill to 2820' . Hole displaced with Water based mud - 100.00 % displaced Pulled Drillpipe in stands to 0.0 ft At Surface: 0.0 ft Planned maintenance Serviced Block line Line slipped and cut BHA run no. 1 Made up BHA no. 1 PIU section milling BHA. BHA no. 1 made up R.I.H. to 2799.0 ft Locate casing collar at 2799. Stopped: To correlate depth Milled Casing at 2794.0 ft PIU 6' above collar and begin section milling @ 2794'. Milled to 2797'. Recovered 150# metal. At Kick off depth: 2797.0 ft Circulated at 2797.0 ft Mix and pump sweep. Circ 14 bpm, 1325 psi. Facility PB S Pad Dateffime 09 Aug 99 01 :00 01 :00-02:00 02:00 02:00-03:30 03:30 03:30-04:30 03:30-04:30 '- Duration I hr 1-1/2 hr I hr I hr 04:30 Ö4:-3Ö-GG:O~ 1 ' 1 I') l,p ;.. ·.11 ¿., &.1.1 04:3(\-05:00 1/2 hr 05:00 05:00-06:00 I hr 05:00-06:00 1 hr 06:00-08:00 2 hr 06:00-08:00 2 hr 08:00 08 :00-1 0:00 2 hr 08 :00-10:00 2 hr 10:00 10:00- II :00 10:00-11 :00 11:00 11:00-13:30 11 :00-13:30 13:30 13:30-14:30 13:30-14:00 14:00 14:00-14:30 14:30 14:30-15:30 14:3Q-15:00 1 hr 1 hr 2-1/2 hr 2-1/2 hr I hr 1/2 hr 1/2 hr 1 hr 1/2 hr Exhibit VI - 9c Progress Report Well S-24A Rig Nabors 9ES Page Date 3 08 September 99 Activity Hole swept with slug - 400.00 % hole volume Pulled out of hole to 673.0 ft At BHA Pulled BHA Stand back HWDP and DC's. LID jars and section mill. BHA Stood back Fluid system Circulated at 26.0 ft RIU and circ to clean stack. Attempted to circulate thru 13-3/8" annulus, pressure to 400 psi, 12.5 ppg EMW, no circulation. Stopped: To change handling equipment 'Nel1head WOrK Removed Wear bushing Equipment work completed Removed Seal assembly Pulling 9-5/8" packoff at report time. Removed Seal assembly Pull 9-5/8" packoff thru stack. Packoff damaged, had to modify running tool. Recovered packoff. Wellhead work (cont...) Removed Seal assembly (cont...) Pull 9-5/8" packoff thru stack. Packoff damaged, had to modify running tool. Recovered packoff. Equipment work completed Pull Casing, 9-5/8in O.D. Pulled Casing on retrieval string to 25.0 ft PIU 9-5/8" spear and packoff assembly. Catch casing below hanger. Worked pipe to 350K, 400 psi on pump. 2' pipe movement at surface, no circulation. Stopped: To flowcheck well Well control Flow check Gas breaking out of crude/diesel freeze protect in annulus. Closed annular and took gas expansion to gas buster. Well unloaded 37 bbls fluid. No shut in pressure. Lubricate well, took 37 bbls to fill. Observed well static Pull Casing, 9-5/8in O.D. Worked stuck pipe at 2797.0 ft Work pipe to 4ooK. Pressure to 600 psi attempting to bread circulation. Unable to free casing. Release spear. Aborted attempts to work Casing free at 2797.0 ft Wellhead work Installed Seal assembly Eqpt. work completed, running tool retrieved Installed Wear bushing Eqpt. work completed, running tool retrieved Fluid system Reverse circulated at 2797.0 ft Attempted to circulate down casing annulus. Pumping away at 2 tptn, 1300 psi. No rcturüs up 9-5/8" '- (¡j Facility PB S Pad Dateffime 15:00 15:00-15:30 Duration 1/2 hr 15:30 15:30-21 :00 15:30-16:00 5-1/2 hr 1/2 hr 16:00 16:00-17:00 17:00 1 hr 17:00-18:00 1 hr 18:00 18:00-19:30 1-1/2 hr 19:30 19:30-20:30 1 hr 20:30 20:30-21 :00 1/2 hr 21:00 21 :00-21 :30 1/2 hr 21:00-21:30 1/2 hr 21:30 21 :30-23:00 1-1/2 hr 21 :30-23:00 1-1/2 hr 23:00 23:00-23:30 1/2 hr 23:00-23:30 1/2 hr 23:30 23:30-06:00 6-1/2 hr 23:30-00:30 1 hr 10 Aug 99 00:30 00:30-03:00 2-1/2 hr 03:00 03:00-03:30 1/2 hr 03:30 03:30-06:00 2-112 hr 03:30-06:00 2-112 hr ~ 06:00-13:00 7 hr Exhibit VI - 9c --- Progress Report Well S-24A Rig Nabors 9ES Page 4 Date 08 September 99 Activity casing. Stopped: To hold safety meeting Held safety meeting Held Technical Limit! Safety Meeting with T. Bunch and D. Abert. Completed operations BHA run no. 2 Made up BRA no. 2 PIU hydraulic multi cutter tool. BHA no. 2 made up R.I.H. to 2659.0 ft At 13-3/8in casing shoe To cutting point 10' above 13-3/8" casing shoe. Cut Casing at 2659.0 ft .. . .~. .:. Cut casing wiLh. multicutter ,...0 - . Completed operations Circulated at 2659.0 ft Open 13-3/8" annular valve and allow 9.6 ppg mud to U-tube crude/diesel freeze protect to outside tank. Recovered 100 bbls freeze protect. Hole displaced with Water based mud - 100.00 % displaced S/I to allow oiVgas/mud mixture to separate. Pulled out of hole to 654.4 ft At BHA Pulled BHA UD casing cutter. BRA Stood back Wellhead work Removed Wear bushing Equipment work completed Auid system Circulated at 2659.0 ft Closed blind rams and circulated thru cut in 9-5/8" casing. Obtained bottoms up (100% annulus volume) Wellhead work Retrieved Seal assembly Pulled 9-5/8" packoff. Equipment work completed Pull Casing, 9-5/8in O.D. Pulled Casing on retrieval string to 40.0 ft RIH. Latch casing w/ spear. Pulled to floor, 145K. Released spear. Fish at surface Rigged up Casing handling equipment Equipment work completed Circulated at 2659.0 ft Pump pill. Heavy slug spotted downhole Laid down Casing of 1200.0 ft Lay down 9-5/8" casing at report time. Laid down Casing of 1200.0 ft UD 9-5/8" casing. Recovered 67 jts + 15' cutjt. Recovered 11 turbulators. Pull Casing, 9-5/8in O.D. (cont...) '" .~ Facility PB S Pad Dateffime Duration 06:00-11 :00 5 hr 11:00 11:00-13:00 2 hr 13:00 13:00-22:00 9 hr 13:00-14:30 1-112 hr 14:30 14:30-15:30 1 hr 15:30 15:30-17:30 1 hr·· 17:30 17:30-19:30 2 hr 19:30 19:30-20:30 1 hr 20:30 20:30-21 :30 1 hr 21:30 21 :30-22:00 1/2 hr 22:00 22:00-22:30 1/2 hr 22:00-22:30 1/2 hr 22:30 22:30-23:00 1/2 hr 22:30-23:00 1/2 hr 23:00 23:00-06:00 7 hr 23:00-00:30 1-1/2 hr 11 Aug 99 00:30 00:30-01:30 1 hr 01:30 01:30-06:00 4-112 hr 01:30-06:00 4-1/2 hr 06:00-04:30 22-1/2 hr 06:00-16:30 10-1/2 hr 16:30 16:30-17:30 1 hr 17:30 Exhibit VI - 9c '-' Progress Report Well S-24A Rig Nabors 9ES Page Date 5 08 September 99 Activity Laid down 2659.0 ft of Casing (cont...) LID 9-5/8" casing. Recovered 67 jts + 15' cut jt. Recovered 11 turbulators. 67 joints laid out Rigged down Casing handling equipment RID and clean rig floor. Equipment work completed BHA run no. 3 Made up BHA no. 3 Fishing BRA, spear. BRA no. 3 made up R.I.H. to 2659.0 ft At Top of fish: 2659.0 ft Fished at 2659.0 ft - ..~,---- Latched fish. J arréD 2?..5K to 275K. Attempted to pump. No-go. Good jarring action. Released fish Abandoned effort to pull fish free. Serviced Top drive Inspected derrick and top drive. Repaired sheared bolts in top drive cover plate. Equipment work completed Pulled out of hole to 700.0 ft At BRA Pulled BRA UD fishing spear, bumper sub, accelerator jars. BHA Stood back Removed Drillfloor / Derrick Clear floor, PIU Baker tools. Equipment work completed Planned maintenance Serviced Top drive Equipment work completed Wellhead work Installed Wear bushing Eqpt. work completed, running tool retrieved BRA run no. 4 Made up BHA no. 4 Milling BRA. BRA no. 4 made up R.I.H. to 2659.0 ft At Top of fish: 2659.0 ft Milled Casing at 2670.0 ft Milling ahead, 4.5'lhr. 2670' at report time. Milled Casing at 2670.0 ft Milled casing to 2726'. SID to make a connection. BRA run no. 4 (cont...) Milled Casing at 2726.0 ft (cont...) Milled casing to 2726'. SID to make a connection. Began precautionary measures Investigated pressure change Wad of mill cuttings backing up flowline and bell nipple. Clean same. Completed operations !- ~ Facility PB S Pad Dateffime 17:30-20:00 20:00 20:00-20:30 20:30 20:30-23:30 23:30 23:30-02:00 12 Au~ 9o~ 02:00 " 02:00-03:00 03:00 03:00-04:30 04:30 04:30-06:00 04:30-05:30 05:30 05:30-06:00 06:00 06:00-09: 15 06:00-08:00 08:00 08 :00-08: 15 08:15 08: 15-08:30 08:30 08:30-09:00 09:00 09:00-09: 15 09:15 09:15-10:00 09:15-10:00 10:00 10:00-13 :00 10:00-10:30 10:30 10:30-12:00 ~ Duration 2-1/2 hr 1/2 hr 3 hr 2-1/2 hr 1 hr 1-112 hr 1-112 hr 1 hr 1/2 hr 3-114 hr 2 hr 1/4 hr 1/4 hr 1/2 hr 1/4 hr 3/4 hr 3/4 hr 3 hr 1/2 hr 1-1/2 hr Exhibit VI - 9c '_0 Progress Report Well S-24A Rig Nabors 9ES Page 6 Date 08 September 99 Activity Milled Casing at 2739.0 ft Finished milling 70' window for kickoff. At Window: 2739.0 ft Circulated at 2739.0 ft Circulate sweep. Flowline plugged off before sweep returns. Stopped: To service drilling equipment Rigged down Flowline Break flowline apart and unplug flowline. Cuttings ball plugging flowline. Equipment work completed Circulated at 2739.0 ft Obtained clean returns - 400.00 % hole volume . =: -.:' --P!.impswe'i:0ps, dean meta! fr6iif hòle.-- Puìkd. 01)t of hole to 672.0 ft At BRA Pulled BRA UD mills. 20% wear on mill. BHA Stood back 4in. Drillpipe workstring run Ran Drillpipe in stands to 2669.0 ft RIH wI muleshoe. At 13-5/8in casing shoe Washed to 2820.0 ft Wash to 2820' at report time. (Top of 18 ppg pill.) At Setting depth: 2820.0 ft Bottom of cement plug. 4in. Drillpipe workstring run (cont...) Circulated at 2820.0 ft Hole swept with slug - 200.00 % hole volume Pulled Drillpipe in stands to 2615.0 ft At top of check trip interval Ran Drillpipe in stands to 2820.0 ft No resistance. Stopped: To circulate Circulated at 28~0.0 ft Stopped: To hold safety meeting . Held safety meeting Held PJSM wI Dowell. Completed operations Cement: Kickoff plug Mixed and pumped slurry - 65.000 bbl Pump 5 bbls H20. Test lines to 3000 psi. Pump 35 bbls H20, 65 bbls cmt, 3 bbls H20. Displace with 17.5 bbls 9.6 ppg.mud. Cement pumped CIP 1000 hrs 8/12199. 4in. Drillpipe workstring run Pulled Drillpipe in stands to 2150.0 ft Stopped: To circulate Circulated at 2150.0 ft Circulate and clean hole. Got 2 bbls cmt contaminated mud to surface. _., - ....-... i .~_ '~ Facility PB S Pad Dateffime 12:00 12:00-13:00 Duration 1 hr 13:00 13:00-14:30 13:00-13:30 13:30 13:30-14:00 1-1/2 hr 1/2 hr 1/2 hr 14:00 14:00-14:30 1/2 hr 14:30 14:30-!7:00 7.: j !1-:=;:'- 14:30-15:00 1/2 hi 15:00 15:00-17:00 2 hr 17:00 17:00-06:00 13 hr 17:00-19:00 2 hr 19:00 19:00-20:00 1 hr 20:00 20:00-20:30 1/2 hr 20:30 20:30-22:30 2 hr 22:30 22:30-23:00 1/2 hr 23:00 23:00-06:00 7 hr 13 Aug 99 06:00-12:00 6 hr 06:00-07:00 1 hr 07:00 07 :00-10:00 3 hr 10:00 10:00-11 :00 1 hr 11 :00 11 :00-12:00 1 hr 12:00 12:00-18:00 6 hr 12:00-17:00 5 hr 17:00 17:00-18:00 1 hr Exhibit VI - 9c .....-' , Progress Report Well S-24A Rig Nabors 9ES Page Date 7 08 September 99 Activity Obtained clean returns - 150.00 % hole volume Pulled Drillpipe in stands to 0.0 ft Pump pill and POH. LID muleshoe. At Surface: 0.0 ft Wellhead work Removed Wear bushing Equipment work completed Circulated at 25.0 ft Washed stack with perforated joint. Functioned BOP's. Stopped: To service drilling equipment Installed Wear bushing Eqpt. work completed, running tool retrieved .. . Plan..'1e.d maintemiÌïce..~--~;: --.--- --- - -'=.=.~-_.:.. --- -I. Serviced Drillfloor / Derrick Cleared and cleaned rig floor. Equipment work completed Serviced Rotary table Level rig. Settling moved rig off center. Equipment work completed BHA run no. 5 Made up BHA no. 5 BHA no. 5 made up R.I.H. to 2364.0 ft RIH to 2100'. Washed to 2364', TOC. Observed 20.00 klb resistance Drilled cement to 2397.0 ft Stopped to test casing Circulated at 2397.0 ft Obtained clean returns - 150.00 % hole volume Cement contaminated mud. Tested Casing - Via annulus Tested 13-3/8" casing to 2500 psi for 30 min, bled off 178 psi, OK. Pressure test completed successfully - 2500.000 psi Drilled cement to 2610.0 ft Drilling hard cement. (Very hard) 30K wob, 100 rpm, 650 gpm. Drilling cement at report time. BHA run no. 5 (cont...) Drilled cement to 2669.0 ft Finished drill cement to 13-3/8" csg shoe. Completed operations Circulated at 2669.0 ft Circ and cond cement contaminated mud. Obtained clean returns - 300.00 % hole volume Pulled out of hole to 932.0 ft At BHA Pulled BHA UD steel DC's, stood back HWDP. BHA Laid out BHA run no. 6 Made up BHA no. 6 BHA no. 6 made up R.I.H. to 2400.0 ft Facility PB S Pad Datelfime 09:00-14:00 14:00 14:00-15:00 15:00 15:00-17:00 17:00 17:00-18:30 18:30 'j .1 18:30-20:30 18:30-20:30 20:30 20:30-06:00 20:30-23:00 23:00 23:00-04:30 26 Aug 99 04:30 04:30-06:00 06:00-15:30 06:00-12:30 12:30 12:30-13:00 13:00 13:00-15:00 15:00 15:00-15:30 15:30 15:30-22:00 15:30-19:00 19:00 ~' Duration 5 hr 1 hr 2 hr 1-1/2 hr 2 hr 2hï 9-1/2 hr 2-1/2 hr 5-1/2 hr 1-1/2 hr 9-1/2 hr 6-1/2 hr 1/2 hr 2 hr 1/2 hr 6-1/2 hr 3-1/2 hr Exhibit VI - 9c '~ Progress Report Well S-24A Rig Nabors 9ES Page Date 16 08 September 99 Activity Pulled out of hole to 2669.0 ft At 13-3/8in casing shoe POOH. Kingak 20-30 klbs o/pull. Hole in good shape. Serviced Block line Line slipped and cut Pulled out of hole to 1000.0 ft At BHA Pulled BHA BRA Laid out Laid out BRA. Top stabiliser balled in water courses. Bit balled on one water course plugging one jet. Bit in excellent condition. BOP/riser operations - BOP stack . Jnstål1ed-Top ï:am .... Equipment work completed Pull wear bushing. Change top rams to 7" and test same to 3500 psi. Pull test plug. Run Casing, 7in O.D. Rigged up Casing handling equipment Work completed - Casing handling equipment in position Clear rigfloor. R/U casing handling equipment and Fill up tool. Hold PJSM. Ran Casing to 2669.0 ft (7in OD) At 7in casing shoe Check Floats. Bakerlock shoetrack. Run 7", 26 lb/ft casing to 13.3/8" shoe @ 2669 ft. Circulated at 2669.0 ft Circulate casing contents - 5 BPMl205 psi. Run Casing, 7in O.D. (conL.) Ran Casing to 7684.0 ft (7in OD) Observed 10.00 klb resistance RIH. Up and down drags following consistent trend. At 7,684 ft unable to pull up- overpull= 350 Klbs. In HRZ formation. Circulated at 7684.0 ft Broke circulation Circulate @ 2 BPMI 300 psi- OK. Able to breakover pull @ 335-350 KLbs. Decision made to RIH without attempting any further pick up weights. Ran Casing to 10180.0 ft (7in OD) On bottom RIH. Tag bottom circulating last 20 ft. Final slack-off weight @ 155 klbs. 251 joints of 7", 26 lb/ft casing run. Rigged down Casing handling equipment Equipment work completed RID Franks Fill up tool. Packer element damaged but intact. R/U Dowell cement head. Cement: Casing cement Circulated at 10180.0 ft Obtained clean returns - 120.00 % hole volume Stage up pumps very slowly from I BPM to 6.6 BPM over a two hour period. FInal circulating pressure @ 6.6 BPMl500 psi. Circulating 130% string contnets, 120% am1Ulus contc.nts. HOld PJSM while circulating. _~~4"-- __._ _ .__" . --~ - - ,1- .. i -- =--:'~_.....-