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Home My WebLink AboutAIO 026 ) ) Image Project Order File Cover Page XHVZE 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. ~IO Od.0 Order File Identifier Organizing (done) ~wo-sided 1111111111111111111 o Rescan Needed 1111111111111111111 RESCAN ~olor Items: o Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) o Maps: o Other Items Scannable by a Large Scanner o Diskettes, No. D Other, No/Type: o Poor Quality Originals: OVERSIZED (Non-Scannable) o Other: o Logs of various kinds: NOTES: o Other:: vnJJ 11111111111111111 f) /s/ rvt - = TOTAL PAGES I ÚJ-. (Count does not include cover she~t) 'l1J1fl /5/ r V ~ 1111111111111111111 /s/ BY: ( M~rj9.) Date: I I . to 10 fa Project Proofing BY: ~ Date: 1~/IJI00 Scanning Preparation BY: C Maria ") ~. x 30 = J I . Date: I t-O. 0 (, I + Production Scanning Stage 1 Page Count from Scanned File: J C ~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: v/ YES Date: ¡/IO/ () to If NO in stage 1 page(s) discrepancies were found: NO VVlJ BY: ~ /5/ Stage 1 YES NO BY: Maria Date: /s/ I11II111I1111111111 Scanning is complete at this point unless rescanning is required. ReScanned I BY: Maria Date: /s/ Comments about this file: Quality Checked 1IIII11111111111111 10/6/2005 Orders File Cover Page.doc . 1. September 11, 2003 2. October 1, 2003 3. October 20, 2003 4. October 29,2003 5. November 20, 2003 6. December 4, 2003 7. December 4, 2003 8. September 27,2004 9. December 8, 2005 . INDEX ORION AREA INJECTION ORDER 26 Submission of Confidential (located in vault) Materials for Pre-application Meeting submitted by BPXA Submission of Orion Pool Rules (Confidential exhibits located in Vault) Notice of Hearing, Affidavit of publication, e-mail Distribution list, bulk mailing Submission of Supplemental Exhibits E-mail re: Addition to the Administrative Record Sign In Sheet Transcript Letter from AOGCC re: Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells BPXA Application to Amend Rule 4 (AIO 26.001) AREA INJECTION ORDER 26 ) ) J STATE OF ALASKA ALASKA OIL AND GAS CONSERV A TION 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 a proposed Orion Oil Pool, Prudhoe Bay Field, North Slope, Alaska IT APPEARING THAT: ) Area Injection Order No. 26 ) ) Prudhoe Bay Field ) Schrader Bluff Oil Pool ) Orion Development Area ) ) January 5, 2004 1. By letter and application dated October 6, 2003, BP Exploration (Alaska) Inc. ("BPXA") in its capacity as 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 a proposed Orion Oil Pool within the PBU. 2. Notice of a public hearing was published in the Anchorage Daily News on October 20, 2003. 3. The Commission held a public hearing December 4, 2003 at 9:00 AM at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska. FINDINGS: 1. Operator: BPXA is operator of the property in the area in which injection is proposed. 2. Project Area Pool and Formations Authorized for Enhanced Recovery: Enhanced recovery injection for the Orion development is proposed within the Schrader Bluff Oil Pool. The target injection zones are correlative to Prudhoe Bay Unit well V-201 between the measured depths ("MD") of 4,549 feet and 5,106 feet (Schrader Bluff Formation). Area Injection Order 26 January 5, 2004 ) ') Page 2 3. Proposed Injection Area: BPXA requested authorization to inject fluids for the purpose of enhanced recovery operations on lands within Umiat Meridian TI2N-RI0E, TI2N-RI1E, TIIN-RIIE, and TIIN-RI2E in the Prudhoe Bay Unit. 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 and the Milne Point Unit. The State of Alaska, Department of Natural Resources is the only affected surface owner. 5. Description of Operation: Initial development of the Schrader Bluff Oil Pool in the affected area, referred to in this order as the Orion development area, is planned in three phases, beginning near the crest of the structure and progressively moving toward the outer margins of the pool. Peak production rates are expected to be between 30,000 and 50,000 barrels of oil per day ("BOPD"). W aterflood injection rates are estimated to peak between 100,000 and 125,000 barrels of water per day ("BWPD"). 6. Hydrocarbon Recovery: The Schrader Bluff Oil Pool is estimated to contain 1,070-1,785 million stock tank barrels ("STB") of original oil in place ("OOIP") within the Orion development area, based on exploratory drilling and seismic mapping. Computer simulation results indicate primary recovery within the major sands of the development area is expected to be 5 to 1 0% of the OOIP, and implementing a waterflood may increase recovery to 20 to 25% of the OOIP. 7. Geologic Information: a. Stratigraphy: The Schrader Bluff Oil Pool encompasses reservoirs assigned to the Late Cretaceous-aged Schrader Bluff Formation ("Schrader Bluff'). The Schrader Bluff is divided into two stratigraphic intervals that are designated, from deepest to shallowest, the "0 sands" and the "N sands." The 0 and N sand intervals were deposited in marine shoreface and shallow shelf environments. The Schrader Bluff 0 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 sandstone at the top. Area Injection Order 26 January 5,2004 ) ) Page 3 The lower portion of the Schrader BluffN 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. b. Structure Overview: The structural dip ranges from 1 to 4 degrees to the east and northeast, and is broken by three sets of normal faults from Northwest to Southeast, North to South, and East to West. The Northwest to Southeast fault trend has throws up to 200 feet. The North to South striking faults, downthrown to the west and east, have throws of up to 100 feet. East to West faults are less common, and form the reservoir trap on the southwestern side of the Orion development area. c. Confining Intervals: The upper contact between the N Sands and the overlying Prince Creek Formation is a generally an abrupt transition from sandstone to mudstone forming the upper confinement. The Lower Prince Creek Formation (Ma-Mc sands) typically contains over 30 feet of laterally continuous shales and mudstones. Mudstones and muddy siltstones up to 1000 feet thick provide the basal confinement of the Schrader sandstones. 8. Well Logs: The logs of existing injection wells are on file with the Commission. 9. Mechanical Integrity and Well Design of Injection Wells: The casing programs for L-I03i, L-llli, L-115i, L-117i, and V-I05i were permitted and completed in accordance with 20 AAC 25.030. These wells are designed to allow dual injection with packers installed for zonal isolation. Cement-bond-Iogs have been run and demonstrate isolation of injected fluids to the Kuparuk River and Schrader Bluff Formations. Mechanical integrity tests have been performed on all wells. 10. Type of Fluid / Source: Fluids requested for injection are: (a) produced water from Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; (b) source water from the Prince Creek Formation (also known as the U gnu formation); (c) tracer survey fluid to monitor reservoir performance; (d) fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); ( e) source water from the Seawater Treatment Plant; and (f) non-hazardous water collected from well-house cellars and standing ponds. Area Injection Order 26 January 5, 2004 } ¡ ,)' Page 4 11. Water Composition and Compatibility with Formation: The composition of produced water will be a mixture of connate water and injection water, and will change over time depending on the rate and composition of injection water. Based on analyses of Polaris water samples, no significant compatibility problems are expected between connate water and injection water. 12. Injection Rates and Pressures. Fracture Information: 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 a dipole sonic log from well W-200 (or a fracture gradient in the mudstones of approximately 0.67.) On the basis of this test information, the Commission ordered (Area Injection Order 25, dated 2/4/03) that Polaris Oil Pool normal injection pressure be limited to 0.67 psi/ft to ensure injection stays within the intended injection interval. Subsequently, BPXA performed step rate water injection tests in two Polaris wells, W- 212i and S-215i. The Schrader Bluff Formation in these wells should be comparable to that in the Orion development area. Injection rates of up to 10000 BWPD and injection gradients of 0.75-0.8 psi/ft were achieved. Temperature surveys showed the water to be confined to the intended intervals, with no fluid movement behind pipe. This pressure exceeded that obtained with the stress test described above. The Commission granted approval (see Enhanced Recovery Injection Order No.1) of a pilot water injection test to be conducted in well V-I05. Confirmation of vertical confinement within the Schrader Bluff Oil Pool is an objective of the pilot project. BPXA requested a maximum surface injection pressure of 2800 psi with an average surface operating pressure of 2200 psi. The injection rate will be controlled by flow restriction at the downhole injection mandrel, and hence pressure will be restricted adjacent to the perforations in the Schrader Bluff formation. 13. Freshwater exemption: Aquifer Exemption Order #1, dated July 11, 1986 exempts all portions of aquifers beneath the Western Operating Area of the Prudhoe Bay Unit, including the area designated for the proposed waterflood pilot project. 14. Mechanical Condition of Adjacent Wells: Adjacent wells to the existing proposed injectors have been reviewed for mechanical isolation. The records of cement jobs and cement bond logs were reviewed. All wells appear to have mechanical isolation between the Schrader Bluff and all other intervals. Area Injection Order 26 January 5,2004 ) ") Page 5 CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. Water injection will significantly improve recovery. 3. Dual injection is appropriate so long as mechanical isolation of the pools within the wellbore is assured and water injection is allocated between the pools. 4. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 6. Injection pressures will be above the fracture gradient of Schrader Bluff Sandstones. Pressure should be maintained below the fracture gradient of the confining mudstones. Results from the pilot water injection test in Well V-I 05 will be used to determine if injection pressure may be increased above 0.67 psi/ft. 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. Sufficient information has been provided to authorize five (5) existing wells to inject water into the Schrader Bluff Oil Pool for the purposes of pressure maintenance and enhanced oil recovery. Authorization to inject in additional wells subject to the provisions of this order is appropriate upon verification of the mechanical condition of all wells within a one-quarter mile radius. NOW, THEREFORE, IT IS ORDERED that: 1. Enhanced Recovery Injection Order No.1 dated October 14, 2003 continues in effect according to its terms. 2. The underground injection of fluids for enhanced oil recovery is authorized in the area defined below, subject to the following rules and the statewide requirements under 20 AAC 25 (to the extent not superseded by these rules). Umiat Meridian Township Range, UM T12N-R10E Lease Sections ADL 025637 13 and 24 N/2 TI2N-R11E ADL 047446 17, 18, 19, and 20 Area Injection Order 26 ') ) Page 6 January 5, 2004 ADL 047447 16 S/2 and NW/4 and S/2 NE/4, 21, and 22 ADL 028238 25 SW/4, 26, 35, and 36 ADL 028239 27,28,33 E/2 and N/2 NW/4, and 34 ADL 047449 29 N/2 and SE/4, and 30 N/2 NE/4 TI1N-RIIE ADL 028240 1,2, 11 E/2 and E/2 NW/4, and 12 ADL 028241 3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4 ADL 028245 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 TIIN-RI2E ADL 047450 7, and 8 S/2 and NW/4 ADL 028263 16 SW/4 and S/2 NW/4, and 21 SW/4 and S/2 NW/4 and NW/4 NW/4 and W/2 SE/4 ADL 028262 17, 18, 19 N/2 and SE/4 and N/2 SW/4, and 20 ADL 047452 28 W/2 and W/2 E/2 ADL 047453 29 N/2 and N/2 SE/4 Rule 1 Authorized In.iection Strata for Enhanced Recovery Fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery within the Orion development area into strata that are common to, and correlate with, the interval between measured depths 4,549 feet MD and 5,106 feet MD in the PBU V-201 well and between the measured depths of 4174 feet and 4800 feet in Milne Point Unit well A-I. Rule 2 Fluid Iniection 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. Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection include: a. produced water from 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; d. source water from the Prince Creek (Ugnu) Formation; and e. non-hazardous filtered water collected from Schrader Bluff Oil Pool well house cellars and well pads in the Orion development area. Area Injection Order 26 January 5, 2004 ) ) Page 7 Rule 4 Authorized In.iection Pressure for Enhanced Recoverv a. Injection operations must ensure that injected fluids do not fracture or migrate out of the approved injection stratum. b. Injection pressure shall be limited to .67 psi/ft, except to the extent allowed per Enhanced Recovery Injection Order No. 1 or as otherwise approved by the Commission. c. If fluids are found to be fracturing the confining zone or migrating out of the approved injection interval, the Operator must immediately shut in the injector(s). Injection may not be restarted unless approved by the Commission. Rule 5 Monitorine Tubine-Casine Annulus Pressure Tubing-casing annulus pressures within each injection well must be checked and recorded daily to ensure there is no pressure communication or leakage in any casing, tubing or packer. Rule 6 Demonstration of Tubine/Casine Annulus Mechanical Inteeritv 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 Injection 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 Notification of Improper Class II In.iection Inj ection 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 26 January 5, 2004 ') ) Page 8 Rule 9 Plu22in2 and Abandonment of Fluid In.iection 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 10 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 11 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 freshwater. ,I?ONE at Anchorage, Alaska and date, d January 5, 2.00. 4. G2..-. .' ' -, . , ~ OIL -1N. ~.L IY-' L. ,0" It.. (l-----. ¡( ~~~~~ Sáfah~, Chair ('~?~~l~,'~~P 0~~ c:~..%.a.....~ommission ~ ......-;<.;.J//''''..:,;''..:.'.:\r.:.':;;..'...!,..t .I¡".J'I' 1 Ý(I /I~ ~ ~\ (") ¿;;' ¡f'¡{iii¡!.·\;\'···'·~~'1:.:·;:i:·~/:;···..·;.:;g:,:;.'~~__-ll, Danl'el T. Seamount, Jr., Comml'SSl'oner ~ t? ~ . i '\.' l:.:'< ':~':\'I:' "-¡-',:j i' A... ¡ '~~i~~~~iilif;"(~~{\;~~~~ Alaska Oil and Gas Conservation Commission 'c1 'l'l(i""r r·,·...\·~~ 1.>',;.<' ~~:~;;;~~,,;)ßY' - 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 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely tìled. 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). CO 505 and AIO 26 ) ) Subject: CO 505 and AIO 26 From: Jody Colombie <jody _ colombie@admin.state.ak.us> Datè:NiOll,()5Jan20041Q:5 f:} 1.·...PQQQ ~b.:·.·.·.··~.~~~~ª··.·~··.·.~çi~~t·...~ø~¢î[l~ì~~~@~~µ...~.t~~~.J.~~.~.~~·....··.·'·'···············:·:··'·....... ..... . Please add to web site AIO Content-Type: applicationJrnsword Content-Encoding: base64 I................................................................................".."..,...,....,...".....,...................,...."...,...,....,...,. ............................................................."..................,..... ...........,.........................................,............."........,..................................................................."..................."'.......................¡ I I Content-Type: applicationJrnsword' i CO 505.doc. . : Content-Encoding: base64 ,..................................................................................................................................................................................................................................................................................................................................................... 1 of 1 1/5/2004 10:52 AM CO 505, AIO 26 and MPU L-43 Notice ) ') I I MPU _ L-43 _Spacing _Exception _ N otice.doc Content-Type: applicationlmsword 1 of 2 1/5/2004 10:51 AM CO 505, AIO 26 and MPU L-43 Notic0 ) ") Content-Encoding: base64 AIO 26 l Content-Type: application/msword .doc: . Content-Encoding: base64 ""..."""..................................................., I...... ............................................. ..............,.........."..........,,,.,,"''''...... .....................,.....,...."..............."..."......."................."...."....... ...........,.........................".............................. ......"..........,.......................... I I : I 0 :.1 Content-Type: applicationhns\vord : CO 5 5.doc . . Content-Encoding: base64 ì--____ 20f2 1/5/2004 10:51 AM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 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 ) Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 ) David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rdStreet, #1202 Boise,ID 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 I:.'-:~ =~-::-~~~ (~'I'~' ..."'. if,wicl !//.;/ÓY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 'I.. ,. Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order authorizing underground injection of fluids for enhanced oil recovery in a proposed Orion Oil Pool, Prudhoe Bay Field, North Slope, Alaska IT APPEARING THAT: ) Area Ioj ectioo Order No. 26 ) ) Prudhoe Bay Fie}d ) Schrader Bluff Oil Pool ) Orion Development Area ) ) January 5, 2004 1. By letter and application dated October 6, 2003, BP Exploration (Alaska) Inc. ("BPXA") in its capacity as 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 a proposed Orion Oil Pool within the PBU. 2. Notice of a public hearing was published in the Anchorage Daily News on October 20, 2003. 3. The Commission held a public hearing December 4, 2003 at 9:00 AM at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska. FINDINGS: 1. Operator: BPXA is operator of the property in the area in which injection is proposed. 2. Project Area Pool and Fonnations Authorized for Enhanced Recovery: Enhanced recovery injection for the Orion development is proposed within the Schrader Bluff Oil Pool. The target injection zones are correlative to Prudhoe Bay Unit well V-201 between the measured depths ("MD") of 4,549 feet and 5,106 feet (Schrader Bluff Formation). @r~c;r~ ~Jlrullb 1"'-'''\ r"f:'1i If!! Ir ~,~~) LM ) II'~ I-I I-;~~ (C~:)'J? i~ &~ :! ..A \, '\ " , l..,¡~ ¡~!, ~I' \ 'I LrLl1~æ)l ~ ) ALASKA. OIL AlWD GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 26.001 Mr. Gil Beuhler Greater Prudhoe Bay West Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Beuhler: By letter dated December 8, 2005, you requested that Rule 4(a) of Area Injection Order 26 be eliminated. This rule limits injection pressures to 0.67 psi/ft. BP Exploration (Alaska), Inc. ("BPXA") has stated that water injection volumes are severely constrained with this pressure limitation, negatively impacting voidage replacement. The Alaska Oil and Gas Conservation Commission ("Commission") finds that administrative amendment to eliminate the injection pressure restriction is appropriate for the Orion Oil Pool. It is BPXA's responsibility to ensure the injected fluids stay within the approved injection interval. Accordingly, Rule 4 of Area Injection Order 26 is amended to read as follows: Rule 4 Authorized In.iection 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. 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. Discussion: The Commission originally ordered this rule to ensure that Orion injected water does not fracture or migrate out of zone, and based its decision upon BPXA's estimate of a 0.66- 0.67 psi/ft fracture pressure for the confining mudstone using data from stress tests and dipole sonic log. The Commission noted that injection tests within the Schrader were planned to determine if higher injection pressures would result in water migrating out of zone and specifically indicated that dependent upon the results of these tests, the Commission may waive this restriction. ) ) Mr. Oil Beuhler AIO 26.001 December 13,2005 Several tests have been conducted that support BPXA's conclusion that increased injection pressures will not result in migration out of zone. A zonal isolation test was completed in Orion well L-210 in April 2005. Sand-face pressure gauges were installed adjacent to discrete zones both above and below an isolated inj ection interval in order to record pressure response and reveal whether injection was breaching the confining barriers. The two perforated zones were separated by around 28 feet TVD of unperforated OA interval comprised of silty mudstone. Injection rates of up to 4200 BWPD with an injection gradient of up to .82 psi/ft were achieved while injecting into the lower zone. No pressure response in the adjacent zone was seen; hence, the water did not breach out of zone. BPXA performed step-rate water injection tests in June 2003 in Polaris Oil Pool Wells W -212i and S-215i. These tests showed significant improvement in injection rate with increased injection pressure. Temperature logs run in July 2003 showed the water to be confined to the intended intervals. These tests were performed at an injection gradient of 0.75-0.80 psi/ft, well above the expected confining zone fracture pressure gradient of 0.67 psi/ft. Based upon this information, the Commission approved removal of the injection pressure limitation in the Polaris Oil Pool. A pulse test in Milne Point Schrader Oil Pool MPS-26 also indicated full zonal isolation. The well had been injecting at about 0.8 psi/ft for two years prior to the test. The conclusions from these tests are a. The shale barrier between sands is not transmissible; b. Packers and completion cement integrity allow for good mechanical isolation and independent zonal injection control; and c. Fracture height is confined to the individual injection sand interval. Aquifer Exemption Order #1, dated July 11, 1986 exempts all portions of aquifers beneath the Western Operating Area of the Prudhoe Bay Unit, including the area designated for the proposed waterflood pilot project As stated in Rule 10 of AIO 26, unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule of AIO 26 or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person ) Mr. Gil Beuhler AIO 26.001 December 13, 2005 ) may not appeal a Commission decision to Superior Court unless rehearing has been requested. : Alaska and dW 2005. Daniel T. Seamount, Jr. Commissioner f b... OIL A~ ~~~ ~N~ ,.¡(~~;! 1m, . K~;·v' '\ (.!,~ \ ~~I / I ,Q "/ '" /".:,~,\~II / l~1 7 It , '" '~'\ tp f, ",,,.,.:iii~ i~., ,~ .... ,.~<.,', 11\\ ,\. ,,'.'.\>0.::.,,--.:..~\ .~.::--, . ,./'-.....'.c:· }"¡;:.,,, t" t¡ ~, ~ r ) 1 ~ '"' f ¿;;::'~/(i(, \:':..;:'::';:.:~::'.:~;'~:.:/~~..~~~ ( \ ~ rll~ i,\ ,'" 'J. ;~;~:,I '-- \·5;l~ .J;.:;~ )¡";:';;:':):~:: ;~: :Y:-.::' ·1~~:::'il;;~ <'Ÿ 6~ '~' '1!:6' '',;''''.' ~~"".:.'" ..',":."':~'l",."""<>- ..,J. ¿::f;, V.J.· ~":'; l:~\h::¡;.'.· :,.::>:;'" .!,""'> ..~,,. ,\;:...¡' <P~i!!af~.;p II ~~~ Commissioner \.1026.001 PHU ') ) Subject: AI026.00 1 PBU From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Thu, 15 Dee 2005 14:57:27 -0900 .' ,'.' , ';,"::,:' ::' '. ::':,:' ,':' ,:',:'" ',' ',,::':,::' ',' : ,:', '" '" ,': <:'::: ,,' \,'\ ,": :".:,' ' , 1Ø;lii~di~'~~Q$éØ fr~ç~~!¢P,l~~;':;:!" i i I:i . '", .<,', "',: I ,:., '"::: ;',":' ':"!','. 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'" ' , ' <y~~n91~~9L'geR~~~Bt9~~.4gsp{off@ao/ør~gg",er.cpg¡~"I,gre~~ ~~dy<g1J~?g.naây~snelLcom>~Fred Steece .~f%e'~.st~eQ~@,st~t~.sâ~¥~~,. ~cro~tY<~9rott~®cn~tn~.coWf,j~JQne~ .~jejOtl~s@~u~9rapower;com>, da})~<:d~p~~~la~kå.~h~~~, jtP~eri9k..<jrq'~e~ic1~~gei.n~~ ,,~Y~c~<eYancY@1seal-tite.ne~~"J amesM'~ Ruud" .~~e~.~ln.pJµd@b(nlþ~?phillipsi~c?rn*,··. Brit. L!y~l~.·<:fl1~Ptllaska@a~.n~tê~j@.. .... <jab@dnr.stat~.åk. u~:>' bu()pojè:,<þuoµoje@bp..col11>,. Marklf~ley -<rparI<lhanleY@~a4arko.c0gt>, loren_lel11an <loren _lél1lan@~oy.state¡ak. uSe ,Julie!i0~le<j.ulie_ houle@dnr.stat~.ak. us~,JohnWKatz <j ",katz@sso,. 9~g> ,Spzaµ J . HiH<:~u:zan+-hill@de9'ist~te'ak' qs>,taþlerk<taþlerk@un9caLco111>' Brady <bradY($~o~a.~r~:>,I3FianPI~ve1ock' <beh@dnr,stat~.ak.us> ,:bpopp .<bpopp@~orough.kenai.ak. us>, Jim W. h. it. e,',' ~,·...i... m.... wh.. ,.it....e..... .,@. .' S...a..t. .x, , .rr. .' ...c.o..·..l11>..".,. '.. I.'.J ohnS.. ..H.·.. .awort.h'" <....Jo,hn. .. . s.......ha.....wort.,. h@..ex.xb.nm.·...obiLc.·.o.,....111>,.marty , ,I, ':' I"': I,"; ,,',", ",,', ", ","', ,,"',' I " ',:, "':1' ':,' ',' I, '" " ' ' , <tpa.rty@r1dn(þ.1stri~l.'c'om>,.ghamrnons <ghamµ1ons@aoLcom> ,r~clean <rmcle~@pob9x.alaska.net>, mkm7200 <l11km 7200@ao1.com>, Bri~ Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapowe~.com>, ToddDurkee<TDURKEE@KMG.com>,Gary Schultz <gary _schultz@dnr .state.ak. us>, Wayne R~cier <RANCIER@petro-c~ada.ca>, Br~don Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoi1.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copel~d <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zem~ <kjzem~@marathonoi1.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@~adarko.COM>, Scott Cr~swick <scott.cr~swick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unoca1.com>, jack newell <j ack.newell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, david roby <David.Roby@mms.gov>, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <J erry. C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belm~ <roger.belm~@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unoca1.com>, Todd Kratz <ToddKratz@c,hevron.com>, Gary 10f2 12/15/20052:57 PM \1026.001 PBV ) ) R. O. g."'.e.,., r. S.' .. ~,g. aiD', ,'_..·.....:.t.O.,. ....ge. r...~, @. re..ven...·lle~~'.t..·'.·.ª.t. e. ....a...k. .'U...s*..".,A.......,···~.l1ur.. ....'...: çö...p.·., 0. U.' ..10. '.s. :!<..Å,rt. llÛf..,-.,. C.opo.u...·.l..o.· ..s@.d..nr...· ...s.ta. t.é.~k. U, s>,K.....en . I' ,:' 'I ':,',' ,,,', ,','" ,I I" 1", ': 1,:'(1:: ",' "," ,,,' :;",," " . '. :' , ., "'," ,I' ;"" < "', ",1",' ",,' ,:. ,':," ','II, ',' :": ' ",:. ,!" I "'." :"',' " I' , . ,','I' I . ,. ""',,: " , ': ,."," ' " ,: I ,.1', :' " , ,I <~en\@seporp~i~S.co~~I'....Stev: :La~b~rt ~s~l~?~rt~~oç~l.~op1~, Jqe..}Jicks<Çl1e",s@radiokenai;com>, J eny. ~9CMtd1eon. ~su~i:ttl~~qtonQw~y~pO.cqrtl>~ga~lJo~d<p~1l1~q@~9sala~ka.net> ,'.Bill Walker <bil1-W\\'a~~.n~!~,. IrisN1~tt~~~s~Iri~:- o/Ifltthews~legis.state.'ak~ us>, PaµI' Deçi<:er <paul_ deckerC$dnést~te.::lk.'us>, ....... . .... .' ,,' : .....,:.. .' , 20f2 12/15/20052:57 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil I nformation Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage; AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation . Land Department PO Box 129 Barrow, AK 99723 ) Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 ) David McCaleb IHS Energy Group GEPS 5333 West heimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue SOldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 . \~~ b0 \~\~\ \d" \~ . #9 ) BP ...~~Ioration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 bp "r¡l ~ II December 8, 2005 ~€C€I'vÞ D£co. cD Allllka Oil fJ 2005 & Ga~ C A. 0111. Co . nChø',g, 111rnlsSio!l Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Application for Amendment to Area Injection Order No. 26 Dear Commissioners: BP Exploration (Alaska) Inc. (BPXA), Operator of the Prudhoe Bay Unit (PBU), hereby makes application to amend Area Injection Order No. 26, Rule 4. BPXA requests that Rule 4 be amended as follows: Rule 4 Authorized Iniection Pressure for Enhanced Recovery a. Injection operations must ensure that injected fluids do not fracture or migrate out of the approved injection stratum. b. If fluids are found to be fracturing the confining zone or migrating out of the approved injection interval, the Operator must immediately shut in the injector(s). Injection may not be restarted unless approved by the Commission. This amendment would remove the injection pressure limitation on the Orion Oil Pool. This constraint seriously limits injection rates which have been shown to be inadequate to provide sufficient voidage replacement for ensure proper reservoir management. This situation was discussed in our annual surveillance report and with Commission Staff during the technical review held on September 28, 2005. In 2003, BPXA requested and was granted a similar amendment to AIO 25, which applied to sister field, Polaris. In that request and subsequent technical discussions, it was shown that injection could be accomplished at pressures above the confining mudstone approximate fracture gradient of 0.67 psi/ft without fracturing through this confining layer. Step rate tests and follow-up temperature profiles showed that fluids were not migrating out of the authorized injection stratum, and therefore the injection pressure limitation was removed. At this time, AIO 26 limits Orion injection pressure to a maximum 0.67 psi/ft gradient, a restriction the Commission has deemed appropriate to remove from the other Schrader Bluff and West Sak developments. Analysis of formation evaluation logs, well testing, and field experience indicate that the Schrader Bluff reservoir in the Orion Field is correlative and similar in stratigraphy, rock mechanical properties, and operational behavior to adjacent ) ) Schrader BlufflWest Sak fields - Polaris, Milne Point, and KRU West Sak. AU i fields lie in a structurally shallow depth range which results in similar corresponding fracture gradients. Based on these observations, it follows that the Orion Schrader Bluff reservoir should be analogous to the adjacent Schrader BlufflWest Sak fields under increased injection pressures. In order to qualify this assumption, a zonal isolation test was completed in Orion well L-210 in April 2005. Sand-face pressure gauges were installed adjacent to discrete zones both above and below an isolated injection interval in order to record pressure response, and reveal whether injection was breeching the confining barriers (Exhibit A). The outline and objectives of this plan were reviewed with Commission Staff on February 25, 2005. Injection rates of up to 4200 BWPD and an injection gradient of up to 0.82 psi/ft were achieved while injecting into a single zone. Results showed no pressure response in the adjacent zones, and no indication of barrier breach (Exhibit B). A similar pulse test was conducted on Milne Point Schrader Bluff well MPS-26 to test inter-zone isolation, which yielded identical results. This well had been operating at a 0.8 psi/ft injection gradient for almost two years prior to the test. The test concluded: ./ The shale barrier between the sands is not transmissible. ./ The packers and completion cement integrity allow for good mechanical isolation and independent zonal injection control. ./ Fracture height is confined to the individual sand. Based on these tests, and the similarity between the West Sak/Schrader Bluff fields, we are requesting a change to Rule 4 of Area Injection Order 26 to remove the injection pressure constraint. Thank you for your timely consideration. Any questions regarding this request should be directed to me at 564-5143 or Taylor West at 564-4647. Sincerely, ~'~. / () / ~. ¡~~~./ - Gi Beuhler - r GPB WEST Manager Attachments Exhibit A - L-210 Isolation Test Configuration Exhibit B - L-21 0 Zonal Isolation Test Results CC: Sonny Rix (Exxon Mobil) Gary Forsthoff (Chevron) Jonathan Williams (BPXA) Dan Kruse (CPAI) Paul Winslow (Forest Oil) Gary Gustafson (BPXA) L-;21 0 Isolation Test Configuration :5 't 00 - 8600 -4400 = - 8700 - 4500 _ 8900 = 9000 ~. ~ -'--'.. ,....,......., JCU= _9100 _ 9200 -4700 = - 9300 '" e 00 --;;;:::;ø' --:::;:;:;t'" · . · 4 \I ~ ~ · . J ~ .. Downhole ~ Exhibit A ¡bit ? .' ~ 0:,.\:5 ,",v' ~ ~'V ~. n'~~ I\.V· r.:. ~'ò ,",'-1 . r": ~'ò '"' 'U . ~ f": OJ "-.). ~ ",r¡... 1\.;.,»' m O¡ a. 1800 :s 1920 ~ ! Q.. 1900 -. ~ 2000 on #8 ) ,) ~,,~ -\ """"""""" .'-~ lnJ ~.' . ./,~' "! r' .,! :r ",," . / 1"\'1 'I, ",.,'\ " ",w \ '. '¡ :1 ,"::1 nù)' 'I' .~, '\ ': ;\ r i.,~' l..; LiD ~ .L=:J (<"-\ 'i'-.=J In!1 .j ¡ :.,1 1.iJ: 1.1 .' .:..,. 'I ,J ',,' : :1 :. , ,j:/ \,~ U n li4'~\ trLj 'I ) ! \ \\, ", [i I ,~, \ ;~\') "\ " !-, ,r 1 ,I ,i ,I. ,J J ,--..,., i-J I.... .,._,J i:"\ I ;(\ I. I J '\ '\ /iJ\ /11 \ .W ~,J~ FRANK H. MURKOWSKI, GOVERNOR A.",A.~1iA OIL AND GAS CONSERVATION COMJIISSION 333 W. ]TH AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276·7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contan1Ïnation 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 In te gri ty" Affected Rules "Well Integrity Failure and Confinement" " Administrative Action" Area Ioj ection Orders AIO 1 - Duck Island Unit AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; Western Operating Area AIO 4C - Prudhoe Bay Unit; Eastern Operating Area AIO 5 - Trading Bay Unit; McArthur River Field AIO 6 - Granite Point Field; Northern Portion AIO 7 - Middle Ground Shoal; Northern Portion AIO 8 - Middle Ground Shoal; Southern Portion AIO 9 - Middle Ground Shoal; Central Portion AIO lOB - Milne Point Unit; Schrader Bluff, Sag River, Kuparuk River Pools AID 11 - Granite Point Field; Southern Portion AIO 12 - Trading Bay Field; Southern Portion AIO 13A - Swanson River Unit AIO 14A - Prudhoe Bay Unit; Niakuk Oil Pool AIO 15 - West McArthur 6 7 9 6 7 9 6 7 9 6 7 9 ._,____,_."'_'M_"'.'_____,,__..,____ 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 Unit; Meltwater Oil Pool Ala 22C - Prudhoe Bay 5 No rule 8 U nit; Aurora Oil Pool 6 9 AIO 23 - Northstar Unit 5 AIO 24 - Prudhoe Bay Unit; 5 No rule 9 Borealis Oil Pool AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Disposal Injection Orders DIO 1 - Kenai Unit; KU No rule No rule No rule WD-1 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; WMRU D-l DIO 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 Injection Order "Demonstration of Mechanical Integrity" DIO 11 - Kenai Unit; KU 24-7 DIO 12 - Badami Unit; WD- 1, WD- 2 010 13 - North Trading Bay Unit; S-4 DIO 14 - Houston Gas Field; Well #3 010 15 - North Trading Bay Unit; S-5 010 16 - West McArthur River Unit; WMRU 4D 010 17 - North Cook Inlet Unit; NCill A-12 010 19··- Granite Point Field; W. Granite Point State 17587 #3 010 20 - Pioneer Unit; Well 1702-15DA WDW 010 21 - Flaxman Island; Alaska State A-2 DIO 22- Redoubt Unit; RU 01 010 23 - Ivan River Unit; IRU 14-31 DIO 24 - Nicolai Creek Unit; NCU #5 010 25 - Sterling Unit; SU 43-9 010 26 - Kustatan Field; KFl Storage Injection Orders SIO 1 - Prudhoe Bay Unit, Point McIntyre Field #6 SIO 2A- Swanson River Unit; KGSF #1 SIO 3 - Swanson River Unit; KGSF #2 Enhanced Recovery Inj ection Orders ErO 1 - Prudhoe Bay Unit; Prudhoe Bay Field, Schrader Bluff Formation Well V-I05 2 2 2 2 2 2 2 3 3 3 3 No rule 3 3 No rule 2 2 No rule Affected Rules "Well Integrity Failure and Confinement" "Administrati ve Action" 3 4 3 5 3 6 3 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 N'o rule No rule No rule 6 No rule 7 No rule 8 Injection Order EID 2 - Redoubt Unit; RU-6 ) "Demonstration of Mechanical Integrity" 5 ) Affected Rules "Well Integrity Failure and Confinement" 8 "Administrati ve Action" 9 I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA ADVERTISING ORDER SEl;eQTTOMF()RIN"OICE~OI)RE~ NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO, CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC 333 West ih Avenue, Suite 100 Anchorage, AK 99501 907-793-1221 AGENCY CONTACT DATE OF A.O. R o M lody Colombie September 77, ).004 PHONE PCI\! (907) 793 - ) )) ] DATES ADVERTISEMENT REQlJ IRED: T o Journal of Commerce 301 Arctic Slope Ave #350 Anchorage, AK 99518 October 3, 2004 THE MATERJAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. A IT ACH 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:; BCC:Cynthia BMciver <bren_mciver@admin.state.ak.us>, Ang~lá Webb <an.·, g¡e_webb@a.dmin.state.àk:.us>"Robert EMintz <robert..~ ~i9tz@.· 'låW~.S.. tate.. *~u. .s>. ' ..Christine . . . .' H;ansen <c.han$en@iogcc..state.ok.us>~.Terrie Hubble <hubbletl@bp.coD:1>, Sondra Stewman <StewinaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska~net>, staµekj <stanekj@unoca1.com>, ecolaw <:ecolaw@trustees.org>, roseragsdale <r()seragsdale@gcLnet>,.trmjrl <tnnjr 1 @~o1.com>, jbriddle <jbridcile@marathonoiLcom>,.ràckhill <rockhill@aoga.org>, shaneg <shan,eg@evergreengas.com>, jçlarlington<jdårlington@forestoil..coin> ,.n~lson <knelson@petroletimnews.com>, cbøddy <cboddy@usibeIli.com:>, Mark.,DåIton , <mark.dalton. ..@hdrinc.com>,.Shånnon Donnelly <shannon.donnelly@conocophiIlips.com>; '~Matk P. " . . . . . \. .: Worcest~r"<mar~.p.w:orcester@conocophillips.~om>, "Jerry C;. Dethlefs" ..' \ <jerry.c.dethlefs@conocöphìl1ips.com>, Bob .<bob@inlet~eeper.org>, wdv<vvdv@dnr~state.ak.us>, . . . tjr<tjr@dnr.state.ak.u$>, bbritch <bbritch@a1aska.net>, :m.jnelson .<rnjrielson@pu~ingertz.com>, Charles O'Donnell <charles.o'donnell@veco.cori1>, "RandyL. Skillern" <SkilleRL@BP.cpm>, "Deborah]. Jonest! <JonesD6@BP.com>, "Paul G. Hyatt" <hyattpg@BP.com>, "Steven R. Rossberg" <RossbeRS@·ßP .com> ~ Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.()r~>, Gordon Pospisil <PospisG@BP.coJ,TI>, "~rancis s~ Sommer" <Somme:fFS@BP.co~>, MikelSchultz <Mike1.Schultz@BP.com>, "Nick.W..Glover" <GloverNW@BP.,com>~."Daryl J~ Kleppin" <KleppiDE@BP.com> , "Janet D'. Platt" <PlattJD@BP . com> , "Rosanne M. Jacobsen" <JåcobsRM@Bp.com>, ddonkel <ddonkel@cfl.rr.com>, Collins Mount <collins _ motint@revenue.state.ak.us>, mckay <mckay@gci.net>,Barbara F. FuHmer <barbara.f.fullmer@conocophillips.com>, bocastwf <boc~twf@bp.com>, Charles, Barker: <barker@tisgs.gov>, dou,g_schultze <doug_ schultze@xtoenergy.com>,H~· Alfòrd <hà.rik.a1ford@exxonmobil.com>,Mark Kovac . <yesno 1 @gci.net>, gspfoff <gspfòff@aurorapower~com>, Gregg Nady <gregg.nady@shell..com>, Fred Steece <fted.steece@state.sd..us>, rcrotty <rcrotty@ch2m.com>, jejones. <jejones@aurorapower.com>, dapa . <dapa@alaska~net>, jroderick <jrQderick~gci.net>,eyancy <eyancy@seal;.tite~net>, "James M. Ruud"<james.m.ruud@co.nQc()phillips.com>" Brit Lively <~ap~aska@ak.net>, jab" <jaþ@di1r.state.ak..us>, Kurt E Olson, <kurt _ olson@legis.st~te.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <m,ark_hanley@anadarko.com>, 10ren_Ieman <loren_lemari@gov.state.ak.us>, Julie Houle ·<julie_houle@dnr.state.ak.us>, John WKatz <jwk~tz@ssó.org>, Suzan J Hil~ <suZan ~ hill@dec.state.ak.us>, tablerk <tablerk@unoca1.com>, Brady' <brady@aoga.org>, Brian Havelock <beh@<Inr.state.ak.us>, bpopp <bpopp@borollgh.kenaì.ak.us>, Jim ~te <jimwhite@satx.rr.com>, "John S.Haworth" <johnrs~haworth@exxo~obil.com>, Marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, nnclean ' . <nÍ1clean@pobox.alaska.net>, mþn 7200' <mkn17200@ao1.com>,· ~rian Gillespie <itbmg@uaa~a1aska.edu>, David L Boelens ·<dboelens@81lforapovyer.cotn> ~ Todd, Durkee <TDuR1Œ;E@KMd.com~, Gary Schultz <gary_schultz@dnr.~tai.e.ak.us>, Wayne ~ancier <RANC~R@petrq-canada.ca>, Bill Miller <Bill_ Miller@XtoaIasJça.çOID>, 'BrandQnGagnon <bgagnon@brenalaw.corp>, Paul Winslow <pmwinslow@forestoitcom>, ÇJarry Catron <catrongr@~p.com>, Sharmaine Copeland <copelasv@qp..èom>, Sµzänne Allexaµ.. <s~lexan@helnienergy.com>, Kristin Dirks <kristin _ dìrkS@dn.!.S~á~è.àl<:~~> ,.' ·~~~~1I Zeman . <kjzeman@marathonoil.com>, John Tower <lohn.Tower@eia-OOe.gov>, ~ill. Fowler . <Bill_ F owler@anadarko.COM> , Vaughn Swartz <vaughn.swartZ@rbccm.com.>, ·Scott Cranswick 10f2 9/29/2004 1: 10 PM Public Notices <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP .com> Pleàse find the attacheÇl Notice and Attachment for the proposed amendment of underground. injection orders and the Public Notice Happy Valley #10. Jody Colombie : . .' . .' . .. ... . ..r Content-Type: application/msword !Mechanlçallntegrlty proposaI..doc ¡ .... ..' .... ...... b 6.4 : Content-EncodlDg: . ase Content"Type: application/msword Mechanicallntegrity of Wells N·otice.doc Content-Enêodil1g: base64 Content-Type: application/msword HappyVal.leyl0 _ HearingNotice.doc : Content~Encoding:hase64 . . ' ~ , ,.' "0" ..."" . ._ ~__ ..,.......,., ._~'.,'..~.,'..,.,~.,~. .,...... .,."..,,~ ..... .._..,'._" ..~...,,,,,_,, "", "._..,,,..,, ."_,,, ,. . ".,_", _."..".. ,".... .._, .". ._.. .._ , ,,,,,"".... _. ..,..". _,. .,. w,"" _ ,". .".. ..<.. .-...0"·'--...·......... .~-,".~- ..~_..'_........"..~_. ....,~._....._~"._,_..,.'. . '.' w'.. .. '... ,,,., _,_ '. . ......,. ....._~ 2 of 2 9/29/2004 1: 10 PM Public Notice ) ) Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state;ak.us> ~~~'~:i~eq,..??~:p.~~.0~...1~:55 :26 T~;:..J~gé3;J:@~l~~f{ajip~~.çpq1.; Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Content-Type: applie ation/msword Mechanical Integrity of Wells Notice.doc Content-Encoding: base64 Content-Type: application/msword Ad Order form. doc Content-Encoding: base64 1 of 1 9/29/2004 1: 10 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy. Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 /tJalled I{//((f~ David McCaleb I HS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio. TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught. Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street. #1202 Boise, 10 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Watdsmith 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 Sofdotna, 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 0 ) - Well Integrity... ) ~ubject:. [Fwd: Re: '?ºnsistèntWorg~n~:J?t h1Jectio~Ordê!S "WêllIQtegrity(;Reviseq)] }from: J.ohn N..' orrnan<johnnOtm..'. an.@.., ..ad.'.·.min~.'...s.tate..~.éÙ(~µS,? . ,','.': ","'",,- . '. " " " '" , . Pi~·~e:F~i,pl<?ct~9?;EI:9~:~6-0~O?. .,.'...,..,.'...'........'. ........ .'.' ........ ...... .... ...... ........'.. .'" . ....... 1'9;·J(J~y:[·Ç()t9!1Ìþie:~g4y2º<?~~tµ1Jie@ªctm~~:;;st~t~~~.ljs*' , 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 l1lintz@law.state.ak.us> To:j 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 <jim regg@admin.state.ak.us> 8/25/2004 3:15:06 PM »> Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...] to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions 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 <:i im regg(ã)admin.state.ak.us> 8/17/2004 4:33 :52 PM »> Please delete previous version (emaiI 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 Sf. 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 lof2 10/2/20044:07 PM [Fwd: Rè: Consistent Wording for Injectio. clers - Well Integrity... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see 01025 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 "Admi.nistrative 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 NOffi1an@?admin.state.us> Commissioner , Alaska Oil & Gas Conservation Commission 20f2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection 0. ) - Well Integrity... ) ~~b~ect: [Fwd: Re: ..ConsistentW ordingforlrtjectipn Orcien; ~ ..WellI11tégrity(l{evi'sed)] from: John Norman <jpoo2nQrInan@admiIl.stélte.ak:.1,ls> Date: Fri, 01 Oct 2004 11 :08:55 ~0800 Tº:£·,.·7qdy··j'·,êª~q~~ì¥·"·'1J;~ø~-&cQî~~iDlþie@:~~iþ.~t~t~..åk~~,s;'..,·.·,'..···.···'·'··" 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 norman@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 redlines on the second document attached. »> James Regg <jim reg,g@Jadmin.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 Sf. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for 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 DIG 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions lof2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injectio. jers - Well Integrity ... - adopts "Administrative Actions" title (earlier rules used "Administrative Relier'); - 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. Norman <John Norman@admin.state.us> Commissioner , Alaska Oil & Gas Conservation Commission Content-Type: applicationlmsword Injection Order language - questions.doc Content-Encoding: base64 Content-Type: applicationlmsword Injection Orders language edits.doc Content-Encoding: base64 20f2 10/2/20044:07 PM J ) 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 Integ;rity 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 !_njcction \velI), and before returnin.g a well to service folh.1\vin.g afK.:>f a workover affecting mechanical integrity, and at kast OHce every 11 year~; \vhile actively injecting. For ~;!urry lft.tt"Ction \VeIls, the tubing/casing annulus tnust bè t2:st~d for mechanical integrity èvery 2 years. Unless an alternate 11lèat1S is approved by the COlnn1ission. tl1echanical integrity lTIUst be demonstrated by a tubin.g pressure test using a +he Mfl2-surface pressure of must bc 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, thatfF\-H5t-show3. stabilizing pressure that doesand Inay not change more than 10.94r- percent during a 30 minute period. --AH-y alterl1at~f dCll10flStrating lllochanìcal intGg:rÍ:ty must be approved by the COtTI.il1ission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as othenvise provided in this rule, +Ihe tubing, casing and packer of an injection well must EIßmonstrate il1aintain integrity during operation.\Vhenever any pressure conlmunication, leakage or lack of injection zone isolation is indicated by inkction rate, operating pressure obscn"ation, test, survey, log. or other evidence. t+he operator mttSt-shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval:. whenever any pressure COlTIInUnication, kakage or lack of injection zone isolation is indicated by injection rate. operating pressure observation, test, survey. or log. The operator shall shut in the well if so directed by the COlTI111Ïssion. The operator shall shut in the well \vithout a\vaitin.g a response from the Comlnission if continued operation \vould be unsafe or would threaten conta111ination of freshwaterlf there is no threat to freslnvater, injection tnay continue until the C0l111nission requires the \vell to be shut in or ~~ecured. Until corrective action is successfully cornplcted, 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. Administrati ve Actions Unless notice and public hearing is otherwise required, the Commission may administratively vvaive 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 Langu lor Injectors]] ) St.1~Ject:. [Fwd:.Re: [Fwd: AOGCCProposed WI Language for Injectors]] ~r()tn:.Winton.Aubert ·<'^'~t()n__aubert@admÍ1l.state.alcus> i~~~~~~~~~~~~l~~~_i~t~f~,~~· This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngeIHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven; Engel, Harry Ri Cismoski, Doug Ai NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.; Reeves, Donald Fi 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 còmments, 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* ** lof3 10/28/2004 11 :09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI La. .Lge for Injectors]] returnj.ng a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall * immediately*_** notify the Commission" This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates. II 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 don't 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 Ei McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of Wells Notice.doc» 2 of3 10/28/2004 11 :09 AM #7 metro@gci.net METRO COURT REPORTING 745 W. 4th Ave., Suite 425, Anchorage 99501 907.276.3876 ~~V~ D~7~ c...'t) ,~': J2~ ~, * * * * SARAH PALIN, Chairperson DAN SEAMOUNT COMMISSIONERS: ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING ) ) ) ) ) OF PROCEEDINGS Anchorage, Alaska December 4, 2003 9:00 o'clock a.m. TRANSCRIPT ORION POOL RULES AND AREA INJECTION ORDER HEARING. Page 1 PUBLIC HEARING DECEMBER 4, 2003 ) J In re: 17 18 19 20 21 22 23 24 )25 r 12 13 14 15 16 ,11 ) 8 9 10 5 6 7 4 1 2 3 I ) AOGCC ORlOR POOL RULES HRG AOGCC ORIOR POOL RULES HRG ) )1 2 3 TABLE OF CONTENTS 4 OPENING REMARKS BY CHAIR PALIN ..... . . . . . .. Page 3 TESTIMONY OF JONATHAN WILLIAMS. . . . . . . . . . . . . Page 6 END OF PROCEEDINGS. .. . . .. .. . .. .... .. Page 16 5 6 7 8 ***** 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) 1 PROCEEDINGS 2 (On record 9:03 a.m.) 3 CHAIR PALIN: Good morning. This hearing is now called 4 to order. It's Thursday, December 4,2003, at 9:03 a.m. We're 5 in our AOGCC offices at 333 West Seventh here in Anchorage. 6 I'm Sarah Palin. With me is Commissioner Dan Seamount. We may 7 see our Assistant Attorney General Rob Mintz present himself 8 today. I don't know where he is right now. He may be here. 9 We also have Laura Ferro here of Metro Court Reporting 10 transcribing these proceedings, and if you wish to have a copy 11 of the transcript, please get a hold of Metro if you so desire. 12 These proceedings are held in accordance with 20 AAC 13 25.540, regulations governing public hearings, and these 14 hearings will be recorded. This hearing concerns Orion pool 15 rules and an area injection order. BP requested this, these 16 pool rules, and an area injection order on 10/l/03. We'll be 17 establishing pool rules for the Orion oil pool within the 18 Prudhoe Bay Field, and approve an area injection order 19 authorizing enhanced oil recovery operations in that pool. 20 Anchorage Daily News published this notice on 10120/03. IfBP 21 has any additions to your written application, which we have 22 received, of course, the order of proceedings today will 23 include the applicant presenting testimony. 24 All persons wishing to testify will be sworn in. And f5 if you wish to give expert testimony, we'll ask that you PUBLIC HEARING DECEMBER 4, 2003 Page 2 Page 4 1 provide your qualifications, and the Commission will decide if 2 your testimony will be accepted. Audience members who may have 3 questions may submit those in writing through our Commission 4 staff. Jane and Winton are here, and Jody's here. You can 5 give your questions to those three and they'll forward them on 6 to us. Oral statements may be made after the testimony is 7 presented. And there's a sign-up sheet, and I do have that in 8 front of me. I believe you have all signed in and indicated if 9 you wish to testify or make any statements, and it looks like 10 just Jonathan Williams will be testifying this morning. Thus 11 far no comments have been received, no request for a hearing 12 was received by the public. And, Jody, I assume since I talked 13 to you last, no comments still have been received? Thank you. 14 Okay. Then we will go forward with Jonathan's 15 testimony. And for the record -- and Bob Crandall's here also 16 from the staff. For the record, when Jonathan comes forward to 17 the mike, ifhe can state his name for the record and we will 18 swear him in. So, Jonathan, you're already here. 19 MR. WILLIAMS: Yeah. 20 CHAIR PALIN: Thank you. Okay. I'm going to swear you 21 in first so if you could raise your right hand? 22 (Oath administered) 23 MR. WILLIAMS: I do. 24 CHAIR PALIN: Thank you. And if you wish to be 25 considered an expert witness, please tell us what your Page 3 Page 5 1 qualifications are. 2 MR. WILLIAMS: Okay. My name is Jonathan Williams. My 3 surname is spelled W-i-l-I-i-a-m-s. I'm a geologist with BP 4 Exploration Alaska, Inc. I received a Master's of Engineering 5 degree in Civil Engineering from the University of Nottingham, 6 England, and a Master of Science degree in Geology from Oregon 7 State University in 2000. I've been employed by BP in Alaska 8 as a geologist for the last three years. I've worked on the 9 Prudhoe Bay Ivishak reservoir, and the Polaris and Orion 10 Schrader Bluff reservoirs. I joined the GPB Satellites team in 11 2003. I would like to be acknowledged today as an expert 12 witness as a Geologist. 13 CHAIR PALIN: Any objection? 14 COMMISSIONER SEAMOUNT: No objections at all. 15 CHAIR PALIN: All right. You're an expert. You're 16 accepted. So please proceed, Mr. Williams, with your 17 testimony. 18 MR. WILLIAMS: On behalf of the Prudhoe Bay Unit 19 working interest owners, we have prepared the Orion Pools and 20 Area Injection Order Application submitted on October 6, 2003. 21 During the public notice period, we have answered all questions 22 asked by the Commission, and provided supplements where 23 infonnation as requested. A technical review of the 24 application with representatives of the Commission was 25 conducted on October 28, 2003. Prior to submission, we held 2 (Pages 2 to 5) 907.276.3876 METRO COURT REPORTING 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net AOGCC ORIOR POOL RULES HRG ) ) PUBLIC HEARING DECEMBER 4, 2003 I ) . 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 Page 6 several meetings with the Commission to discuss important aspects of the application. We ask that the Commission enter its entirety this application to the record with two corrections as follows: On page 33, under reservoir pressure measurements, the common datum elevation should be 4,400 feet TVD subsea. On page 38, under area injection operations, we request authorization for water injection only. At this time we do not request authorization for a miscible gas injection pilot to enhance recovery from the Orion Pool. CHAIR PALIN: Okay. We'll note that. Do you have any questions? COMMISSIONER SEAMOUNT: I have no questions. I'd like to thank you for a very complete and excellent write-up application. CHAIR PALIN: Thank you, guys. Thanks. Okay. I don't have any questions either. Anybody else from BP with anything else that you would like to add? Okay. We thank you guys then. Mr. Williams, thank you for your testimony. And hearing no questions from my fellow commissioner and I have none also, then we can adjourn this very quick proceeding. And thank you guys for your time for coming over very much, and hopefully we'll get this out soon. Okay. Thank you guys. We'll go off record. We're adjourned. (Off record 9:08 a.m.) Page 7 CERTIFICATE SUPERIOR COURT )ss. STATE OF ALASKA 4 5 I, Laura C. Ferro, Notary Public in and for the State of Alaska, do hereby certify: 6 THAT the annexed and foregoing pages numbered 2 through 7 7 contain a full, true and correct transcript of the Public Hearing before the Alaska Oil and Gas Conservation Commission, 8 taken by and transcribed by Laura C. Ferro: 9 THAT the Transcript has been prepared at the request of the Alaska Oil and Gas Conservation Commission, 333 West 10 Seventh Avenue, Anchorage, Alaska, 11 DATED at Anchorage, Alaska this 9th day of December, 2003. 12 SIGNED AND CERTIFIED TO BY: 13 14 15 16 Laura C. Ferro Notary in and for Alaska My Commission Expires: 6/03/05 17 18 19 20 21 22 23 24 i5 3 (Pages 6 to 7) 907.276.3876 METRO COURT REPORTING 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net AOGCC ORIOR POOL RULES HRG ) A AAC3:12 accepted 4:2 5: 16 acknowledged 5: 11 add 6:18 additions 3 :21 adjourn 6:21 adjourned 6:24 administered 4:22 Alaska 1:1,7 5:4,77:3 7:5,7,9,10,11,16 Anchorage 1:7 3:5,20 7:10,11 annexed 7: 6 answered 5 :21 Anybody 6:17 AOGCC 3:5 applicant 3 :23 application 3:21 5:20 5:246:2,4,15 approve 3:18 area 1:4 3: 15,16,18 5:206:7 asked 5 :22 aspects 6:2 Assistant 3:7 '\assume 4: 12 / Attorney 3:7 Audience 4:2 authorization 6:8,9 authorizing 3: 19 Avenue 7:10 a.m 1:8 3:2,46:25 B Bay 3:185:9,18 behalf 5: 18 believe 4: 8 Bluff 5: 10 Bob 4:15 BP 3:15,205:3,76:17 C C 3:1 7:1,1,5,8,15 called 3:3 CERTIFIED 7:12 certify 7: 5 CHAIR 2:3 3:34:20,24 5:13,156:11,16 Chairperson 1: 11 Civil 5:5 comes 4: 16 coming 6:22 )comme.nt~ 4: 11,13 I ComnusslOn 1: 1 4: 1,3 907.276.3876 ') 5:22,246: 1,3 7:7,9 7:16 commissioner 3: 6 5: 14 6: 13,20 COMMISSIONERS 1: 10. . common 6:6 complete 6: 14 concerns 3: 14 conducted 5 :25 Conservation 1:1 7:7,9 considered 4:25 contain 7:7 CONTENTS 2: 1 copy 3: 10 correct 7:7 corrections 6:4 course 3:22 Court 3:97:2 Crandall's 4: 15 D D3:1 Daily 3 :20 Dan 1:12 3:6 DATED 7:11 datum 6:6 day 7: 11 December 1:73:47:11 decide 4: 1 degree 5:5,6 desire 3: 11 discuss 6: 1 E E3:1,17:1,1 either 6: 17 elevation 6:6 employed 5:7 Engineering 5 :4,5 England 5:6 enhance 6: 10 enhanced 3: 19 enter 6:3 entirety 6:3 establishing 3: 17 excellent 6: 14 expert 3:25 4:25 5: 11 5:15 Expires 7: 16 Exploration 5:4 F F7:1 far 4: 11 feet 6:6 fellow 6:20 Ferro 3:97:5,8,15 Field 3:18 first 4:21 follows 6:4 foregoing 7:6 forward 4:5,14,16 front 4:8 . full 7:7 G G3:1 gas 1: 1 6:9 7:7,9 General 3:7 geologist 5:3,8,12 Geology 5:6 give 3:25 4:5 go 4: 146:24 going 4:20 Good 3:3 governing 3: 13 GPB 5:10 guys 6: 16, 19,22,23 H hand 4:21 hearing 1:2,4 3:3,14 4: 11 6:207:7 hearings 3: 13, 14 held 3: 12 5:25 hold 3: 11 hopefully 6:23 I important 6: 1 include 3 :23 indicated 4:8 information 5 :23 injection 1:4 3:15,16 3:185:206:7,8,9 interest 5:19 Ivishak 5:9 J Jane 4:4 Jody4:12 Jody's 4:4 joined 5: 10 Jonathan 2:4 4:10,16 4:185:2 Jonathan's 4: 14 K know 3:8 ~ I) L Laura 3:97:5,8,15 looks 4:9 M Master 5: 6 Master's 5:4 measurements 6:5 meetings 6: 1 members 4:2 Metro 3:9,11 mike 4:17 Mintz 3:7 miscible 6:9 morning 3:34: 10 N N3:1 name 4:17 5:2 News 3:20 Notary 7:5,16 note 6: 11 notice 3 :20 5 :21 Nottingham 5: 5 numbered 7:6 o 03:1 Oath 4:22 objection 5:13 objections 5: 14 October 5:20,25 offices 3:5 oil 1:1 3:17,197:7,9 Okay 4:14,20 5:26:11 6:16,18,23 OPENING 2:3 operations 3: 19 6:7 Oral 4:6 order 1:43:4,15,16,18 3:22 5:20 Oregon 5:6 Orion 1:43:14,175:9 5:196:10 owners 5:19 o'clock 1:8 P P 3:1 page 2:3,4,5 6:5,7 pages 7:6 Palin 1: 11 2:3 3:3,6 4:20,245:13,156:11 6:16 period 5 :21 METRO COURT REPORTING 745 W. 4th Ave., Suite 425, Anchorage 99501 PUBLIC HEARING DECEMBER 4, 2003 Page 8 persons 3 :24 pilot 6:9 please 3:11 4:25 5:16 Polaris 5:9 pool 1:4 3:14,16,17,17 3:196:10 Pools 5:19 prepared 5: 19 7:9 present 3:7 presented 4:7 presenting 3:23 pressure 6:5 Prior 5 :25 proceed 5: 16 proceeding 6:21 proceedings 1:62:5 3: 10, 12,22 provide 4: 1 provided 5:22 Prudhoe 3:185:9,18 public 1:2 3:13 4:12 5:21 7:5,7 published 3 :20 Q qualifications 4:1 5:1 questions 4:3,5 5:21 6:12,13,17,20 quick 6:21 R R3:17:1 raise 4:21 received 3:224:11,12 4: 13 5:4 record 3:24:15,16,17 6:4,24,25 recorded 3: 14 recovery 3: 19 6: 10 regulations 3: 13 REMARKS 2:3 Reporting 3:9 representatives 5 :24 request 4: 11 6:7,97:9 requested 3:15 5:23 reservoir 5:9 6:5 reservoirs 5: 10 review 5:23 right 3:84:21 5:15 Rob 3:7 rules 1:4 3:15,16,17 S S 3:1 Sarah 1:11 3:6 metro@gci.net AOGCC ORlOR POOL RULES HRG l1atellites 5: 10 Schrader 5: 10 Science 5: 6 Seamount 1:12 3:6 5:146:13 see 3:7 Seventh 3:57:10 sheet 4:7 signed 4:8 7: 12 sign-up 4:7 soon 6:23 spelled 5: 3 ss 7:3 staff 4:4, 16 state 4:17 5:77:3,5 statements 4:6,9 submission 5 :25 submit 4:3 submitted 5 :20 subsea 6:6 SUPERIOR 7:2 supplements 5 :22 surname 5:3 swear 4: 18,20 sworn 3 :24 "~7:1,1 T TABLE 2:1 taken 7:8 talked 4: 12 team 5:10 technical 5:23 tell 4:25 testify 3:244:9 testifying 4: 1 0 testimony 2:43:23,25 4:2,6,155:176:19 thank 4: 13,20,24 6: 14 6: 16, 18, 19,22,23 Thanks 6: 16 three 4:5 5:8 Thursday 3:4 time 6:8,22 today 3:8,225:11 transcribed 7: 8 transcribing 3: 10 transcript 1:6 3: 11 7:7 7:9 true 7:7 TVD 6:6 two 6:4 ?Unit 5:18 U ) University 5:5,7 W water 6:8 West 3:5 7:9 we'll 3:16,25 6:11,23 6:24 We're 3:4 6:24 Williams 2:44:10,19 4:23 5:2,2,16,186:19 Winton 4:4 wish 3:10,254:9,24 wishing 3:24 witness 4:25 5: 12 worked 5: 8 working 5:19 write-up 6: 14 writing 4:3 written 3 :21 W-i-l-I-i-a-m-s 5:3 y Yeah 4:19 years 5:8 1 10/1/033: 16 10/20/033:20 162:5 2 2 7:6 203: 12 20005:7 2003 1:7 3:45:11,20,25 7:11 25.5403: 13 285:25 3 3 2:3 336:5 3333:5 7:9 386:7 4 4 1:73:4 4,400 6:6 6 62:4 5:20 6/03/05 7: 16 7 77:7 ) PUBLIC HEARING DECEMBER 4, 2003 Page 9 9 9th 7: 11 9:00 1:8 9:033:2,4 9:08 6:25 907.276.3876 METRO COURT REPORTING 745 W. 4th Ave., Suite 425, Anchorage 99501 metro@gci.net #6 l, STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION ORION POOL RULES AND AREA INJECTION ORDER HEARING December 4, 2003 AT 9:00 am NAME - AFFILIATION (PLEASE PRINT) .1) (}'/lv!t1/ S' (' i l11 6.i'~ J'" ryd 611 ::r K~. 111\ +<; ç, \~. ~-\~~ K'¡ --, ~ .~ ~ ..J Ö N l\ 1 f.f AtJ W ¡ L LI AM 5 ~ff' - r " ,..··e .. . h~/"/" Seo.\t- Ceo \e- '( K' 'd~ ..I\IJ \jrV . '(\:~. \Jø<;OYl \Meeting Sign-In ADDRESS/PHONE NUMBER TESTIFY (Yes or No) / ] Lf t.'f11 it(/! (¡,() /;11-/ L J.) ¡( . 11 IV (Htl~/k: ,1 t! d ç~t¡- S7l/! a. 3 Of.{ ~I, gfZ-U)lf-lATH 'Pe it} Â;s fl.·l.Â µ 0 <66::; ¡ ·J¡·)f~·'eA,- D~. ,f\v\c.l. 5't.;ll-"J'ð{(,LJ t-Jd) '''3D ~.f\lERE lli'..LLf) AtvtrtðR4C,E 1 6¿lt-S"g54- 'Yt.S .f beo. !::.Õ-I:j~ ù/ ,! IJ ¡J"k 4} i.. J'6 ¿¡-.J ç ,1-.1- /L~ ,/ . Hcçí( 6 '2...2.2.. P<'-. ^"~ .Î-\K. <1iSb¿tS 35'7·2.. 773 A/ð ?t; 1'3 iVf ~(1 ~ (1. d ,w, 99? r1 ,~l.¡5:-S5S -5 NO #5 [Fwd: Addition to the Administrative Record for Orion Pool PI lies & Ala] ), } } Subject: [Fwd: Addition to the Administrative Record for Orion Pool Rules & AIO] Date: Thu, 20 Nov 2003 08:32:33 -0900 From: Robert Crandall <Bob _ Crandall@admin.state.ak. us> Organization: DOA-AOGCC To: "Aubert, Winton" <winton_ aubert@admin.state.ak.us>, "Palin, Sarah" <sarahjJalin@admin.state.ak.us>, "Seamount, Dan" <dan _ seamount@admin.state.ak.us>, "Williamson, Mary" <j ane _ williamson@admin.state.ak.us>, "Colombie, Jody" <jody _ colombie@admin.state.ak.us> Jody¡ Can you add a paper copy of this e-mail to the Orion applications? AII¡ This will help with two points we should include in the Orion CO and AIO. 1) The Schrader Bluff in the west end of PBU has a huge eor target and maximizing ultimate recovery may require more than waterflood. We should include a progress report on viscous oil recovery in the annual surveillance report. 2) The Orion Pool areal and vertical extent may be revised in the future. Let me know if you'd like to discuss. BC Subject: RE: Addition to the Administrative Record for Orion Pool Rules & AIO Date: Wed, 19 Nov 2003 14:55:23 -0900 From: "Huff, Brian D" <HuffBD@BP.com> To: Robert Crandall <Bob _ Crandall@admin.state.ak.us>, "Seamount, Dan" <dan _seamount@admin.state.ak.us> cc: "Gustafson, Gary A" <GustafGA@BP.com>, "Williams, Jonathan D" <WilliJD@BP.com>, "Huff, Brian D" <HuffBD@BP.com> Bob, we concur with the clarification you propose below. It is reasonable to assume that we will: 1)continue to study EOR techniques for viscous oil, and 2) continue to evaluate other wells relative to their bearing on the Orion Oil pool¡ and update AOGCC on both. The only edit I would make to what you have below is to change horizontal extent to aerial extent. Please feel free to use the text below to update the administrative record for the proposed Orion Pool. Let me know if this matter requires anything further from the Orion Team. -----Original Message----- From: Robert Crandall [mailto:Bob Crandall@admin.state.ak.us] Sent: Wednesday, November 19, 2003 10:29 AM To: Huff, Brian D¡ Seamount, Dan Subject: Addition to the Administrative Record for Orion Pool Rules & AIO 1 of 2 11/20/20033:05 PM [Fwd: Addition to the Administrative Record for Orion Pool Rules & AIO] "", l '^ j Brian; As we discussed on the phone this morning, there are several issues related to the proposed Orion development that we feel should be addressed by the subject orders and are not explicitly addressed in the applications you have submitted. Your response to this e-mail can be used to update the administrative record for these orders. Both of the points that need clarification relate to the extent of the proposed Orion development. The vertical extent of the pool is not a function of the distribution of the resourèe, but rather the distribution of oil BP anticipates will be most amenable to waterflooding. Within the proposed development area, an as yet undetermined amount of resource will not be producable with the proposed waterflood. BP will address this issue by studying EOR techniques for viscous oil. Depending on the success of this work, at some point in the future the vertical extent of the pool may be revised to include oil excluded from the initial development plan. The AOGCC will periodically review (perhaps annually) the progress of your work with viscous oil EOR techniques. The horizontal extent of the proposed Orion Pool is to some degree a function of well control. As development in the Western PBU proceeds, numerous wells to either the Saddlerochit or the Kuparuk Fm. will be drilled. These wells should be routinely evaluated for oil bearing equivalents of the Orion Pool. With your concurrence on these two points, we will update the administrative record for the proposed Orion Pool. Bob Crandall 2of2 11/20/20033:05 PM #4 October 29,2003 ) BP E:.. ,ìration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Orion Pool Rules And Area Injection Application - Supplemental Exhibits Dear Commissioners: We have reviewed your October 20, 2003 correspondence regarding confidentiality of eight exhibits in our Orion Pool Rules and Area Injection Order Application. Attached are three (3) copies of the non-confidential version of the following exhibits. Please supplement the record accordingly to include these materials in the Orion Pool Rules and Area Injection Order Application: Exhibit 1-2A Exhibit 1-3A Exhibit 1-4A Exhibit 1-12A Exhibit 1-13A Exhibit 11-1A Exhibit 11-4A Exhibit 11-7 A Orion Pool/Injection Area and Proposed Orion Participating Area Outline Orion Pool/Injection Area Type Log Well V-201 Orion Pool/Injection Area Top Schrader Bluff OA Structure Map Orion Pool/Injection Area Thickness of Mudstone Between Top Na Sand and Base MC Sand Orion Pool/Injection Area Nand 0 Sand Reservoir Compartment Map Orion Model Reservoir Property Ranges Orion MDT Summary Table Orion Waterflood Rate Forecast Please contact myself (564-5110), or Jonathan Williams (564-5854) if you have any questions or comments regarding this response. Sincerely, -1J - ~,;J/f 'ó/z~Ä' Brian Huff Satellite Resource Manager Greater Prudhoe Bay Attachments ;J' '''), E"~ (..... E ~. .,. . 1'. ..~ "'." ~-"' -- f ~ ~ f' ~ 'I. '" ",I _~" I C_ t.,) OCT 2 9 20D3 Ä,\2ska Oil & Gas Cons. Cornmissic:i¡ .ðnchor2g~: cc: Francis Sommer (BPXA) Dan Kruse (CPAI) Ken Griffin (Forest Oil) Gary Gustafson (BPXA) Mark Vela (ExxonMobil) G.P. Forsthoff (Chevron) Jonathan Williams (BPXA) 5$3:1300 56>.000 .@0~ S?;.~1Iì! 5GQ ,\1M OOfh!!@!ð >e0.\l1Iì! GQ5.~~e 1Iì!0.~OO Gli5.ß0Ø .a,MII .¡¡¡.eee &-J~f0-Ø-i , , r .. 001/1 njecti on 0 £..èS;~gfiØ .- - ".9"5.~"\! rea and 15 ¡'I J3 16 15 Propos .. rlon ""'III"'" Particip .. I Ing rea S~ggLiilia - line 23 24 'QY '" '\ s.OO¡.\!\!~ - 26 25 30 28- 25 S. MQ .~oo - \ 32 32 36 31 "/ ' ( " Sf' ~i ti]'(j@ - - ..¡r¡..e\!~ \~ \ 5 . ! '3 6 5 I .. ¡¡,9?Q.ß!!(I - \- ''¡I'!\! .\1$0 .¡~ " 12 7 13 e Q 12 s.oos.iI!OO - 5.9$.,0110 .- 13 18 17 16 - 11':: Injection Wen ~ G.MI.illOO T11 N, ~1 , - S'¡!S6,\!OO In a 2'1 19 20 21 22 23 24 ¡;,IJf.¡.~æ - . ¡ ~ 26 25 27 25 30 29 28 27 S.%I.\I@íI - - 5.9&\1,099 , , I _,\I"" MS,íi. ~'1j¡."¡¡¡¡ S?~~jjèi 5\11.1i"" ~5.¡¡iII< $9.a~JiÜ ss.s~JiU t!liß.liœ ~u.,,¡¡¡¡ ßHihliU ßj5:~iìI@$ aZIi~ßJtJi Exhibit 1-2A M III - ~cu :aGJ ..t:L...,..- ><<(0 Ws;:C\I o I 11I- ......, - (J- GJ II~ So o 0 ..J . > -:.¡:; U) . ...... U) cD et:: et:: (!) -. "'" '"' ='"' Ib o ..- ..- s;: 0 ..- ~ fI .a ~ c 11- Z Z Z 0 L. fI.a 1:1 m m m o 0 0 0 uoqe U.UO.::l JTlI g JapeJUJS 4V ... m o 0 ¡ ì. 12^Ja¡UI 11/10011 UOIJ .... ~,9'1¡1~" - wen 12 7 8 ¡"aoó,¡¡011 - Production Wen 13 18 17 16 Wen &.961.0011 - &SI!.600 OO&.afll! ,QOO S'''HÍ:11iJi@ ;;¡¡..@oo Sl!S,JilOO S90,.00 GfJ@.iOO OO&,Q$@ &j"QOO ~~,jJ0'J; - ¡ . - S,!)!jjt,.illi> !>,.$g¡¡, ~ild ~- 16 15 14 13 ¡;~ a~u .$Ü - 23 2'1 '¡.ßG. ,GM - 25 ',$Gij,il1iii 36 3J ~h irl~ ,!10tt - ¡;, 5 2<J 19 zø Z! 22 23 25 3'1 29 Z8 27 26 25 S,$ói..11iii - .6u~¡¡øa ¡¡¡S.UII ß1m.¡¡OO 5€i¡¡,JiU 5íI~.n. 5'1i!.Q!iI.I 5'1!1.¡a¡)ß 5ili.U' , 5115.<100 5.0.,. 595..00 (1j13.U" ß!l5..U Orio ool/lnjection rea p chrader ure ap Contour := 20 feet Exhibit I G2ij,¡jíilØ S~996~J:1¡H t" S~,>;¡gS*iiØ 1<] 16 J 5 J 3 S'" OO.0~ iiQm - 23 2'1 &.9!1;;.00\1 25 13,91301903 - 38 3J ,,$7..00\1 '- \) 5 S$!j'Nh~ - r 8 ¡;,0\I..Dæ - J3 J8 J7 16 ..911&.00\1 ~ 2LJ 21 22 23 19 20 \¡,~5.m- 25 30 26 28 27 28 ~?-9G0-ti0íJ -- ~ 5U.DIi!õ , S:?&~ tiS: S8S~Ø:ti .~'1~*tili ,,00._ 5.~.1iJI1i ¡¡Sß._ .;¡¡¡,IiI!~ 595.Øü Jlii.'¡¡¡' ßl5"ilii i!ôß.¡;¡¡§ o,¡~.oom Orio ool/lnjection rea Thickness ud one en ~ a Sand and Sand Me Me top Contour Interval = 2 feet Interval Permeability Exhibit 1-1 s.ooa.¡¡iIU - 36 :n Overlay on Top OA Structure. C.I. == 20' ¡¡.$7',~iII! - Orion Production Well _IV..2011 6 5 Orion 5~''1I,.ß~ .." Prudhoe - j2 7 8 '.iII!'.ii!iII! - WIi.ioo Sß!i.¡¡iII! ,~oo , - S'1St@0!a ;;e¡ ,000 saSt\Ï00 .. t </" I;S0,0oo . , .oo:ø,aOI! &a,,000 a!0,@~a 61 £.~oo '¡a,ijß0 5~gg.~ß. 6~9S;"IiØ ¡.- - ~,,~,J;1"0$ JIì j3 16 15 2'3 2'1 ¡"OO',ijill! - 25 13 j8 17 j6 ..!JSI.eill! 2'1 19 20 2! 22 23 Jz,.~,~,tJ1ØM 25 30 29 28 27 26 25 F ... ¡',ª",¡¡00 SßJ.J.iü , ~'1:hi.1:ü 61..11"" ßZ~,'¡¡¡¡ j ..s.U¡¡ -'- ¡¡¡¡..lIiiI'! _.ßBiI S?¡"IiH SIIi.ílU 5$i:,.¡;. '9S,II"" ~a,,¡JHMa dHhíiß!ii rio ool/Injection a N and Sand eservoir o ap me Exhibit 1-1 Exhibit II-4A - Orion MDT Summary Table SAND UNIT OA OBa OBb-d BP, psia 1324-1743 1134-1872 1207-2045 Rs, scf/stb 167-194 131-324 117-354 API Gravity 15.6-18.3 15.2-22.5 17.8-22.8 Viscosity, cp 41.2-118.2 7.4-132 6.1-62 .~ FVF, rblstb 1.048-1.086 1.154 (1sample only) 1 .121-1 . 165 ~ Average Property Ranges SAND LAYERS NET FEET POROSITY PERMEABILITY md OA 9 14.4 - 29 0.271 - 0.3 163 -194 OBa 7 14.4 - 27.5 0.283 -0.302 181 -236 OBd 8 24 - 37.8 0.277 -0.282 57 - 89 Exhibit II-1A - Orion Model Reservoir Property Ranges Exhibit II-7A - Orion Waterflood Rate Forecast 120 Orion Oil Production 100 Orion Water Production "!'" "C ..c - &I WI Orion Water Injection E '" 80 G) ...... cu 0:: L.. 60 ~ G) 'I!Þ - ...... " cu ~ ~ "C 40 ., c cu ...... ...... 0 20· o 2000 . . . . . 2005 2010 2020 2025 2015 Year . 2030 #3 STATE OF ALASKA ADVERTISING ORDER SEE. BOTTOM FOR INVOICE ADDRESS _) NOTICE TO PUBLISHER ...) INVOIC T BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO.~TIFIED AFFIDAVI OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-02414010 F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT Jody Colombie PHONE DATE OF A.O. October 16, 2003 PCN (907) 793 -1')71 DATES ADVERTISEMENT REQUIRED: ¿ Anchorage Daily News POBox 149001 Anchorage, AK 99514 October 20, 2003 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal o Display Advertisement to be published was e-mailed o Classified DOther (Specify) SEE ATTACHED .:.':.......:.:':":'.: ".:"." ::... .' ",:.":":"" :.' SENßJ~V,..,)~IC.'i.:,1?l~:~~'P~IÇÄTE AOGCC, 333 W. 7th Ave., Suite 100 " '/', . ,. >TO' Anchorage, AK 99501 NUMBER AMOUNT DATE TOTAL OF PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS REF TYPE 1 VEN 2 ARD 3 4 FIN AMOUNT 02910 SY CC PGM LC ACCT FY NMR D15T LlQ 04 02140100 73540 2 3 4 REQUISITIONED.BY: " . /"ì r', (~ ( ":Ä- ( ß.<O~~J^, /' /___ ) _.-- "- o IfS19N_ APp'ROVA~: . , (f}/"vvcdt- ,,0. ,£A-l-c?"' (j- 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM -) . ." Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Orion Oil Pool, Prudhoe Bay Field Area Injection Order and Pool Rules BP Exploration (Alaska), Inc Alaska, Inc. by application dated October 6, 2003, 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 Orion Oil Pool, Prudhoe Bay Field, on the North Slope of Alaska. The Commission has set a public hearing on this application for December 4, 2003 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West ih 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 November 6, 2003. 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 November 24,2003. ~~~ Randy Ruedrich Commissioner Published Date: October 20, 2003 ADN AO 02414010 RE: Ad Order .) ) " Subject: RE: Ad Order Date: Thu, 16 Oct 2003 17:22:34 -0800 From: "legalads" <legalads@adn.com> To: "Jody Colombie" <jody _ colombie@admin.state.ak.us> Hi Jody: Following is the confirmation information on your legal notice. Please let me know if you have any questions or need any further information. Account Number: STOF 0330 Legal Ad Number: 978425 Publication Date(s): October 20,2003 Your Reference or PO#: AO-02414010 Cost of Legal Notice: $107.16 Additional Charges Web Link: E-Mail Link: Bolding: Total Cost to Place Legal Notice: $107.16 Add Will Appear on www.adn.com: XXXX Add Will Not Appear on www.adn.com: Thank You, Kim Kirby Anchorage Daily News Legal Classified Representative E-Mail: legalads@adn.com Phone: (907) 257-4296 Fax: (907) 279-8170 ---------- From: Jody Colombie Sent: Thursday, October 16, 20032:51 PM To: legalads Subject: Ad Order «File: Orion Pool AIO.doc»«File: Ad Order form.doc»«File: jody colombie.vcf» Please publish on Monday October 20,2003. lady ... _oÇ-1 10/20/2003 8:25 AM ) tChOrage Daily News Affidavit of Publication ~) 10/11/2QQ3 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 978425 10 /20/2003 02414010 STOF0330 $107.16 $107.16 $0.00 $0.00 $0.00 $0.00 $0.00 $107.16 STATE OF ALASKA THIRD JUDICIAL DISTRICT Kimberly Kirby, 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 time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on 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. ::!~~:to¿f! date: /ryá¢q Notice of Public Hearing STATE OF ALASKA Alaska Oi.1 and .Gas Conservation Com m issi on Re:OrionOil pool, PnJdhoe Bay'Field Arealniection Order and Pool Rules ~P ~xploration(Alaska), IncAlaska, Inc. byap- I pllcat.lO.n d~ted October 6, 2003, has applied for an arealnlectlonorder and pool rules.under20AAC 25.460 and 20 AAC 25.5?0, respectively, to. govern d~velopment of the anon on Pool, Prudhoe Bay Field, on the North Slope of.Alask'l' Th~Co.mmission has set"a,públi~ hearin90n this appllcatl~n for December 4, 2003 at 9:00 am at the Alaska. 011 and Gas Conservation Commission at ~~~o~est 7th,'Avenue, Suite 100, Anchorage,Alaska In.addition, <? person may sU'bmitwritten com- mentsregardlng th)s application to the Alaska 011 and Gas Co.nservatlon Commission at 333 West 7th Avenue, SUite 100, Anchorage, Alaska 99501. . Writ- ten comments must be received no later than 4' 30 pm on November 6, 2003. . .' . If YOU ar~ a per~o.n with a disability who may need asp"ç'l] m()d;f,cot;"r. ;" order to comment or to atte~d I r.o; ["Jr.!!!: r·e'," '"9 pleasecòntact Jody ColombIe at 793-1221 before November 24, 2003. RandYR.uedrich Commissioner ADN AO 02414010 Publish: October 20, 2003· Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska 'a ~ MY CüMMISSI EXPlRE\ ~?q5... \l\U (((({It: \\\ ....l,..\ES ^I',r,.-: ~\ ott~. .:~;.: ~-t ~ ~ ~·~OTA~··~"S ~.- --. ~.. =. §~. : ~ÞuBL\C = § ;:::..,% . .~ """' ..... ~ ..--£;. ~ :::,.~ .:"\ ~ . .~Of ~ .' .øD,,:y ;¿ . . . . . ._~,,~:\'\ //. ¡:~p'~\\\ STATE OF ALASKA ADVERTISING ORDER ::~g¡~,:~9t.;r~~,:F<~':\~Y~JÇE;¡¡~I:5¡~~'~~~::·'·:\:"¡ >.. ~ NOTICE TO PUBLISHER . \ INVOIC . 'T BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO.~IFIED AFFIDAV F PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-02414010 >:. : ;~. ,r.:"· '"."",: .., F AOGCC 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1221 AGENCY CONTACT DATE OF A.O. R o M T o Anchorage Daily News POBox 149001 Anchorage, AK 99514 Jody Colombie October 16, ?003 PHONE PCN (907) 793 -1 ??1 DATES ADVERTISEMENT REQUIRED: October 20, 2003 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2003, and thereafter for _ consecutive days, the last publication appearing on the _ day of ,2003, 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 2003, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER Public Notice J J Subject: Public Notice Date: Thu, 16 Oct 2003 14:55:39 -0800 From: Jody Colombie <jody _ colombie@admin.state.akus> Organization: Alaska Oil and Gas Conservation Commission BCC: Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, John Tanigawa <JohnT@EvergreenGas.com>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj@unoca1.com>, ecolaw <ecolaw@trustees.org>, roseragsdale .<roseragsdale@gci.net>, trmjrl <trmjrl@ao1.com>, jbriddle <jbriddle@marathonoi1.com>, rockhill <rockhill@aoga.org>, shaneg <shaneg@evergreengas.com>, rosew <rosew@evergreengas.com>, j darlington <j darlington@forestoi1.com>, nelson <nelson@gci.net>, cboddy <cboddy@usibelli.com>, "markdalton" <markdalton@hdrinc.com>, "shannon.donnelly" <shannon.donnelly@conocophillips.com>, "mark p. worcester" <mark. p. worcester@conocophillips.com>, "jerry.c.dethlefs" <jerry.c.dethlefs@conocophillips.com>, bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.akus>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, burgin --, d <burgin _ d@niediak.com>, "charles.o'donnell" <charles.o'donnell@veco.com>, "Skillern, Randy L" <SkilleRL@BP.com>, "Dickey, Jeanne H" <DickeyJH@BP.com>, "Jones, Deborah J" <JonesD6@BP.com>, "Hyatt, Paul G" <hyattpg@BP.com>, "Rossberg, R Steven" <RossbeRS@BP.com>, "Shaw, Anne L (BP Alaska)" <ShawAL@BP.com>, "Kirchner, Joseph F" <KirchnJF@BP.com>, "Pospisil, Gordon" <PospisG@BP.com>, "Sommer, Francis S" <SommerFS@BP.com>, "Schultz, Mikel" <Mike1.Schultz@BP.com>, "Jenkins, David P" <JenkinDP@BP.com>, "Glover, Nick WI! <GloverNW@BP.com>, "Kleppin, Daryl J" <KleppiDE@BP.com>, "Platt, Janet D" <PlattJD@BP.com>, "Jacobsen, Rosanne M" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, collins_mount <col1ins _ mount@revenue.state.ak.us>, mckay <mckay@gci.net>, "barb ara. f. fullmer" <b arb ara. f. fullmer@conocophillips.com>, eyancy <eyancy@seal-tite.net>, bocastwf <bocastwf@bp.com>, cowo <cowo@chevrontexaco.com>, ajiii88 <ajiii88@hotmai1.com>, doug_schultze <doug_ schultze@xtoenergy.com>, "hank.alford" <hank.alford@exxonmobi1.com>, yesno 1 <yesno 1 @gci.net>, gspfoff <gspfoff@aurorapower.com>, "gregg.nady" <gregg.nady@shell.com>, "fred. steece" <fred. steece@state.sd. us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancey <eyancey@seal-tite.net>, "j ames.m.ruud" <j ames.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <jah@dnr.state.akus>, Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buonoje@bp.com>, "Emeka. C.Ezeaku" <Emeka. C.Ezeaku@spdc.shel1.com>, mark _ hanley <mark_ hanley@anadarko.com>, loren _leman <loren_Ieman@gov.state.ak.us>, Harry R Bader <harry_bader@dnr.state.ak.us>, julie_houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, lof2 10/16/20032:55 PM Public Notice J ~ Suzan J Hill <suzan _ hill@dec.state.ak.us>, tablerk <tablerk@unoca1.com>, brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenaLak.us>, jimwhite <jimwhite@satx.rr.com>, Stephanie_Ross <Stephanie _Ross@thomson.com>, "john.s.haworth" <john.s.haworth@exxonmobi1.com>, marty <marty@usalaska.biz> Orion Oil Pool, Prudhoe Bay Field, Area Injection Order and Pool Rules. ! Name: Orion_Pool_AIO.doc .,~ ~~~,:n,::~, ,~,I~~~O,~t~~~~;;~,;;;~~~~I,~"~~~~::t~:~=:=:~d)! Jody Colombie <jody colombieca!.admin.state.ak.us> 20f2 10/16/20032:55 PM Public Notice J Subject: Public Notice Date: Thu, 16 Oct 2003 14:54:24 -0800 From: Jody Colombie <jody _ colombie@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Nancy Norton <Nancy _Norton@admin.state.ak.us> Please publish on the web site. Jody ~ r:::::::::::::::::::::::::::::::::::::::::::::::::;::::::::::::::':.::::::.::::::::::::::::::.:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::.:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::=::::::::::::::::::::::::::::::::::::::::::':::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: Jody Colombie <jody colombie(â1admin.state.ak.us> 1 of 1 10/16/2003 2:55 p~ Ad Order J ~ Subject: Ad Order Date: Thu, 16 Oct 2003 14:51 :47 -0800 From: Jody Colombie <jody _ colombie@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Legal Ads Anchorage Daily News <legalads@adn.com> Please publish on Monday October 20, 2003. Jody ; ""::"' .' . :' Name: Orion_Pool_A~O.doc. . ',1 ¡ ~Onon Pool AIO.doc,! Type: WINWORD FIle (apphcatlonlmsword)¡' , ,. """"·",,,·,,····,·,·,·,···,,,,,,,,,·,,·"w' ,.': ~,~~.?«~~~~:,''''~~,~,~.?,~.".,.''w,'''".,',.,...,.,..,'·'··'···'·""""""'''''''''''·'',m·""···,·,,,,·w·,''·''''·,.",,,,.,.,..,J ."., I Name: Ad Order form:doc .. . I . ffigAd Order form.doc Type: WINWORD FIle (apphcatlOnlmsword), '.,......,.."., ",,,,",,«,,,,,,,,,,,,,,,,,,,,,,,",,,,,,,,,,,,,,,,",,.!,:,~<J?:,~~,~~~,~,: ,?~,~"~~,~,....".,' ,. ,..."",,,,,,,..,.,.,,,,,., ,..,,,,,,,,,,,,,,,,,.,,.,,,,,,,,,,,, "",,,," Jody Colombie <jody colombie~admin.state.ak.us> 1 of 1 10/16/2003 2:56 PIv SO Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SO 57702 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 Penny Vadla 399 Riverview Ave Soldotna, AK 99669-7714 J 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 W. Allen Huckabay ConocoPhillips Petroleum Company Offshore West Africa Exploration 323 Knipp Forest Street Houston, TX 77079-1175 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Trustees for Alaska 1026 West 4th Ave., Ste 201 Anchorage, AK 99501-1980 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 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 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-'6247 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 J North Slope Borough PO Box 69 Barrow, AK 99723 ...,) Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 #2 bp } ) 0··,'·'.:,········,··'.·:,"'·· :'~'~~' ~~r, ~ ." ;,", ..,i1f& tr BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 October 1, 2003 DELIVERED BY HAND Commissioners RE Alaska Oil and Gas Conservation Commission Ce'''ED 333 West 7th Avenue, Suite 100 0 Anchorage, AK 99501 CT 062003 RE: Orion Pool Rules and Area Injection Order ApPlicatio~OII&~Cðns.~ .""chOtlge IUIUIUP Dear Commissioners: Enclosed for your review and action is the Prudhoe Bay Unit (PBU) Working Interest Owners' application for Pool Rules and Area Injection Order for the Orion reservoir, submitted pursuant to 20 MC 25.520 and 20 MC 25.460. BP Exploration (Alaska) Inc.(BPXA), as Orion Operator and Unit Operator, respectfully requests that the Commission schedule a hearing as early as possible on this application. Please maintain as confidential those certain exhibits attached and labeled "CONFIDENTIAL" in accord with AS 31.05.035 and 20 MC 25.537. Please contact myself (564-5110) or Jonathan Williams at 564-5854 if you have any questions or need additional information. Sincerely, -6 -.__, [\), Brian Huff Satellite Resource Manager Greater Prudhoe Bay ~41 Attachments Cc: Francis Sommer, BPXA Marc Vela, ExxonMobil Dan Kruse, CPAI G.P. Forsthoff, Chevron Ken Griffin, Forest Oil Jonathan Williams, BPXA Gary Gustafson, BPXA f Orion Pool Rules and Area Injection Order Ap( ion (' October 6, 2003 ( Orion Pool Rules and Area Injection Order Application ( October 6, 2003 ( Orion Pool Rules and Area Injection Orde 'Iication October 6, 2003 Table of Contents I. Geo logy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 4 Introduction....................................................................................................................................... 4 Stratigraphy............................................................................................................. ..........................5 Schrader Bluff Formation - Geologic Structure..............................................................................l 0 Fluid Contacts .................................................................................................... ............................. 12 Oil-Water Contacts............................................................................................ .............................. 12 Net Pay and Pool Limits .......... .... ......................... .......................................................................... 13 II. Reservoir Description and Development Planning ................. 15 Rock and Fluid Properties ................ ..... ............................................................................. ............. 15 Hydrocarbons in Place............................................... ............................................ ......................... 17 Reservoir Performance.................................................................................................................... 18 Development Planning.................................................................................................................... 19 Development Options...................................................................................................................... 20 Development Plan ........... ... ..... ... ..... .............. ............. ... ........ ................... ............. ..... ........ ... ..... .....21 Reservoir Management Strategy.. .... .... ................. ........................... ............. ........ ........ ..................23 III. F acili ti es ................................................................................ 25 General Overview........................................................................................................................... 25 Pad Facilities and Operations.......................................................................................................... 26 Gathering Center............................................................................................................................. 28 IV . Well Operations .................................................................... 29 Existing Wells .. ............. ..... ... ....... ... ......... .... ......... ... ............... ........... ........... ... ..... ........ ......... .........29 2 Orion Pool Rules and Area Injection Order A~' cion (' October 6, 2003 (' Drilling and Well Design... ................... ................................... .......................................................29 Reservoir Surveillance Program... ............................ ........................................... .................. .........33 ~. J>r()clIlc;ti()Il ~11()c;(lti()Il............................................................. :3~ ~I. ~re(l IIlj ec;ti()Il Oper(lti()IlS ..................................................... :3 8 . Plat of Project Area............................... ............................................. .............................................38 Operators/Surface Owners.............................................................................................................. 38' Description of Operation................................................................................................................. 38" Pool Information.............................................................................................. ......... ............. ......... 39 Geologic Information............................................................................. ........................... ..... ......... 39 Lo g Information.............................................................................................................................. 39 Injection Well Casing Information......................................................................................... ... ...... 39 {r' \ Injection Fluids................................................................................................................................ 40 Injection Pressures .......................................................................................................................... 41 Fracture Information..... .......................................................................... ........................................ 41 F ormati on Water Quality ................................................................................................................ 42 Freshwater Strata.................................................................................................................. ...........42 Hydrocarbon Recovery ................................................................................................................... 42 Mechanical Integrity of Wells......................................................................................................... 42 ~II. J>r()p()secl Ori()Il J>()()l RIlles.................................................. 44 ~III. J>r()p()secl ~re(l IIljec;ti()Il Orcler ........................................... 51 IX. List ()f Exhibits .....................................................................55 ( 3 Orion Pool Rules and Area Injection Order ~ication October 6, 2003 I. Geology Introduction The proposed Orion Pool Rules area is located within the Prudhoe Bay Unit (PBU) on Alaska's North Slope, as illustrated in Exhibit 1-1. The Orion Pool overlies the Prudhoe Oil Pool (also referred to herein as the "Prudhoe Pool" or "Prudhoe") in the vicinity of PBU L, V, Wand Z Pads and overlies the Borealis Oil Pool (also referred to herein as the "Borealis Pool" or "Borealis") in the vicinity of PBU L and V Pads. The Kuparuk State No.1, drilled in 1968, was the first well to penetrate and log hydrocarbons in the Orion Pool. In 1998, the Northwest Eileen 2-01 well was drilled. Sidewall cores in that well confirmed hydrocarbons in the Schrader Bluff sands. Exhibit 1-2 shows the location of the Orion Pool area. The boundaries of the Orion Pool Rules area coincide with the boundaries of the proposed Orion Participating Area (OPA). The Orion Pool hydrocarbon accumulation is bounded by faults on the up-dip west and south sides and by closure down-dip into the regional aquifer on the down-dip east side. To the north, the Orion Pool hydrocarbon accumulation is interpreted to extend to the boundary of the Schrader Bluff Oil Pool. To the northeast, although seismic evidence suggests the hydrocarbon accumulation may extend beyond the Prudhoe Bay Unit boundary, this has not yet been confirmed. The Orion Pool is comprised of the ten distinct Nand 0 sand intervals of the Schrader Bluff formation. Hereafter, applicants request the Commission define the Orion Oil Pool (also referred to herein as the "Orion Pool" or siInply "Orion") as including all of the hydrocarbon bearing sands within the described area that correlate with the Schrader Bluff Nand 0 sand intervals detailed on the V -201 type log depicted in Exhibit 1-3. As shown on the Schrader Bluff OA structure map in Confidential Exhibit 1-4, the Orion structure crests in the northwest Orion Pool region (3980 feet TVDSS at the Schrader Bluff OA mapping horizon) and trends down dip to the east through faulting and regional dip. North-south, east-west, and northwest-southeast trending faults subdivide the Orion Pool into discrete fault blocks. Fluid 4 Orion Pool Rules and Area Injection Order A~' lÌon ( October 6, 2003 ; f isolation between several fault blocks is interpreted by log data from adjacent fault-separated wells that show water structurally higher than oil in the same sands on opposites sides of faults. Sealing faults are predicted in the Orion Pool based on the prevalent low net to gross reservoir lithologies. Commerciality of the Orion Pool was confirmed in April 2002 through the fracture-stimulated completion and production of the Schrader Bluff 0 sands in well V-201. Well V-202 was the first Orion high-angle development well at V-Pad and began production from the OBd sand interval in June 2002. Additional laterals will be added to well V-202 in the OBa and OA sands to make it a high-angle trilateral producer. Stratigraphy Exhibit 1-3 shows the open-hole wireline log character of the Schrader Bluff 0 and N sands in a type log from the V -201 well. This type log illustrates the vertical stratigraphic extent of the Orion Pool that comprises the 0 and N sands. In the V - 201 well, the top of the Orion Pool occurs at 4,126 feet TVDSS (4,549 feet MD) and the base occurs at 4,650 feet TVDSS (5,106 feet MD). ( As shown in Exhibit 1-3, the Orion 0 and N sands are further subdivided into seven 0 sands, and three N sands. A general description of the thickness and character for each of the Orion sands follows. A detailed description of the rock properties associated with individual sands is given in Section II. In general, the 0 and N sand intervals are present across the entire Orion Pool area and, as a package, thin slightly from southwest to northeast across the Orion 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. 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. ( 5 Orion Pool Rules and Area Injection Ordet .ication October 6, 2003 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 Orion, form the basal confining unit of the Orion 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 4 to 12 foot thick muddy siltstone layer. Exhibit 1-12 is a thickness map of this mudstone. Mapping using 3D seismic and well control shows no areas in the Orion Pool area where this mudstone is not present between the Mc and N sands. o Sands The Schrader Bluff 0 sand interval is the primary development target in the Orion Pool and is subdivided into seven separate reservoir horizons, from deepest to shallowest - the OBf, OBe, OBd, OBc, OBb, OBa, and OA. OBe and OBf Sands The OBf and OBe intervals, each ranging in thickness from 35 to 55 feet, comprise the basal Orion Pool's 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, 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. OBd Sands The OBd sand interval in the Orion Pool ranges between 55 and 70 feet thick and forms one of the primary Orion reservoir target horizons. OBd sands are thickest in the Z-Pad area ranging up to 64 feet net sand in well KUPST -01, and thin gradually northward to between 5 and 30 feet net sand in the proposed I-Pad area. The OBd interval grades upward, from a basal muddy siltstone into low 6 { Orion Pool Rules and Area Injection Order Api .ion ( October 6. 2003 ( quality laminated and bioturbated reservoir sands that gradually clean upward. A 10 to 30 foot thick blocky to fining upward sand unit caps the OBd interval over most of the Orion Pool area. The basal 5 to 10 feet of this blocky sand interval forms the highest quality OBd reservoir unit, but thins to the north of L-Pad. Reservoir quality OBd sands are unconsolidated and almost entirely very fine to fine-grained. Initial production rates from a single horizontal leg of well V -202 drilled in this sand with oil-based mud exceeded 7000 bopd. OBc Sands The OBc sand interval, ranging between 45 and 60 feet thick, comprises a minor Orion reservoir unit with reservoir quality sands present mainly in the V-Pad and Z-Pad areas. The OBc interval coarsens upward from basal muddy siltstones to a low net to gross silty sand, with a moderate net to gross laminated to layered very fine-grained sand at the top of the unit. Up to 20 net feet of OBc sand is mapped in the V-Pad areas, while at L-Pad net sand thickness is typically 5 to 15 feet. To date, OBc sands have not been perforated in any Orion Pool well. ( OBb Sands The OBb sand interval, also a minor Orion Pool reservoir unit, has a thickness range of between 45 and 60 feet with between 15 and 25 feet of net sand present in the V-Pad area. Regionally, the OBb interval typically contains less than 20 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 interval, and higher net to gross than the underlying OBc interval. Individual clean OBb sand layers, observed in core from Polaris wells, are typically less than one foot thick and are separated by silts and muds of comparable or greater thickness than the sands. There are occasional blocky sands greater than one foot thick. OBb sands in the V -201 well were hydraulically fractured and produce commingled with the overlying OBa sands. OBa Sands The OBa sand interval within the Orion Pool, with a 25 to 55 foot thickness range, cleans gradually upward from a basal siltstone into interbedded thin sands and mudstones to an upper cross-laminated ( 7 Orion Pool Rules and Area Injection Orde. lication October 6, 2003 sand unit. Two regionally extensive erosion/scour surfaces are identified in the OBa sand, one in the middle of the unit and one at 10 to 15 feet from the top of the unit. Above each erosion/scour surface are bioturbated, blocky to fining upward high permeability sands (1000+ md.) that constitute a primary development target of the Orion Pool. The high permeability sand interval above the lower erosion/scour surface thins from southeast to northwest across the Orion region and is 5 to 10 feet thick. The upper high permeability sand is 5 to 15 feet thick, caps the OBa unit and thins to the southeast across the Orion Pool such that it is missing in the Z-Pad area. Hydraulically fractured OBa sands were produced in well V - 201. OA Sands The OA sand interval comprises a 10 to 25 foot thick basal silty mudstone that coarsens upward, gradually or abruptly, into stacked sets of cleaning upward reservoir sand units. As a package, the OA interval is 45 to 80 feet thick, with net sand thickness of 10 to 35 feet. OA sands show a dominantly coarsening upward log profile with the highest quality sands present in the upper third of the OA gross interval. 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. Similar to the OBd and OBa intervals, the high quality sand sits above a regionally extensive erosion/scour surface and is heavily bioturbated. The high quality OA sand is less than 5 feet thick at Z-Pad, and thickens to 15 to 20 feet in the L-Pad and V-Pad areas. The high quality reservoir sand caps the OA interval and is truncated abruptly at the top OA sand contact. Basal and middle OA sands are generally poor to non-reservoir in quality. OA sands have been completed in the hydraulically fractured V -201 well. N Sands The Schrader Bluff N sand interval overlies the Schrader Bluff 0 sand interval and ranges between 140 and 180 feet thick in the Orion Pool area. Orion 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 8 Orion Pool Rules and Area Injection Order A~· .ion (" October 6, 2003 sand interval form an important regional vertical reservoir barrier which segregates lighter, higher quality, oil in the main development horizon 0 sands at Orion and Milne Point (D, B, and A sands at West Sak) from heavy oil and extensive wet sands in the overlying N and M sands (Lower U gnu sands at West Sak). Nc Sands The Nc interval, ranging from 75 to 105 feet thick, is dominated by mudstone and muddy siltstone in the Orion Pool area and contains thin interbedded reservoir quality sands only in the upper 15 to 30 feet of the interval. Nc net sand is typically less than 15 feet thick across the Orion Pool area. Individual sands are generally unconsolidated and interbedded with thicker non-reservoir muddy siltstones. Nc sands are very fine grained, laminated and moderately to highly bioturbated. Nc sands have not been perforated or tested in an Orion Pool well. Nb Sands The Nb sand interval ranges from 30 to 50 feet thick in the Orion Pool and comprises the primary N ( sand interval completion target. Nb net sand character is highly variable in the Orion Pool area with net sand thicknesses ranging from 10 to 40 feet. The best Nb reservoir quality occurs near L-Pad where blocky to fining upward sand with very high permeability (1000+ md.) occurs above an erosional surface. This high quality interval is some of the coarsest grained sand in the Orion Pool, but it is not laterally extensive and it may be a channelized deposit. Other channel deposits in the Nb sand may be present near V-Pad, Z-Pad, and the possible new I-Pad, but existing penetrations do not delineate these features. Outside of the known channel sands, Nb sands are less than 10 feet thick and are interbedded with similar or greater thicknesses of mud and silt. No Nb sand completions have been made in the Orion Pool area. Na Sands The Na sand interval is a thin, very 10w net-to-gross interval, which lies at the top of the N sand section and is consistently about 25 feet thick across the Orion Pool. Na reservoir sands are generally very fine-grained, laminated, and bioturbated. Individual Na sands are two to four feet thick, exhibit ( 9 Orion Pool Rules and Area Injection Orde¡ tication October 6, 2003 a spikey log character, and are interbedded with thicker non-reservoir siltstones. No Na sand tests or completions have been made in an Orion Pool well due to poor reservoir characteristics in this area. Schrader Bluff Formation - Geologic Structure Exhibit 1-4 is a structure map on the top of the Schrader Bluff OA sand in the Orion Pool area, with a contour interval of 20 feet. Although the Schrader Bluff interval generally dips eastward and northeastward at one to four degrees in the western portion of the Prudhoe Bay Unit, it is broken up into a series of distinct fault blocks in the Orion Pool, as indicated by 3D seismic data and by well penetrations. The structural character at the Schrader Bluff level in the Orion Pool and vicinity 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, provides the predominate structural fabric of the Orion Pool. Faults with this orientation occur throughout Orion, and form the boundaries of the Inajor structural blocks in the area. The southwestern linlÍt of the Orion Pool is formed by a complex fault system of northwest-southeast striking faults that link up and intersect with north-south faults to form a series of fault traps. The northwest-southeast faults more often are downthrown to the southwest, but can also be downthrown to the northeast. North-South Fault Trend North-South striking faults, downthrown to the west and east are the second most dominant fault system in the Orion Pool. These faults have throws of up to 100 feet. Some of the north-south trending faults can be demonstrated to have relatively recent movement, with offsets as shallow as 1000 feet tvdss in the permafrost. East-West Fault Trend East-West faults are the least common fault trend in the Orion area. East-west faults form part of the complex fault system that forms the reservoir trap on the southwestern side of Orion. 10 Orion Pool Rules and Area Injection Order Apf .ion ( October 6, 2003 ( Reservoir Compartments Elements of each of the major area fault systems were used to subdivide the Orion Pool into reservoir compartments for development planning purposes. As additional wells are drilled and production data gathered, the reservoir compartment picture could change. The location and areal extent of these reservoir compartments is marked by the polygon boundaries shown in Confidential Exhibit 1-13. Each compartment was defined along seismically mapped fault trends and is 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 Orion and from analog studies, which show a high probability of clay smear seals forming along faults in the Orion low net to gross reservoirs. Polygon nomenclature and boundary character is summarized below. Reservoir POIY20n Boundary Character Polygon 1 Fault bounded on the southwest, southeast and northwest sides. On the northeast side of the polygon, reservoir sands dip to the northeast into the aquifer. Fault bounded on the west, northwest, south sides. On the northeast side of the polygon, reservoir sands dip to the northeast into the aquifer. Polygon is fault bounded on all sides. Wells in the down- dip southeast portion of polygon are wet. Polygon is fault bounded all sides, extent of filling unknown on down-dip east side. Fault bounded on northeast, west, northwest, and southwest side. Down-dip east side of block is bound by dip into aquifer. Fault bounded on west, southwest, and east side. North- south fault on east side of polygon has up to 200' of throw, and separates Orion from Polaris. Dip within fault block to northeast, with two well penetrations in the aquifer. Polygon 4 is downthrown to Polygon 1 by a northwest- southeast fault with up to 180' of throw. Polygon 4 is a complexly faulted graben that is fault bounded on all sides. Polygon lA Polygon 2 Polygon2A Polygon 3 Polygon 3A Polygon 4 ( 11 Orion Pool Rules and Area Injection Orde ,Ii cation October 6, 2003 Polygon 5 Polygon 5 is fault bounded on all sides. Dip within polygon is to the east; wet wells in down-dip east side of block define OWC. Polygon 6 Fault bounded on all sides, with complex internal faulting indicated by seismic. No well penetrations in polygon 6 inside PBU. However, down-dip penetrations of fault block in MPU show presence of hydrocarbons. Fluid Contacts Confidential Exhibits 1-6 through 1-11 show the depths of interpreted Oil/Water Contacts (OWCs) in the Nand 0 sands on cross-sections across the Orion Pool. Nand 0 sand OWCs are in general poorly defined due to the lack of well control in down structure areas. No Gas/Oil Contacts (GOCs) have been logged in any Orion sand nor is the presence of free gas in Orion Pool intervals predicted from oil PVT test results. Each sand in the Orion Nand 0 interval is assumed to be vertically isolated from overlying and underlying sands by low net-to-gross, non-reservoir, muddy siltstones and is assumed to have a different associated OWC depth. Oil-Down-To (ODT) limits and Water-Up-To (WUT) limits constrain Orion Pool area oil column heights. The best defined reservoir compartments are at L-Pad and V -Pad where oil column heights range between 150 and 310 vertical feet. Oil-Water contacts have only been logged in three Orion Pool area wells: KUPST-Ol (OBa and OBd sands); L-I01 (Nb sand); and NWEILEEN-l (OA and Nb sands). 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 Orion Pool. Oil-Water Contacts Orion Nand 0 sand OWCs were interpreted for each sand using one of the following methods as most appropriate to that situation: 1) at the midpoint between the deepest Oil-Down-To (OOT) levels logged in upstructure wells and the down-dip structural spill point (defined at fault tips), 2) at the midpoint between the updip ODT levels and down-dip Water-Op-To (WUT) levels, or 3) at the midpoint between fault leak points (defined at fault intersections) and the down-dip structural spill 12 Orion Pool Rules and Area Injection Order APt ion ( October 6, 2003 { point. Based on the described methodology, the Nand 0 sand expected case oil column heights across the Orion Pool range between 0 feet (Nb-Polygon lA) and 433 feet (Oa-Polygon 3). Orion area Nand 0 sand OWC depth uncertainties between the minimum possible and maximum possible OWC cases average 190 vertical feet per reservoir unit sand. The wide range in OWC depth uncertainty is due to the lack of down-dip penetrations in the majority of the reservoir polygons. The best OWC depth definition occurs at L-Pad and V-Pad where there is a concentration of Borealis wells penetrating the Schrader Bluff Formation. At L-Pad and V-Pad the OWC depth uncertainty range is 17 vertical feet to 59 vertical feet. In the main target horizons OA, OBa, and OBd at L-Pad and V-Pad the average most likely oil column range is 156 vertical feet (Polygon 5) to 308 vertical feet (Polygon 2). Net Pay and Pool Limits ( The limits of the Orion Pool are defined up-dip by fault barriers and down-dip at the zero foot limits of Nand 0 sand most likely case net pay. Orion is bounded on the southwest by 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 north and northwest, the Orion Pool limit is established by the Prudhoe Bay Unit boundary, not by a geologically defined trap. Rule 2 of the Milne Point Field, Schrader Bluff Oil Pool Rules (CO 477) requires, consistent with the statewide rule (20 AAC 25.055), that wells be open no closer than 500 feet from the exterior boundary of the Milne Unit. A similar restriction is proposed for the Orion Oil Pool (see Proposed Rule 1 in Section VII.). These restrictions should be sufficient at this time to protect correlative rights and avoid waste. To the east, the Orion Pool limit is defined by the down-dip intersection of the top of the reservoir with the most likely case Nand 0 sand oil-water contact depths defined by structural spill points. The precise down-dip reservoir boundaries have not been verified with well control. Orion Pool net pay thicknesses were derived using a petrophysical log model developed for the Schrader Bluff Formation. Reservoir lithologies and porosities were based on a multi-log analysis calibrated to conventional core from Polaris wells S-200PB 1 and W -200PB 1, Milne well MPE-20, and West Sak wells lR-07 and WSI-01. Water saturations were calculated using the Waxman- 13 ( Orion Pool Rules and Area Injection Orde Ilication October 6, 2003 Smits model calibrated to the S-200PB 1 and lR-07 core samples. Depth trends were used to vary the resistivity of water and the relationship between porosity and permeability. Log-model cutoffs of 6 millidarcies permeability, 65% water saturation and 35% clay volume were used to define Orion net pay. Confidential Exhibits 1-14, and I-IS show the 0 and N sand composite net pays. Confidential Exhibit 1-14 is an Orion Pool composite-O-sand net-pay map showing the combined thickness and extent of the Orion area OA through OBf sand net pays. Confidential Exhibit 1-15 is an Orion Pool composite N sand net pay map showing the combined Na through Nc sand net pay thickness. Confidential Exhibits 1-16, and 1-17 show the 0 and N sand oil pore-foot thickness, respectively. Similar to the net pay maps in Confidential Exhibits 1-14 and I-IS, the 0 and N oil pore-foot thickness maps represent the combined oil pore-foot thickness for all of the 0 sands (Confidential Exhibit 1-16) and all of the N sands (Confidential Exhibit 1-17). 14 Orion Pool Rules and Area Injection Order AP~- .ion ( October 6, 2003 ( II. Reservoir Description and Development Planning Reservoir management and development scenarios for Orion have been evaluated using pattern and partial field reservoir simulation models. Low recovery estimates for primary depletion are influenced by low gas oil ratio (GOR), low initial reservoir pressure and viscous oil. The models have identified water flooding as a viable secondary recovery mechanism and are being used to optimize well spacing and pattern configurations. Orion development, as currently planned, will utilize the existing footprint of Pads L, V, Z and W, with minor modificatio~s, that were constructed by the Initial Participating Area ("IP A") and Borealis Owners to develop the Prudhoe Pool and the Borealis Pool. In addition, the Orion Owners are evaluating the possible construction of a new pad (I-Pad), located northwest of L-Pad for Orion development. Rock and Fluid Properties Porosity and Permeability (' Orion Pool rock properties were derived using conventional core data from two Polaris wells (S- 200PB1 and W-200PB1), two West Sak wells (WS1-01 and 1R-07), and one Milne well (MPE-20). Although Orion core was recently obtained in well V-Ill, rock properties from this well are not yet available. Rock properties were distributed across the Orion Pool area using log model transforms. Pending receipt of Orion core analysis results, log models derived from Polaris (which is considered to be a close analog for Orion) and other Schrader Bluff fields, have been used in reservoir simulation and analysis. Polaris porosity and permeability values were measured by routine core analysis (air permeability with KIinkenberg correction) of core plugs from S-200PB 1 and W- 200PB 1. Typical plug kv/kh values ranged from 0.001 to 1.0. Porosity and permeability for reservoir simulation were upscaled from the Orion static 3D geologic model (RMS), which is based on the Polaris log model (PLM). A 6 millidarcies permeability cut- off was utilized. Thick shale intervals representing the low net-to-gross, low-permeability shelf deposits between the reservoir sands were explicitly included in the layering, while the thinner shales within the sands were built into the vertical permeability during upscaling. (, 15 Orion Pool Rules and Area Injection Orde: lication October 6, 2003 Confidential Exhibit II-I shows typical ranges for porosity and horizontal permeability by zone that were used in the reservoir simulation. Water Saturation Water saturations have been characterized using mercury injection data from Polaris S-200PB 1 and W - 200PB 1 cores. Distribution of the data was characterized using a Leverett J -function to capture variations in water saturation with variations in porosity and permeability. The J -function data were then used to initialize the Orion reservoir models under capillary pressure equilibrium. Each interval was assumed to have a separate oil/water contact; the contacts were adjusted in the models to match observed water saturations from logs. Relative Permeability Relative permeability curves were based on unsteady state relative permeability experiments on S- 200PB 1 and W - 200PB 1 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. Confidential Exhibit II-2 shows the relative permeability curves used in the reservoir simulation. End point scaling has been used to adjust the curves for differences in initial water saturation. Initial Pressure and Temperature Initial reservoir pressure is taken from V-I 00, which had MDT samples over the range 3954' to 4623' TVDSS, at a datum depth of 4400' TVDSS, which has been chosen as the pressure datum depth for the Orion Pool. Average initial reservoir pressure is estimated to have been 1970 psi at 4400' TVDSS. Reservoir temperature is approximately 87° Fahrenheit at this datum. 16 Orion Pool Rules and Area Injection Order APl ,on (' October 6, 2003 ( Fluid PVT Data Three types of fluid data have been gathered at Orion - fluids extracted from sidewall core plugs, MDT samples and production samples from surface and downhole. Oil samples obtained from sidewall core plugs in seven wells, uSIng two different extraction methods (solvent extract, or retort), show API gravity variations of up to 10°. This range is not considered unusual, since extraction tends to under-predict API gravity, while retorting tends to over-predict. The uncertainty range means that these samples are of limited value for oil quality determination. A total of 23 PVT analyses have been performed on Orion oil samples and they are shown in Confidential Exhibit II-3. All of these samples were obtained from MDT's and 35% of the main sand/fault block reservoir units have been sampled to date. There appears to be a relationship between oil viscosity and the GOR of the samples. Confidential Exhibit 4 lists number of samples and property ranges for the MDT samples, at reservoir temperature and pressure, in each major sand. ( Geochemical (GC) analysis has been performed on 19 Orion oil samples and the coverage is shown in Confidential Exhibit 11-5. Results are interpreted to indicate that at least two oil charges are present in the reservoir, distinguished by the presence, or absence, of a GC "light end". The PVT properties used for reservoir simulation are derived from measured values in the area being studied. Where no measurements are available, a range of possible values is used, to quantify the impact on results. The current set of PVT tables is shown in Confidential Exhibit II-6. Hydrocarbons in Place A full-field reservoir simulation model for Orion has not been developed. Estimates of hydrocarbons in place for Orion 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 for the major sands are as follows: ( 17 Orion Pool Rules and Area Injection Orde )lication October 6, 2003 Sand OOIP (mmstb) OGIP (bscf) 0 845-1410 170-280 N 225-375 40-65 Total 1070-1785 210-345 The ranges in OOIP and OGIP are due primarily to uncertainty in individual fault block oil-water contacts, reservoir properties (<þ, So) and oil properties (Bo, Rs). The Orion Pool is under-saturated. Fluid saturations obtained from Orion partial field models have been compared to those calculated in the Orion log model and are in good agreement. Reservoir Performance Well Performance Two wells, V-20l and V-202 are producing from the Orion Pool. V-201 was drilled in early 2002 and put on production in April 2002. V-202 was drilled in May 2003 and put on production in July 2003. Both wells are currently producing under primary depletion. V -201 was the first producing well drilled in Orion. The well received two fracture stimulation treatments targeting the OA, OBa, OBb, and OBd, sands. The fracture stimulation was performed to decrease skin and control sand production by using a resin-coated proppant. V-20l production was initiated in April 2002 and initially produced 21.5 API oil at 1080 bopd, 400 GOR and 0% WC, on gas-lift. The low rate and low flowing wellhead temperature (330 F) caused problems with gas hydrates and the well was converted to jet pump. After 16 months, the well was producing 600 bopd, at 7% WC and 400 GOR, and had produced approximately 174mbo. V -202 is a 3000 foot single lateral, drilled with oil-base mud and completed with slotted liner in the OBd. The well was put on production in July 2003 and initially tested at 7100 bopd, 350 GOR (est.) and 0% WC. After 1 month the well was producing 2000 bopd at 0% WC and 1000 GOR, and has 18 Orion Pool Rules and Area Injection Order AP«" ¡on { ( October 6, 2003 ( produced over 100 mbo. V-202 had the highest initial rate of any Schrader Bluff viscous-oil development well drilled to date and appears to be relatively undamaged. Oil quality is excellent in the OBd at this location at 22.9 API. OA and OBa laterals are scheduled to be drilled and completed in this well in fourth quarter 2003. Aquifer Influx The aquifer to the east of Orion could provide limited 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 Conin!!1 Under-Runnin!! There are no indications of a free gas column in the Orion Pool; coning or under-run mechanisms are not anticipated. Development Planning Several reservoir models, using data from the Orion Pool, have been constructed to evaluate development options, investigate reservoir management strategies and generate rate profiles. Reservoir Model Construction Partial field models built from the Orion static model have grid blocks upscaled from approximately 95 x 95 x 1-2 feet to 150 x 150 x 3-7 feet. These are black-oil models, with a total of 25 active layers representing the net sand in the OA, OBa and OBd intervals. Shale and minor sand intervals (N, OBb and OBc) are gridded in the models, but properties are zeroed out at this time. Faults (internal and boundary) are included in all of the models and assumed to be sealing. Fine-grid models have been completed for about 60% of the field area to support development and appraisal drilling activity. { ... 19 Orion Pool Rules and Area Injection Orde ,Iication . October 6, 2003 Development Options Development options evaluated for the Orion 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 Orion Pool. The pnmary recovery mechanism was a combination of solution gas drive and reservoir compaction. Model results indicate that primary depletion would recover approximately 5-10% 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 the main development option for Orion. It is anticipated that overall field development will involve 40-80 injectors and 30-45 producers, depending upon the type of well designs utilized. In the major sands that will be developed with horizontal wells and full waterflood patterns, recovery may reach 20 to 25% of OOIP. The minor sands and N sands are likely to be produced through vertical fractured producers and horizontal laterals as reservoir quality permits. Waterflood patterns in these secondary layers may not be fully developed and recovery could be as low as 50/0 of OOIP in areas of poor rock quality and crude quality. These estimated waterflood recoveries are inclusive of primary recovery and assume 1.5 hydrocarbon-pore volumes injected (HCPVI). Oil production rate is estimated to peak at 30-50 mbd, with a maximum water injection rate of 100-125 mbd. The Orion waterflood oil and water production and water injection forecasts are shown in Exhibit 11-6. Enhanced Oil Recovery (EOR) Enhanced recovery techniques such as miscible-gas injection and water-alternating with miscible- gas injection are under evaluation. Preliminary evaluations indicate that EOR could yield incremental recovery from the Orion Pool. Milne Point Unit Schrader Bluff equation of state data 20 Orion Pool Rules and Area Injection Order AP~' .on ( October 6, 2003 ( have been reviewed in conjunction with slim tube simulation to assess potential EOR benefits at Orion. Upon completion of these and additional technical and economic evaluations, forward action plans will be determined. Injection wells are being engineered to accommodate the potential for enhanced oil recovery service. Horizontal Wells Favorable results have been obtained with horizontal multi-lateral (ML) wells in Orion and other pools within the Schrader Bluff Formation (Milne Point and West Sak) and the initial development plan for Orion is primarily based on ML wells. Simulation and development planning efforts sho~ that horizontal wells have the potential to enhance rate and recovery, while reducing development costs and minimizing facility expansion requirements. Horizontal well potential is currently being evaluated in the V -Pad area where the target is the three major sands - OA, OBa, and OBd. The V- 202 tri-lateral well (initially drilled as an OBd single-lateral) encountered approximately 2100 net feet of horizontal section and is currently on production. The V -202 well was drilled with oil-base mud to provide horizontal well productivity information, and appears to be relatively undamaged, ( based on initial rate. Injection well designs evaluated and employed to date in the Schrader Bluff formation pools within the PBU (Polaris and Orion) are vertical. Horizontal injection wells will be considered in the future, using single, multi-lateral and/or undulating wellbore profiles. Development Plan Reservoir simulation supports implementation of a waterflood in the Orion Pool. Initial development will take place in a phased manner, working from the areas of least reservoir/fluid risk towards the less well defined areas of the Pool, incorporating data gathering necessary to refine development plans. In this context, uncertainty includes structure/faulting (areas of poor-quality seismic and/or lack of early well control), oil quality (possible compartmentalization) and rock properties (areal and vertical variations in net-to-gross, porosity, and permeability). A phased development plan allows for evaluation of the Schrader Bluff in deeper Kuparuk and Ivishak ( 21 Orion Pool Rules and Area Injection Orde )Iication October 6, 2003 development wells prior to proceeding with development in each. field area. The Operator will determine 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 areas with good seismic quality and/or well control. Several water flood development options have been studied using the Orion reservoir simulation models. The results of those simulations provided criteria for spacing of wells and identifying the number of injectors necessary for adequate voidage replacement. Phase I development results will be used to validate development assumptions and refine Phase II and Phase III development plans. Phase I drilling in Orion is a combination of development and appraisal wells, designed to provide early production and injection well performance information, while evaluating the fluid and rock quality in previously untested areas of the field. V-Pad currently includes the V-201 and V-202 wells, which are currently on production and the V-I05 dual (with Borealis) water injector. Tri- lateral producers and vertical or multi-lateral injectors are under consideration. V-201 may be converted to water injection in the future. The central V -Pad line drive patterns will provide early data on flood performance and operation. L-Pad area development consists of drilling one tri-Iateral producer, L-200, in late 2003/early 2004, with immediate support available from the existing dual (with Borealis) water injector, L-117. 2004 drilling anticipates the addition of tri-Iateral producers and vertical or multi-lateral injectors. W -Pad currently has no Orion wells. Tri-Iateral producers and vertical or multi-lateral injectors are being considered to access Orion from W -Pad in 2004. These wells will test the southeast area of the field, which has relatively poor well control and no recent test data. Phase II Development Orion Phase II development is directed to completing development of locations that can be reached from existing gravel pads. Development of these areas will involve an additional 10-20 producers 22 Orion Pool Rules and Area Injection Order APt .ion (' October 6, 2003 ( and 20-40 injectors in the UV/Z Pad area plus approximately two producers and four to eight injectors in the W -Pad accessible area. Locations will be determined 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 areas with poor fault resolution, including higher-risk, structurally complex areas. Phase III Development Orion Phase III development will target areas in the northwest portion of the field that cannot be reached from L-Pad. The installation of I-Pad is being evaluated for this purpose. An estimated 1º -20 producers and 20-40 injectors will be required in this phase of the development. Well SpaCÎne: Initial production well spacing for development is nominally 160 acres with ML producer/vertical injectors. Due to faulting, the patterns are expected to be irregular and wells may be relatively 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 developing the Orion 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 field average 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 Orion reservoir management strategy is to operate the Pool in a manner that will maximize recovery consistent with good oil field engineering practices. Waterflood support and injection conformance are key to minimizing well decline rates. The reservoir management goal is to maintain a balanced voidage-replacement ratio. To accomplish this objective, reservoir ( 23 Orion Pool Rules and Area Injection Orde lication October 6, 2003 management will be a dynamic process. The initial strategy will be derived from reservoir-model studies and limited well-test information, and will utilize multiple packer assemblies to control water injection. Development well results and reservoir surveillance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. Reservoir management strategy for the Orion Pool will be evaluated throughout the life of the field. Reservoir Performance Conclusions Reservoir simulation supports implementation of a waterflood in the Orion Pool. Peak production rates are expected to be 30-50 mbd. After waterflooding commencement, peak injection rates will be 100-125 mbd. It is requested that the Operator be allowed to determine the field off-take rate based upon sound reservoir management and facility operational practices. Orion production performance can be divided into two aspects - reservoir delivery and well operability. Early production tests in the OBd sand at Polaris were significantly lower than expected, possibly due to formation daInage. Recent success in V-202 suggests drilling with oil- based mud and ensuring that the wellbore stays in the best quality rock can offset formation damage. Producer to injector ratios of 1: 1 to 1:3 will be needed to maintain reservoir pressure without high injection pressures in individual wells, depending on well types selected. Keeping Orion wells on line with a combination of low rates, cool production temperatures, presence of water, and lift-gas composition and temperature, has proven both challenging and costly. V-201 well operability, affected primarily by hydrate formation during gas-lift, was a problem when the well was first put on production. The V-201 well was switched to jet pump during the first month of production and has produced without problems for over 1 year. Artificial-lift will be provided using either artificial-lift gas, or with jet pumps using injection water as the power t1uid, or electrical submersible pumps (ESPs), or some combination as a function of the needs of the individual producer. 24 Orion Pool Rules and Area Injection Order Apf .ion ( October 6, 2003 ( III. Facilities General Overview Orion wells will be drilled from existing PBU drill sites (L-Pad, V-Pad, Z-Pad and W-Pad) and a possible new I-Pad. Existing pad facilities and pipelines will be used to the extent possible to produce Orion fluids to Gathering Center 2 (GC-2) for processing and shipment to Pump Station No. 1 (PS l). Orion fluids will be commingled with fluids from other fields on the surface at the respective well pads to maximize use of existing 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. Existing MI supply lines may be utilized for potential future EOR applications. The oil-sales line from GC-2 to PS 1 and the power distribution and generation facilities will also be utilized. (' Exhibit III-l provides a schematic overview of the relationship of these pads and pipelines relative to GC-2. Drill Pads and Roads Existing Well Pads L, V, Z and W have been identified as the surface locations for Orion wells to access the expected extent of the reservoir from existing facilities to the extent possible. This use of existing facilities minimizes new gravel placement and well step-out. The addition of a new well pad, I-Pad, adjacent to the Milne Road, as shown in Exhibit III-l and Exhibit III-2 is being evaluated as part of the Orion conceptual engineering effort. Expansions of existing well pad facilities at L- Pad and V-Pad are ongoing and expansions of Z-Pad and W-Pad are being considered to support IP A and Borealis development. The potential needs of Orion development will be considered in these activities. The expansions at L-Pad and V -Pad will not require new gravel. Additional gravel likely would be required at Z-Pad and W-Pad. Efforts will be made to stay within the existing ( 25 Orion Pool Rules and Area Injection Orde lication October 6, 2003 permitted footprint of these well pads. Schematics of existing pads L, V, Z and Ware included as Exhibits 1II-3, 4, 5 and 6. New pipelines would be required to connect possible drill site I-Pad to existing pipelines at L-Pad. The relationship of I-Pad to L-Pad is shown in Exhibit III-I. Pipelines would transport lift gas, water and potentially MI from the Prudhoe infrastructure to I-Pad and would transport produced fluids from I-Pad to the existing pipeline system. Orion production will be routed to GC-2 via the existing low-pressure, large-diameter flowlines. The need to expand existing infrastructure by looping pipelines or through the addition of processing facilities to accommodate Orion development is being evaluated as part of Orion conceptual engineering activities. Pad Facilities and Operations Orion wells at existing pads will be tied in as dictated by facilities available at the pad. The type of facility to be installed at the possible drill site I-Pad is being evaluated. The Borealis owners installed L-Pad, V-Pad, and the associated production facilities to support development of the Borealis Pool. Each pad allows 48 new wells (see Exhibits 111-3 and Exhibit III- 4). On-pad facilities included production and injection manifolding for 24 wells, well test facilities, safety shutdown valves, pigging facilities, controls, communications, production support and utilities. These well pads are being modified to allow for the injection of Miscible Injectant in a Water-Alternating-Gas (WAG) EOR process into any of the underlying pools. This expansion will be implemented using a WAG trunk and lateral design, which will allow all of the existing manifold slots to be used to support production wells. The balance of the surface slots on each pad will be occupied by injection wells. Exhibit 1II-7 and Exhibit III-8 show typical production and injection tie- ins at L- Pad and V-Pad. The existing Z-Pad wells are tied-in to production and injection manifold skids as shown in Exhibit III-5. All of the facilities are being used by wells producing from the Prudhoe Pool and the Borealis Pool, but the owners of these facilities are evaluating options for expansion. The potential needs of Orion development and possible expansion of Borealis development will be considered in this evaluation. 26 Orion Pool Rules and Area Injection Order APt JOn ( October 6, 2003 ( Existing W-Pad wells are tied into production manifold, water header and MI header facilities installed by the IP A owners. Existing W -Pad facilities are shown in Exhibit 111-6. There are facilities for nine new producers and an undetermined number of injectors to be tied in at W -Pad. The need to expand these facilities is being evaluated by the IP A owners. Exhibits 111-9 and Exhibit 111-10 show typical production and water injector tie-ins at W-Pad. Initially, water for waterflood operations will be obtained from the existing pipeline and distribution facilities at existing pads. Water for waterflooding wells at the potential new I-Pad will be supplied by extending the existing 12" water-injection supply line to L-Pad. Additional water wells are also under consideration as a source of injection water. Supplying the water rate required by Orion will potentially require either line looping and process expansions at GC-2 or the installation of processing facilities on or near the well pads. These alternatives are being reviewed as part of Orion conceptual engineering activities. Artificial-lift will be provided using either artificial-lift gas, or with jet pumps using injection water as the power fluid, or electrical submersible pumps (ESPs), or some combination as a function of the ( individual producer. Artificial-lift gas will be obtained from the existing pipelines and distribution systems on existing pads and by extending the 12" gas-lift supply line to L-Pad for possible future 1- Pad. Looping of existing artificial lift lines may be necessary. Well control will include data acquisition as well as actuated divert and choke valves. Wells will be tested using existing well test facilities at existing Pads. Anew, two-phase test separator would be installed at the new pad. Wells will be 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 Orion wells and drill site equipment. The data gathering system will continuously monitor the pressures and temperature of the producing wells. ( 27 Orion Pool Rules and Area Injection Ord( )\ication October 6, 2003 Gathering Center The need for process modifications to the GC-2 production center is being evaluated as part of Orion conceptual engineering activities. 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 of commingled fluids at GC-2, including that from the Orion Pool, is not expected to be limited by oil handling capacity, but is expected to be limited by gas and/or water handling capacity. 28 Orion Pool Rules and Area Injection Order APl' ion ( October 6, 2003 (' IV. Well Operations Existing Wells A number of exploration, appraisal and development wells that targeted the deeper Kuparuk and Ivishak have been drilled and logged in the Schrader Bluff Formation. However, only the V-201 and V-202 have been drilled and completed in the Orion Pool. The Orion Pool is currently producing from these two wells. Recent well test data for V-201 and V-202 are shown in Exhibit N-l. These well locations are shown in Exhibits 1-2 and 1-4. Drilling and Well Design Orion 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 inch conductor casing will be set 80 to 120 feet 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 permafrost 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 Orion. 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. c 29 Orion Pool Rules and Area Injection Orde ,lication October 6, 2003 No significant H2S has been detected in the Schrader Bluff Formation while drilling other development wells or in any Orion 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 Orion. 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 inch depending upon the estimated production and injection rates. In general, production casing will be sized to accommodate the desired tubing size in the Orion wells. The following table indicates typical casing and tubing sizes for proposed Orion wells: Surface Inter/Prod Production Production Casing Casing Liner 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" 5-1/2" to 2-7/8" 4-1/2" to 2-3/8" Multi -lateral 30 Orion Pool Rules and Area Injection Order APi ion ( October 6. 2003 ( Plans are to run L-80 grade casing in the Orion 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. Each multi-lateral leg of Orion horizontal producers will be completed in a single horizon (Schrader Bluff Formation). Vertical injectors and producers 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 horizontal multilateral production wells, Exhibit IV -3 for conventional production wells, Exhibit IV -4 for conventional injector wells, and Exhibit IV-5 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 Orion owners may utilize surplus IP A wells for development provided they meet Orion needs and contain adequate cement and mechanical integrity. The injectors will be designed to enable multi-formation injection where appropriate to the Kuparuk, Schrader Bluff, Sag and Ivishak formations. Multi-lateral undulating injector wells are also being evaluated. No exhibit has been included depicting this well type since it is still in the conceptual stage. Measurement-While-Drilling (MWD) and Logging-While-Drilling (LWD) will typically begin after setting the surface casing. Production hole will be drilled to below the Schrader Bluff Formation and a 7-5/8" 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 (OR), resistivity and density and neutron porosity throughout the reservoir section. Open-hole electric logs may supplement or replace L WD ( 31 Orion Pool Rules and Area Injection Orde ¡lication October 6, 2003 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 7-5/8" casing point. If any horizontal section is drilled, the mud system parameters may be optimized for that hole section, including the use of oil-based mud. 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-Y2" or 3-Y2" 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 Orion 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 Subsurface safety valves are not required in Orion 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 in the pool rules for the existing Schrader Bluff formation pools (Polaris Oil Pool, Schrader Bluff Oil Pool, and West Sak Oil Pool). 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 32 Orion Pool Rules and Area Injection Order APt' ion ( October 6, 2003 { Drilline: Fluids Freshwater low-solids, non-dispersed fluids or oil-based mud consisting of 80% mineral oil, emulsified with 20% water 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 in the water based systems. Other muds may be used in the future to minimize skin damage from drilling and enhance well performance. Stimulation Methods Fracture stimulation has been implemented for the one vertical Orion producer drilled to date and may be implemented in the future to mitigate formation damage, for sand control and to stimulate Orion wells. It may be necessary to stimulate horizontal wells, depending upon well performance. Acid or other forms of stimulation may be performed as needed. 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 common datum elevation of 4,500' 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 Orion reservoir polygon areas identified in Exhibit 1-13, when at least one Orion production well has been completed in the respective polygon. It is anticipated that the operator will collect more pressure measurements during initial field development to identify potential compartmentalization l \. 33 Orion Pool Rules and Area Injection Orde lication October 6, 2003 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 L02S 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 periodically run on commingled injection wells to assist in the allocation of flow splits. Completions - Producin2 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 "long string" 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-bearing interval in the Ugnu section. Production tubing will be run inside the longstring and sealed in the long string at least above the Me 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 will also be utilized to enhance recovery and rate while reducing development costs, facility requirements, and downtime associated with lower flow rates from conventional wells. 34 Orion Pool Rules and Area Injection Order APt' ion (' October 6, 2003 ~. ~, Artificial-lift The primary artificial-lift methods will either be gas-lifting with lift gas supplied from the gas-lift system or jet pumping using injection water as the power fluid as a possible alternative. Utilization of electrical submersible pumps (ESP's) is also under consideration. It is anticipated that all Orion 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. The producing wells may be 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 Soop. Jet pumps are being tested and are expected to mitigate the hydrate problems associated with gas-lift. Orion will likely experience a mix of gas-lifted, jet pumped, and/or ESP lifted wells throughout field life. Completions - Injection Wells f (, 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 -4 shows a typical vertical 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 for future logging. The longstring will be cemented from TD to above the highest significant hydrocarbon-bearing interval in the Ugnu 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. Multi-lateral injection wells are also being evaluated. ML injection wells could be tri-Iateral wells with one lateral drilled horizontally into each producing sand or some combination of undulating laterals could be employed. ML injection wells would look similar to the ML producer depicted in Exhibit IV -2. 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. l \. 35 Orion Pool Rules and Area Injection Orde ,Ii cation October 6, 2003 Commin21ed Injection Approval is requested for commingled water injection in wells L-I03i, L-llli, L-115i, L-117i, and V-I05i in the Borealis and Orion pools. These wells were 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 periodically. Additional opportunities may arise to take advantage of commingled injection wells. Wells L-I08i and L-l 09i were also completed such that they could be utilized for commingled water injection. Approval to inject into these two wells is not requested at this time. 36 Orion Pool Rules and Area Injection Order APt ion f October 6, 2003 ~ t V. Production Allocation Orion production allocation will be done according to the PBD 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 Orion production. All new Orion 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 Orion wells. All Orion gas delivered into GC-2 will be considered as having been used or consumed as fuel, flared or lost gas, with the effect that all residue gas from production operation.s· at GC-2 that is injected into Prudhoe Oil Pool will be deemed indigenous to the Prudhoe Pool. 37 Orion Pool Rules and Area Injection Orde lication October 6, 2003 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 Orion Pool. The proposed area for Area Injection Operations is the proposed Orion Pool area 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 Orion Pool, as of July 1, 2003. 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. 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 Orion Participating Area, which is coextensive with the Orion Pool. Exhibit VI-1 is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the area and within the proposed Orion 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 Orion Pool are described in Section II. Drill pad facilities and operations are described in Section III. 38 Orion Pool Rules and Area Injection Order APt .ion ( October 6, 2003 ( Pool Information 20 AAC 25.402(c)(5) This application for area injection operations is being submitted in conjunction with an application for establishing an Orion Pool and pool rules Geologic Information 20 AAC 25.402(c)(6) The geology of the Orion Pool is described in Section I. Log Information 20 AAC 25 .402( c )(7) Logs of the injection wells are already on file with the commission. ( Injection Well Casing Information 20 AAC 25.402(c)(8) Seven wells, L-103i, L-108i, L-109i, L-111i, L-115i, L-117i, and V-105i, were permitted and drilled for injection service for the Orion Pool. The casing programs for these wells were permitted and completed in accordance with 20 AAC 25.030. The completion diagram in Exhibit IV-4 is representative of a typical vertical Orion injection well. Multi-lateral injection wells are being evaluated and may be utilized. Exhibit IV -5 depicts a typical Orion-Borealis commingled injector. Cement-bond-Iogs have been run on all seven of the commingled injectors and demonstrate isolation of injected fluids to the Kuparuk River and Schrader Bluff Formations. Each well was completed in accordance with 20 AAC 25.412. Cement-bond-Iogs will be obtained on future injection wells drilled to demonstrate zonal isolation prior to water injection. ( 39 Orion Pool Rules and Area Injection OrdeJ lication October 6, 2003 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 Orion Oil Pool are: (a) Produced water from Orion or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; (b) Source Water from the Prince Creek Formation (also known as the Ugnu formation) (c) Tracer survey f1uid to monitor reservoir performance; (d) Fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); (e) Source water from the Seawater Treatment Plant; (f) Non-hazardous water collected from well-house cellars and standing ponds. Water Composition and Compatibility with Formation The injection-water composition in the Orion Pool, based on water analysis from Polaris W -200 well, GC-2 produced water, and sea water, are provided in Exhibit VI-2. The composition of Orion produced water will be a mixture of connate water and injection water, and will change over time depending on the rate and composition of injection water. Based on analyses of Polaris water 40 ( Orion Pool Rules and Area Injection Order Art', ;ion (" October 6, 2003 (' samples, no significant compatibility problems are expected between Orion connate water and injection water. Injection Pressures 20 AAC 25.402(c)(10) The expected average surface manifold water injection pressure is 2300 pSlg. The estimated maximum surface manifold injection pressure is 2800 psig. The resulting bottom hole pressure will be limited by hydraulic pressure losses in the well tubing and flow control devices. To meet a target of 100% reservoir voidage replacement, experience in the Schrader Bluff formation at Polaris has shown that it is optimum to inject above fracture pressure. The Orion injection wells will be managed to keep injected fluids within the approved injection strata. Maximum fluid injection requirements at the Orion Pool are estimated at 100,000 to 125,000 BWPD. ( Fracture Information 20 AAC 25.402(c)(11) It is not expected that the maximum injection pressure for Orion Pool injection wells will propagate fractures through the confining strata, which would allow fluids to enter any freshwater strata. V - 201 was hydraulically fracture stimulated in the OA Sand. The overlying Me Sand is considered wet with approximately 70% water saturation. Production from V-201 has shown very little water production indicating that the fracture did not extend vertically to the Me Sand. Directly above the top of the injection zone in the OA sand, there is a mudstone at the base of the overlying Nc, which is approximately 60 ft thick. This is expected to provide fracture confinement to the 0 sands. To ensure injection conformance, injection performance will be monitored for each injection wel1. Any significant change in injectivity, which would indicate injection out-of-zone, will be followed ( 41 Orion Pool Rules and Area Injection OrdeJ lication October 6, 2003 up with surveillance. The surveillance could include spinner/temperature logs and if necessary, a tracer survey to determine the location of the injection anomaly. Formation Water Quality 20 AAC 25.402(c)(l2) Although no produced water is available to perform a water analysis, it is expected to be similar to Polaris pool water quality. Freshwater Strata 20 AAC 25.402(c)(l3) 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 Orion Area Injection Order. Hydrocarbon Recovery 20 AAC 25.402( c )(14) Orion 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. Mechanical Integrity of Wells 20 AAC 25.402(c)(l5) Mechanical Inte~rity of Wells Within 1,4 mile of Injectors Seven injection wells have been drilled L-I03i, L-I08i, L-I09i, L-llli, L-115i, L-117i, and V-I05i. Approval to inject into L-I08i and L-I09i is not requested at this tÌlne. A filap showing all 42 Orion Pool Rules and Area Injection Order Al iÌon (' October 6, 2003 ( penetrations through the Schrader Bluff Orion Pool, and wells within 1,4 mile of the injection wells are shown as Exhibit VI-3. The wells within the 1,4 mile radius of requested injection wells are, L- 02, L-I10, L-112, L-114, and L-120. A report of the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of an injection well is included as Exhibit VI-4 to VI-8. ( ( 43 Orion Pool Rules and Area Injection Ordel lication October 6, 2003 VII. Proposed Orion Pool Rules BP Exploration (Alaska) Inc., in its capacity as Orion Operator and Unit Operator, respectfully requests that the Commission adopt the following Pool Rules for the Orion Oil Pool: Pool Name, Definition and Classification The field is the Prudhoe Bay Field and the pool is the Orion Oil Pool. The Orion Pool is classified as an Oil Pool. The Orion Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 4,549 feet MD and 5,106 feet MD in the PBV V-201 well (4,126 and 4,650 feet TVDSS, respectively), within the area described below. Affected Area (Umiat Meridian): Township Range Lease TI2N-RI0E ADL 025637 T12N-RIIE ADL 047446 ADL 047447 ADL 028238 ADL 028239 ADL 047449 TIIN-RIIE ADL 028240 ADL 028241 ADL 028245 Sections 13 and 24 N/2 17,18,19, and 20 16 S/2 and NW/4 and S/2 NE/4, 21, and 22 25 SW/4, 26,35, and 36 27,28,33 E/2 and N/2 NW/4, and 34 29 N/2 and SE/4, and 30 N/2 NE/4 1,2, 11 E/2 and E/2 NW/4, and 12 3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 44 Orion Pool Rules and Area Injection Order A~ ¡ion ( TI1N-RI2E ADL 047450 ADL 028263 ADL 028262 ADL 047452 ADL 047453 ( October 6, 2003 7, and 8 S/2 and NW/4 16 SW/4 and S/2 NW/4, and 21 SW/4 and S/2 NW/4 and NW/4 NW/4 and W/2 SE/4 17, 18, 19 N/2 and SE/4 and N/2 SW /4, and 20 28 W/2 and W/2 E/2 29 N/2 and N/2 SE/4 Rule 1: 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 Orion Oil Pool shall not be opened in any well closer than 500 feet to an external boundary where ownership changes. Rule 2: 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 3: 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) Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the safety valve systems and associated equipment are in proper working condition. ( 45 Orion Pool Rules and Area Injection Ordel lication October 6. 2003 Rule 4: Common Production Facilities and Surface Commingling (a) Production from the Orion Pool may be commingled with production from other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. (b) Production allocation is to be performed in accordance with the Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002, subject to ongoing review. All Orion wells must use the Gathering Center 2 well allocation factor for oil, gas and water. (c) All wells must be tested a minimum of once per month. All new Orion wells must be tested a minimum of two times per month during the first three months of production. The Commission may require more frequent or longer tests if the allocation quality deteriorates. (d) Technical meetings must be held quarterly to review progress of the implementation of the Western Satellite Production Metering Plan. (e) The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Rule 5: 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 Orion reservoir compartments where Orion production wells exist. (c) The reservoir pressure datum will be 4,400' 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 frOlll 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. 46 Orion Pool Rules and Area Injection Order APt jon ( October 6, 2003 (f) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. Rule 6: Gas-Oil Ratio Exemption Wells producing from the Orion 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 7: Pressure Maintenance Project Average reservoir pressure will be maintained above' saturation pressure. Rule 8: Multiple Completion of Water Injection Wells (a) Water injector wells into the Orion Pool may be completed to allow for simultaneous injection in the Orion Pool and other pools, 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. (c) Results of logs or surveys used for determining the allocation of water injection must be supplied in the yearly reservoir surveillance report. (d) An approved injection order is required prior to commencement of injection in each pool through a common wellbore. Rule 9: Reservoir Surveillance Report An annual reservoir surveillance report for the prior calendar year must be filed by April 1 st. The report must include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: (a) Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval. ( 47 Orion Pool Rules and Area Injection Orde 'lication October 6, 2003 (b) Reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool. (c) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. (d) Review of pool production allocation factors and issues over the prior year. (e) Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation techniques. Rule 10: Operation of Development Wells with Pressure Communication or Leakage in any Casing, Tubing, or Packer (a) The operator shall conduct and document a pressure test of tubulars and completion equipment in each developlllent well at the tÍ1ne of installation or replacelllent that is sufficient to delllonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. (b) The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. (c) The operator shall notify the AOGCC within three working days after the operator identities a well as having (a) sustained inner annulus pressure that exceeds 2000 psig for all Orion Pool development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. (d) The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC 48 Orion Pool Rules and Area Injection Order Ap( ion ( October 6, 2003 ( approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. (e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. (f) Before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient ( degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig for all Orion Pool development wells, and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. (g) For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intention all y. ( 49 Orion Pool Rules and Area Injection Orde ,Ii cation October 6, 2003 Rule 11: Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into fresh water. 50 Orion Pool Rules and Area Injection Order Apf ion f October 6, 2003 ( VIII. Proposed Area Injection Order BP Exploration (Alaska) Inc., in its capacity as Orion 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 Orion Pool and consider the following rules to govern such activity: Affected Area (Umiat Meridian): Township Range TI2N-RI0E Lease ADL 025637 TI2N-RIIE ADL 047446 ADL 047447 ( ADL 028238 ADL 028239 ADL 047449 TIIN-RIIE ADL 028240 ADL 028241 ADL 028245 TIIN-RI2E ADL 047450 ADL 028263 ADL 028262 ADL 047452 ADL 047453 ( Sections 13 and 24 N/2 17, 18, 19, and 20 16 S/2 and NW/4 and S/2 NE/4, 21, and 22 25 SW/4, 26, 35, and 36 27, 28, 33 E/2 and N/2 NW /4, and 34 29 N/2 and SE/4, and 30 N/2 NE/4 1,2, 11 E/2 and E/2 NW/4, and 12 3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 7, and 8 S/2 and NW/4 16 SW/4 and S/2 NW/4, and 21 SW/4 and S/2 NW/4 and NW/4 NW/4 and W 12 SE/4 17, 18, 19N/2andSE/4andN/2 SW/4, and 20 28 W/2 and W/2 E/2 29 N/2 and N/2 SE/4 51 Orion Pool Rules and Area Injection Orde lication October 6, 2003 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 log measured depths 4,549 feet MD and 5,106 feet MD in the PBU V-201 well (4,126 and 4,650 feet TVDSS, respectively). Rule 2: 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, or through a well that existed as a service well for injection purposes on the effective date of this AIO. 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 3: Authorized Injection Fluids Fluids authorized for injection within the affected area are: (a) Produced water frOlTI Orion or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; (b) Source Water from the Prince Creek Formation (also known as the Ugnu formation); (c) Tracer survey fluid to monitor reservoir performance; (d) Fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); (e) Source water fronl the Seawater Treatnlent Plant; 52 Orion Pool Rules and Area Injection Order Ap(· ion ( October 6, 2003 (f) Non-hazardous water collected from well house cellars and standing ponds. Rule 4: Injection Pressure Normal injection pressures must be maintained slightly above the parting pressure of the Schrader Bluff sandstone to allow economic injection rates while keeping the injected fluids confined in the authorized injection strata. Rule 5: 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 6: Demonstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission that ensures that the tubing- casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. ( ~, Rule 7: Multiple Completion of Water Injection Wells (a) Water injector wells into the Orion Pool may be completed to allow for simultaneous injection in the Orion Pool and other pools so long as mechanical isolation between pools is demonstrated and approved by the Commission. (b) Prior to initiation of commingled 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 through a common wellbore. ( 53 Orion Pool Rules and Area Injection Orde lication October 6, 2003 Rule 8: Well Integrity Failure Whenever operating pressure or pressure tests indicate communication or leakage of any casing, tubing or packer within an injection well, 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 (Fonn 10-403) is required before initiating corrective action. Rule 9: Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 2 without pnor 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 10: 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. 54 Orion Pool Rules and Area Injection Order AP( .ion ( October 6. 2003 IX. List of Exhibits 1-1 Location of the Orion Pool Alaska North Slope 1-2 Orion PoollInjection Area and Proposed Orion Participating Area Outline 1-3 Orion PoollInjection Area Type Log Well V-201 1-4 Orion PooVInjection Area Top Schrader Bluff OA Structure Map 1-5 Orion Pool/Injection Area Top Schrader Bluff OA Structure Map Showing Structural Cross- . Sections 1-6 Orion Pool/Injection Area Structure and Interpreted Oil/W ater Contacts Cross Section A - A" 1-7 Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/W ater Contacts Cross Section B - B' ( \', 1-8 Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/Water Contacts Cross Section C - C' 1-9 Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/Water Contacts Cross Section D - D' 1-10 Orion PooVInjection Area Structure and Interpreted Most Likely Oil/Water Contacts Cross Section E - E' 1-11 Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/Water Contacts Cross Section F - F' 1-12 Orion Pool/Injection Area Isochore Thickness of Mudstone Between Top Na Sand and Base Mc Sand 1-13 Orion Pool/Injection Area Nand 0 Sand Reservoir Compartment Map { 55 t,,~ Orion Pool Rules and Area Injection Orde lication October 6, 2003 1-14 Orion Pool/Injection Area 0 Sands Composite Net Pay Thickness 1-15 Orion Pool/Injection Area N Sands Composite Net Pay Thickness 1-16 Orion Pool/Injection Area 0 Sands Composite Oil Pore Foot Thickness Map 1-17 Orion Pool/Injection Area N Sands Composite Oil Pore Foot Thickness Map II-I Orion Model Reservoir Property Ranges II-2 Orion Relative Permeabilities II-3 Orion Fluid Properties II-4 Orion MDT Summary Table II-5 Orion Geochemical Samples 11-6 Orion Model PVT Properties II-7 Orion Waterflood Rate Forecast II-8 Orion PVT Match Using MPU Schrader Bluff EOS III-l Orion Facility Plan - Planned Facilities - P/L & Utility Map III-2 I-Pad Location Map III-3 Orion L-Pad - Surface Facilities III-4 Orion V -Pad - Surface Facilities III-5 Orion Z-Pad - Surface Facilities 1II-6 Orion W -Pad - Surface Facilities 1II-7 Typical L and V -Pad Production Tie-in 56 Orion Pool Rules and Area Injection Order ApI- )on ) October 6, 2003 III - 8 Typical L and V-Pad Injection Tie-in ) III-9 Typical L and V-Pad WAG Injector III -10 Typical W -Pad Production Tie-in III-II Typical W -Pad Injection Tie-in IV-l Orion Representative Well Test Summary IV-2 Typical Tri-Lateral Production Well IV-4 Typical Vertical Hydraulically Fractured Producer IV-5 Typical Injection Well IV-5 Typical Orion-Borealis Commingled Injector VI-l Affidavit ) VI-2 Polaris Injection Water Compositions VI-3 Orion Pool/Injection Area Injection Well Location Map VI-4 L-02 Well Integrity Report VI-5 L-II0 Well Integrity Report VI-6 L-114 Well Integrity Report VI-7 L-116 Well Integrity Report VI-8 L-120 Well Integrity Report \ )if' 57 cati n f t laska .. rl n rth I I K u paruk nit i- f Prudhoe Bay Unit , I ... l o 3 6 Miles North Exhibit 1..1.. Exhibit "'-1 Orion Facility Plan - Planned Facilities - P/L & Utility Map M Hne S-Pad I-Pad EWE Jct Z-Pad Pipelines EXisting EWE Proj W RD Proj Production Water Inj Gas lift _ M. Power Fiber Optic Cable Exhibit 111-3 Orion L- ad - Surface Facilities , I t.;. ð ¡ 520 521 , WEll PRODUCER II WELL INJECTOR À WELL SLOT 0 WELL SLOT WlCONDUCTOR iIÞ DATE: SCAlE ' '" 1 00' MAP UPDATED: 2002 L Exhibit 111-4 Orion V... ad - Surface Facilities '4 11 .~ \ \ \ t ~ \ , ~ WEll PRODUCER III WEll INJECTOR SLOT SLOT W/CONOOCTOAIIIi DATE: SCAlE: 100' MAP UPDATED, 2002 , v Exhibit 111..5 rion Z- ad - Surface Facilities , ~ It o 2: I ! -- PRODUCER II WElllNJECTOA Å 1 !IIiO'-OíI .... DATE' 1 -z SCALE: 1" "" 250' MAP DATE· 2000 Exhibit 111-6 ion W-Pad - Su ace Facilities ~400--- 8500--- c "* '- Exhiblt 111-7 Typical L and V-Pad Producer -' Lift Gas Well House Shelter Limits r------------------- NG ~.~ o Water X Ot><J ~ ~~ J~ t><J c:::::::I ...... - -= ------------------- II II IX] IX] Well Head Manifold Skid s. Mattison/LJ L August 2003 Exhibit 111-8 Typical L and V-Pad Water Injector '- Well House Shelter Limits r------------------- NH X OI><1Iv1 œ-:R c=I .... - ------~----------- ~ Water Injector - Lift Gas ~ ~ ~o Water !J ~ ~ x --- II Þ<1 Manifold Skid S. Mattison/LJ L August 2003 Exhibit 111-9 Typical L and V-Pad WAG Injector '- ----' Well House Shelter Limits ...~ --------------------- NG X Ot><JIVl ~ a::::::I .... Pi ~ II II [><] [><] ~ t><J t><J ~ - ..... --------------------- -=' Water MI Trunk Trunk S. Mattison/LJL August 2003 - Exhibrt 111-1 0 Typical W-Pad Producer - Lift Gas ~ Well House Shelter Limits r------------------- NG .~ X Ot><J [8--:X ~~ J -&-9 t><J c::::::::I .~ "'" - -------~----------- II II I><J I><J Well Head Manifold Skid S. Mattison/LJ L August 2003 - Exhibit 111-11 Typical W-Pad WAG Injector Well House Shelter Limits --------------------- NG Z OÞ<Uv1 ~ ~ Pi II r::::::I :- ~ II = [XJ [XJ "~ _/ -~ - -= --------------------- Water MI Trunk Trunk ,.¿;;¡ s. Mattison/LJL August 2003 ~ -~_/ =x1ibi~ '.'-1 Orion ~eJresen~a~ive V\'e -es~ Summary Oil Flow Well Test Date Rate (bpd) V-201 * 6/24/2003 V-202** 8/5/2003 * On Jet Pump, prior to conversion to Gas ** OBd single horizontal lateral 7 Gas/Oil Ratio (scf/bbl) Gas Lift Rate (mmscf) Tubing Temp (OF) Tubing Pressure (psia) 344 ~ ~ Typ IC a I T rI-l atera Pro du ctwn Well Exhibit IV-2 l TREE,,-""· '" IN Ell HEft. D : 11", $1.1 Oe n 5 8~'~ Ie IT! .iI. 2a" x 3~' 2155 Ibm, .A.53 EIU"¡ rl~IJI<9led 1Ü2!' -- I D·J If" P 0 r I Colla r I 1 ,ÜÜÜ' ~--. .-. (:3 B 1 ~:" 12,2 Üü' TV D - ~Gu..~ 4- /2"x "fŒG·2 \Jlllth [I CK She:3r 'v:'¡lve in middle mandrel ~-1t2", 12.6 Itliì't, L-30, B TC-U Co I P II_ gOD: 5.2" D rl1tfl D 3.833" i3 95 õ" .II! 10-314", 4~.U L-i'iO 8TC Clg g $ljjlH 100' TV 01 I b$low SVl or ~O' T~!O b $10 \'1 S V3 sleeve with 3.813"1[1 X 5· t2" P;¡¡c¡':er (3.813" !~2 PPG MO Bt,j\ below U u ilia I! ra I L! U! I J lu n clio n @ Î) po,". i and I g-3,'4" OBI la1»ral Pac¡':er 7-5ß",29.71;i, l-3D, BTC-U (3.725" C at II 9 D rtft: 6 .7 5" C at I' 9 If) 6.875" IUUlllaIHalL!U!IJ IUl1cllon @ ~)p ODa liinD I /4" OB:: la1»ral ~ .75" liner P acl<:er 8, 1 ·5,'3" l~ a i In g S h (I! I~ ~ I 2 D' U [I In Î) 111 0 B [ I a 11 D ~-3,'4" OBd La1»ra D.~r.. R"~·.IP CIJ PilI\1"N ''$. 712U2UU8 MI~ TRIOLO LIII,}..I ::I P.' IJII:I~J..j; I:iI rwl. .:¡ .. I~ III (..il.. f":r.:: m ¡: 1 11II I: J1':: " "!iiEL L. Trl-ls 1» ra -) ') Exhibit IV-3 Typical Vertical Hydraulically Fractured Producer T fI. EE: 4--H16-!iM IAI ELL H EA [I : 11-, 5M 13 I!! n 5 8y ~ II!! m C~III' 8rõi'A1on t-.ttx.rlil 9ES RKB L 1 :Z[]- x :340- :z 1!i.5 Ib i'fI, A5:J E fl.1AI h~ ul!:lll!! d 1 114 ' ~ E:J 11,000' 1 Port Cdl.... I 3,ùùù'TVD I : I. 3-1,Q" 'X' L:mding Nipple IJJ ith 2.813" seal bore. . I 1 I') ." [!~GLM 3-1 fl"x 1-1fl" I'utu1G Ii \fI.tth 0 CR Sh ear \l.3lve pinned to 2;500 L e. &1;".40 fD'f1¡ L-So. BTC J Either 100' TVDss œl CJW tcp SV1 cr 90' lVOss œlowtop SV3 p:'! l ~ I 'I :ii II 3 -1,12 - , 9.3 tJ m. L -3[1 I TC II D rrtrlD : 2.861-/2 .992- :'1 ': I ~ , I I, ~ Sliding Slee"oli! with 2.813" Polish Bore jll I} ,I ~"..". ~! ª' r Ä 3-1 œ Production Ps.cker -=: ;2001 PJD 1i!b0'iQ f1.;¡ M !'?itnd ~ 3-1/2 II 'l.J L9J1ding Nipple 'Uith s. 2.81 3 10 3-1/211 Vv'ireLine Entry Guide .....50.. above the OA s9J1d æ 0A:::an d Perfs æ OBs. :::and Perfs æ OBd s9J1d Perfs - - - - - - - - - - - 711J PBm 71~ 26 Mt.. L80J BTc..M od \.....1:50 I M 0 below base 0 Ef \ ~ Date Rev By Comments Mik T Propoæd Completion GE'R . . &-,;/1. ,,11... W'liltYn_llIfWJ{ ,)0' 7/28/03 W'E ll: Producer -) Typical Injection Well --....I.':, ~., . 10 ~'EI /--- 7« Short Joint 8: RA Tag .../ æ - CQ/1Iu Elrõl'.llL101 ~ 9Së1 RKE .. P ortColQI 11,000' I ~ €I- 00".40 IYfI; L: 1;0. BTC Either 30' NDss below SV3 Cf 100' NDss below SV1 ~ 4-1n"::< 3-112"TCII ::<0-- "'TBD' T'J[)~ ~ ... T B D' T'J [) ~ ~ ~) Exh ibit IV-4 TR EE: ...-1i16· SM IAI ELLH EAD: 11· x SM Ol!n S 8y:!=ll!m ~ 20· X 3...· 21 S.5 Ib NI, AS3 E RIAl h:!=lJli:lll!d 114' I ¡.! 'I :j . I I ~ 4-112" 'X' Landing Npple with 3.813" æal bore. 2,~ÜÜ' TVD ~GLM4-1fl"X 1" KBG2 . iii' \l\lith OCR Shear Val", pinnedto 2,500 I 3, 1üü' P/D ii.'. ok Ii . I "-112" 12.15 bttt, L-8D, TC II : 0 rttt I 10 : 3.833· {.J .9 58 · 3-112·, 9.3 b tn:, L -8 0 , T C II o rttt 110 : 2.861· t2 .992· 4-1 fl." 'X' Landing Npple with 3 .813" æal bore. r Ä 3-1/~ Production Paclœr "JJ fj r...Ð .w:. 'iQ 'hi. 'b P Q:J. P r;rf 3-1 fl." 'X' Landing Npple with 2 .813" æal bore. Cam::o 3-112" Ä 1-112" G LM r Ä 3-1 ~ Production P3.cl::er ~. '............ . 3·1fl."'}{' Landing Npple with 2 .813" æal bore. ;. . Cam::o 3-112" Ä 1-112" G LM = I' I, =------- - : . DBa æ.nd Perfs {;I~ r Ä 3-1/~ Produ ction Paclœr ~ 3·1 fl." 'X' Landing Npple with 2 .813" æal bore. q 3-1/2" I¡I¡jreLiM Entry Guide (-50' abo..... !he top OBd pert - - - - ~BdSMdPerfS - - ~w r PBTD ~ 7": 26Wft, LSO, BTGMod ~15ü' MD b".lc..wth". bas". OBf I Date 7/28103 Rev By Comments M ik T Propoæd Co m ple1ion GPR,~ ,'B-A. .-zl '{;]1¡¡/U fImnif!l'dJ..3Y ,,S; WE LL: Injector ~) ~ Typical Orion-Sorealis Commingled Injector Exhibit IV-5 .. ! ¡ TREE: ...-H16· SM IAI ELL H EA. [I : 11· x!5M 0 ~r. 5 8Y:$ ~ m C"'IU E 1rõML1on t-.UboPiI !:IE ~ F: Iœ ... :;m· x 3...· 215.5 Ib "11, AS3 E RIAl Ir.:$ul~ ~ EI 114' PortCdl.... 8!J 11 .000' I ~ 4-112"X 3-1n" TCII XO 4-1 n" 'X' Landing Nipple wrth 3.813" seal bore . I 2,5ùù' TVD I 9- 6JI;': 4) II'fI¡ L: 00 I Ei lC G LÞ..1 4-1 n" Ä 1" KB G2 \IVrth DC R Shear Vah..-e pin ned to 2.500 ~ Eiiher 90' TVDss bel CIW SV3 cr 100 I TVDss be low SV1 ~-1/2· I 12.75 tlm, L-8[] I TC II o rh't f 10 : 3.833....3.958· 3-1/2·,9.3 Ibm. L-8[], TC II o rh't f ID : 2.867·/2 .992· 4-1 n" 'X' Landing Npple with 3.813" seal bore. :;IJ: EIJ r Ä 3-1 re Production Packer ~ ::1)(1 PoD ..00.....1110 1:p co. porf 3-1 n" 'X' Landing Npple with 2.813" seal bore. ~ SchrMerPerfs - - - ~. .'.'.'. '.' 3-112" x 1-112" G Uv1 ~ - - - - SctJrader Perf::: ~ e; ~ r x 3-1/2" Produclion Packer þ3-112" 'J(" Landing t.lpple with 2.813"ssal bore. ~ 3-11211 Vv'ireLine Entry Guide (....1 50" abo'l'e the top per(! - - ~ ~ Kupsruk Perfs ~\~ 71~ PBTD ~ 7': 26 Iff\. L80, BTG-Mod 1~1SÙ' MD b<,lc.wth<, bas<, ~:uparuk C I Date 7/28103 R9J By Co rnnents Mik T Proposed Go mp letion GIêitwhD_kr ~,.". WEll: Injector I ) ) Exhibit VI-I. ') AFFIDA VIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Brian D. Huff, declare and affirm as follows: 1. I am the Greater Prudhoe Bay Orion Manager for BP Exploration (Alaska) Inc., the designated operator of the proposed Orion Participating Area, and as such have responsibility for Orion operations. 2. On 10 10 ( ( 0 J , I caused copies of the Orion 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), INC. ATTENTION: MAUREEN JOHNSON P.O. BOX 196612 ANCHORAGE, AK 99519-6612 ) Surface Owners: STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES ATTENTION: DR. MARK MYERS 550 WEST 7TH AVENUE, SUITE 800 ANCHORAGE, AK 99501-3510 Dated: Och be( I / ~(; 3 'V~ J. Jill Brian D. Huff r ) Declared and affirmed before me this \.It(((({{fl(/. ,\\~fl ~~,~~"~,{r~ ~ ~ ". ..-- ". 0 ~ ~ (J." 01ARy"~~ :::: IlJ : ~' "" .. . ~:::. '-0 ~ ..., "--- :::: 011( : PUa\ ~(j : N ::: :::: ø" g~ JS" "'.:::- ::. ~". " __-~: :0 ~ -..... ~ .~ "" ~ " . :"!~ OF þ.~ . " $' ~ . . . . . . \\ /.J.J fc \ \\ /}}J.IJ))})\ ¡-st- day of (çk~ <9Cù3 0:J~~L~~:f~Ý 1Ji:.¡\~ My commission expires:,::-J \Áne. ~ dUff ......~. "~ - Exhibit VI-2: Polaris Injection Water Compositions W-200 GC2 Source, ppm Formation Water Produced Water Sea Water I -~. Barium 16.9 2.17 0 Bicarbonate 4640 1640 140 Calcium 55 247 407 Chloride 13529 12600 15770 Iron <0.02 4.32 Magnesium 109 156 1290 pH 8 6.9 Potassium 271 107 ..-,- Sodium 7221 8080 8400 Strontium 10.3 26.2 5 Sulfate 479 560 2670 TDS 26322 23427 28687 , I ' I I Ii 'I Orion Pool/Injection Area Injection Well Location ap '\ /// Y~ . / " IsI 25 30 30 I ] e, OB 12E ;¡ ~J ., zg i-. "(\1 <) ~~f:- 32 I~ \ L~ßP~_ " ,. '\. ~ ~ . "1 " ( T1 J =1 ]4 J3 17 ]fi __~ i~",,- me............. ~~ ¿ j 24 ~~ c :J I~ I I ~ 38 31 "32 6 s s 3 / f ..... IV-2011 Production Well 12 9 J -, 7 8 9 10 .~ High Angle Production Well - - ~ '; ~:I IV-1051 Injection Well ] ~, J 0 ] 7 J 6 ~1/Z[ ¡ " 1/4 Mile Rad rcle -.......- T11 Nw-~1 ........ around existing Orion Injection wel WPadl, I 23 24 20 I 2,g ] 9 21 ¿c: 12 --:>c:: c.J 2:=J 28 27 26 25 27 I , Exhibit 1-3 ~ ",-" ~ Exhibit VI-4: L-02 Well Inteqrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: 12/31/2002 8-3/4" Schrader Bluff Penetration Casing Diameter: 7" Well Status as of 8/2003: Oil Producer Gas Lift Cement Logs Across Schrader Bluff: None Comments: The intermediate casing in this well was cemented in two stages. The second stage utilized an HES 2nd Stage Cementer to place cement across the Schrader Bluff from approximately 200' below the interval. The 2nd stage cement job was pumped as planned with the cementer located at 5253'MD. With a gauge hole, 1289'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 790'MD of cement above the top of the Na sand. The plug bumped and held at 1700psi. Additional Information: Well Diagram - Exhibit VI-4 a Drilling Daily Reports (Cementing) - Exhibit VI-4 b '-..-/ L~ TREE = FIv'C4-1/6" 5M WELLHEAD = FM:: GEN 5 . ...........""............ ""~...... '". .. .................. " AC1UATOR= KB. ELEV = 82' SF. a.ËV ";~--~'~-"-~~53'" l(OP =" ,,---'~",-'-~ """"gOOì" fA ngïè ;----98 ò" @f1 0 7227 I uatuñï"'rJD' ;......... ...... ... '''''''1ï)Õ4:ž'' Öa-tüñï iVb .;:;;.... - ··..··..88 oö¡"'sš' \ , L-02 SAFE )OTES: INCLINATION> 700 @ 10310' =----1 954' 1-1 TA M PORT COL LAR 1 2119' 1--14-112" HES X NIP, ID = 3.813" 1 ~ GAS LIFT MANDRELS ST I\/D TVD DEV TY Æ VLV LATCH PORr DATE L 7 3005 2979 20 KBG-2 DOME BK 16 05/31/03 6 4263 4080 30 KB G- 2 S/O BK 22 05/31/03 5 5939 5532 32 KBG-2 DMY BK 05/31/03 4 7248 6603 40 KBG-2 DMY BK 05/31/03 3 8263 7396 38 KBG-2 DMY BK 04/15/03 2 9031 7991 38 KBG-2 DMY BK 04/15/03 1 9594 8438 37 KBG-2 DMY BK 04/15/03 I 9-5/8" CSG, 40#, L-80, ID = 8.835" H 2581' r----A Minimum ID = 3.725" @ 9768' 4-1/2" HES XN NIPPLE 9662' 1--14-1/2" HESX NIP, ID= 3.813" 1 z z 9726' 1-11" X 4-1/2" BKR S-3 PKR, ID= 3.875" 1 I- 9747' 1-14-1/2" HESX NIP, ID= 3.813" 1 ) 14-1/2",12.6#, L-80, .0152 bpf, ID= 3.958" 1-1 9779' 9779' 1-14-1/2" HES XN NIP, 0 = 3.725" 1 1-15" X 7" BKRZXPLNRTOPA<R, ID= 5.610" 1-14-1/2" WLEG, ID = 3.958" 1 1-1 ELMD TT NOT LOGGED ~/ 1 ~ 1 ~ 1 9768' 9783' 7" CSG, 26#, L-80, ID = 6.276" 1-1 9953' J---A .. PffiFORA TION SUM\IIARY REF LOG: ANGLEA TTOP ÆRF: 96 @ 10876' I\bte: Refer to Production DB for historical perf data SIZ E SPF INTER\! AL Opn/Sqz DA 1E SLOTTED 10876 -11318 11525 -12287 12370 - 12571 12775 - 13570 o o o o 12130/02 12130/02 12130/02 12130/02 I RHD HH 13570' 1 ~ \4-1/2" SL TD LNR, 12.6#, L-80, .0152 bpf, ID = 3.958" 13572' ~^^^^^^.... II DATE Y 1 /01/03 .J2/15/03 04/15/03 05/07/03 05/31/03 REV BY DAC/KK GJB/tlh JJ/KA K TH/KAK MI-VTLP COM\llENTS ORIGINAL COrvPLEfION GLV UFDATE GL V C/O ŒPfH CORRECTIONS GL V C/O D<\ TE REV BY COMMEN1S FRLDHOE BA Y UNIT WELL: L-02 PE~IT No: 2012070 A R No: 50-029-23048-00 SEC 34, T12N, R11 E, 2528' SI\l & 3860' WEL Exhibit VI-4 a Operator: BP EXPLORATION Well: L-02 ") Field: PRUDHOE BAY ) BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: Current Well Status Casing Size: 7.000 (in) Costs in: USD Casing (MD): 9,953.0 (ft) Daily Mud: 8,926 Next Casing Size: 4.500 (in) Cum. Mud: 259,578 Next Casing (MD): 13,842.0 (ft) Daily Well: 69,648 Next Casing (TVD):8,857.0 (ft) Cum. Well: 1,355,062 Depth MD: 9,953.0 (ft) Est. TVD: 8,733.0 (ft) Progress: (ft) Auth Depth: 13,842.0 (ft) Hole Size: 8.750 (in) DOLlDFS/Target: 10.3019.80/28.68 Geologist: Ray Engineer: Triolo Supervisor: MADSEN I GALLOWAY Current Status: 24hr Summary: 24hr Forecast: Comments: Days Since Last DAFWC: 343 Last Csg Test Press.: 3,500 (psi) Last BOP Press. Test: 12/3/2002 Next BOP Press. Test: 12/10/2002 Last Divertor Drill (D3): 12/1/2002 No. Stop Cards: FIRE: 12/8/2002 LOT TVD: LOT EMW: MAASSP: Test Pressure: ') Kick Tolerance: ) Kick Volume: 2,580.0 (ft) 13.24 (ppg) 287 (psi) 475 (psi) (ppg) (bbl) ROP Daily: Rap Cum.: WOB (min): WOB (max): RPM Min.: RPM DH: Torq. on Bottom: (ft-Ibf) Torq. off Bottom: (ft-Ibf) (ftlhr) (ft/hr) ) Exh i bit VI-4 b Report: 12 Date: 12/10/2002 Rig Accept: Rig Release: Spud Date: WX Date: Elev Ref: 17:00 11/30/2002 12/1/2002 SEA LEVEL I 2 i 4 Program: Weather: KB Elev: 82.00 (ft) Tot. Personnel: 42 Cost Ahead 300,000 USD, Days Ahead 4.00 2 deg, 10 mph SSW, WC -15 deg Last Trip Drill (D1): Last Safety Meeting: 12/8/2002 12/10/2002 N I D BOP Stack POOH LID 5" DP, Ran 7" Csg to 9,953', Circ Cement 7" Csg, N/D BOP, Set Slips, N/U & Tst BOPs, PIU 4" DP NO ACCIDENTS, NO INCIDENTS, NO SPILLS, 2 deg, 10 mph SSW, WC -15 deg, Visibility 0.2 Miles HSE& Well Control All Free Days: 11 Last Spill Drill: 12/8/2002 Regulatory Agency Insp: N KICK WHILE DRILL (D2)12/7/2002 Pump Slow Pump Rates (Circ) Stroke Rate PressureO Non-compliance Issued: N WELL KILL (D5): 12/4/2002 Slow Pump Rates (Choke) II Slow Pump Rates (Kill) Stroke Rate PressureO Stroke Rate PressureO I i 'I I Operational. Parameters Rotating Weight: (Ibs) Daily Bit Hrs: 0.00 (hr) Pick Up Wt.: (Ibs) Daily Sliding Hrs:O.OO (hr) Slack Off Wt.: (Ibs) Cum. Bit Hrs: (hr) Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: (psi) Circ. On Bottom: (psi) Jar Hrs since Inspect: (hr) Ann. Vel. Riser: (ft/min) i Ann. Vel. DC: 414.8 (ft/minl) Ann. Vel. DP: 261.4 (ft/min,) Manuf. Smith Make S86EHVPX Bits Serial # JS8755 : Nozzles i 12/12/12/12/12/12/12 , 121/ \ TF A (in2) i Depth In (ft) ¡ Depth Out (ft) 0.884 ' 9,953.0' 9,953.0 Daily Hrs 0.00 Cum Hrs I Cum Rap I Pump Status - Drilling and Riser ! Pump ¡¡Type E(~f. ! Str~)kes Line~) Size \ Circ.(~ate I I! ' 1\ i I I I Condition BT G X 1 NO ¡ TD Bit Run # I Re-Run I Size (in) I 4 i Y I 8.750 I. I. , I Cum Prog(ft) 'RPM MinIMax ¡WOB Min/Maxl I ! I : BHA Bha No: 4 Depth In: 9,953.0 Bha Weight: 0 Bha Type: CLEAN OUT Depth Out: 9,953.0 Wt Below Jars: Component Component Detail Jts Length Cum Length aD ID Blade OD Bend Angle Connection P/B (ft) (ft) (in) (in) (in) (0) Size (in) Type BIT Smith PDC 1 0.80 0.80 8.750 2.060 4.500 REG P STAB Integral Blade Stabilizer 1 4.08 4.88 6.590 2.810 8.440 4.500 IF B COLLAR NM FLEX DRILL COLLAR 1 31.14 36.02 6.870 2.875 4.500 IF B HOLE OPENE Mill / Drill 1 6.06 42.08 6.500 2.810 8.750 4.500 IF B COLLAR NM FLEX DRILL COLLAR 1 31.09 73.17 6.830 2.875 4.500 IF B STAB Integral Blade Stabilizer 1 4.75 77.92 6.770 2.810 8.500 4.500 IF B COLLAR NM FLEX DRILL COLLAR 1 30.79 108.71 6.390 2.875 4.500 IF B HWDP HWDP 15 449.83 558.54 5.000 3.000 4.500 IF B )JAR JAR 1 31.00 589.54 6.450 2.750 4.500 IF B Printed: 12/11/2002 6:05:18AM Operator: BP EXPLORATION Well: L-02 ) Field: PRUDHOE BAY Bha No: 4 Bha Type: Component Depth In: CLEAN OUT Depth Out: ¡ Component Detail !HWDP HWDP Type: Time/Loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: LSND 16:00/PIT 9,953.0 (ft) 106 (OF) 11.10 (ppg) 41 (s/qt) (ppg) 13 (cp) 22 (lb/100fF) 9.3 From-To Hrs Phase Op. Depth (hr) 00:00-01 :00 1.00 INT1 5,000 01 :00-02:00 I 1.00 INT1 5,000 I 02:00~Ö4:30 I 2.50 INT1 739 04:30-05:30 1.00 INT1 05:30-06:00 0.50 1 INT1 \ ) 06:00-06:30 0.50 INT1 06:30-07:00 0.50 INT1 , I 07:00-20:30 I 13.501 INT1 9,944 CASE CASE CASE I CASE I I CASE 1 !BOPSU I i CASE I I I CASE Task 20:30-22:00 1.50 INT1, CASE , 9,953 \~ ,j ,l 10 see gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: Activity POH CIR POH BHPULD RU WEAR RU RIH WASH I I Held PJSM. POOH LID 5" DP from 5,700' to 5,000'. I Pumped and Spotted 200 bbl Steel Seal Pill from 5,000' to 2,500'. I Pump Rate 7 bpm, 900 psi. PÖOH L I D5,í DPfrom5,000'to 739'. I I I POOH, Broke Out and LID Clean Out BHA. I I Cleared and Cleaned Rig Floor. i I M I ÜRetrieving Tool. RIH, Latched and Pulled Wear Bushing. LID I Retrieving Tool. ¡Held PJsM. R 1 U 7" Casing Equipment. i M 1 U and RIH wI 7" 26# L-80 BTC-M Casing to 9_5/8íí Casing Shoe at 12,581' at 80' I min, Broke Circulation and Staged Pumps Up to 5 bpm, 1350 psi, No Losses. RIH to 4,000' at 60' I min, Broke Circulation every i 15 Joints, Pump Rate 2.5 bpm. RIH at 20' I min while Circulating. RIH I to 6,500' at 60' I min, Broke Circulation every 10 Joints, Pump Rate i 2.5 bpm. RIH at 20' I min while Circulating. Circulated fl 30 minutes at 6,500'. RIH to 8,500' at 60' I min, Broke Circulation every 10 Joints, Pump Rate 2.5 bpm. RIH at 20' 1 min while Circulating. RIH to 9,300', Broke Circulation at 9,300', Pump Rate 3 bpm, No Losses. Circulated Down 3 Joints from 9,300' to 9,450', Pump Rate 3 bpm, 650 psi, No Losses. RIH to 9,944', Tagged Up at 9,944'. 'Staged Pumps up to 7 bpm, 950 psi, No Losses. Washed Down and Worked Casing Down to 9,953' at 6' 1 hr. String Weight Up 300,000#, 'String Weight Down 175,000#. Ran a Total of 242' Joints of 7" 26# L-80 BTC-M Casing, M I U Torque 9,000 ft I Ibs. 7" Casing Set As Follows: Item Float Shoe 1 Jt 7" 26# L-80 BTC-M Csg Float Collar 1 Jt 7" 26# L-80 BTC-M Csg Baffle Collar 112 Jts 7" 26# L-80 BTC-M Csg HES 2nd Stage Cementer 128 Jts 7" 26# L-80 BTC-M Csg ) BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: BHA 9,953.0 Bha Weight: 9,953.0 Wt Below Jars: ; Jts Length ICum Length! 00 i 10 ¡Blade ODiBend Angle (ft) ¡ (ft) ¡(in) 1 (in) 'I (in) (0) 5 149.46 i 739.00 I 5.000 ¡ 3.000, Drilling Fluid 6 (lb/100fF) I Ca: 9 (lb/100ft2) K+: 2.4 (cc/30min) II CaCI2: 180 (OF) . NaCI: 5.5 (cc/30min) i CI-: 1 (/32") , Sand: 19.00 (ppb) HGS: (ppb) LGS: (mL) Pf/Mf: o 60 (mg/L) (mg/L) (%) (%) 450 (mg/L) 0.25 (%) 123.29 (ppb) 39.24 (ppb) 0.08/1.5 (mL/mL) Opèrations. Summary Code NPT I P P P P P P P P P :) Exhibit VI-4 b Report: 12 Date: 12/10/2002 Connection Size (in) Type 4.500 IF P/B B ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (mV) 12.70 (%) 3.0 (%) 84.1 (%) I (bbl) (bbl) (bbl) 16.1 (bbl) Operation Length 1.65' 40.90' 1.00' 40.12' 0.97' 4,608.11 ' 2.35' 5,247.04' Depth 9,953.00' 9,907.65' 9,906.65' 9,866.53' 9,865.56' 5,255.63' 5,253.28' 0.00' Printed: 12/11/2002 6:05: 18 AM Operator: BP EXPLORATION ,Well: L-02 )Field: PRUDHOE BAY From-To Hrs Phase Task Op. Depth (hr) 22:00-00:00 2.00 INT1 CASE 9,953 From-To Hrs Phase ¡ Task Op. Depth (hr) 00:00-02:30 2.50 INT1 CEMT 9,953 \ ,,) Activity Activity ) BP EXPLORATION ') Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: Operations Summary Code NPT Operation CIR CMT 02:30-03:00 0.50 INT1 : CEMT CIR P 9,953 03:00-04:00 · 1.00 INT1 . CEMT I CMT P 9,953 ¡ ,Ii Exhibit VI-4 b Report: 12 Date: 12/10/2002 P Circulated to Cool and Condition the Mud and Clean the Hole. Pump Rate 7 bpm, 950 psi. No Losses. After 3 Bottoms Up, Shut Down Pumps, RID Franks Tools and M I U Cement Manifold. Established Circulation, Pump Rate 7 bpm, 950 psi. Reciprocated the Pipe 15' While Circulating. 06:00 Update Code NPT ' Operation I P I Held PJSM wI Dowell Crews, RigCrews and Peak Truck Drivers. I Switched over to Dowell. Pumped 5 bbls of Water to Clear the Lines of Air. Shut in Cement Manifold and Tested Lines to 4,000 psi, OK. Pumped 35 bbls of MudPush at 4 bpm, 700 psi. Dropped Bottom Plug, Pumped 123 bbls (500 sx) 15.8 ppg Expando Cement wI 3.00% 'bwoc High Temp Expanding Agent, 0.45% bwoc Dispersant, 0.20 gal/sk AntiFoam, 2.00 gal/sk GASBLOK, 0.25% bwoc Retarder, 0.20% bwoc Silica Pumped Cement at the Following Rates: Pumped Rate Pressure 20.0 bbls 5.00 bpm 1,050 psi 40.0 bbls 5.00 bpm 825 psi 60.0 bbls 5.00 bpm 700 psi 80.0 bbls 5.00 bpm 650 psi 100.0 bbls 5.00 bpm 650 psi 123.0 bbls 5.00 bpm 650 psi Dropped Top Plug and Displaced wI 5 bbls of Water at 5 bpm, 280 psi. Switched to Rig Pumps and Displaced wI 373 bbls of Mud at the Following Rates: Pumped Rate Pressure 50.0 bbls 7.0 bpm 160 psi 100.0 bbls 7.0 bpm 160 psi 150.0 bbls 7.0 bpm 160 psi 200.0 bbls 4.0 bpm 60 psi 250.0 bbls 7.0 bpm 160 psi 300.0 bbls 5.0 bpm 300 psi 350.0 bbls 5.0 bpm 800 psi 372.0 bbls 3.0 bpm 900 psi Wiper Plug Bumped wI 372 bbls Pumped. Pressured up to 1,400 psi, Held fl 5 minutes, OK. Cement in Place @ 0215 Hrs. Bled off Pressure, Floats Held. Reciprocated Casing while Pumping Cement, Casing Started Hanging Up wI 250 bbls of Displacement Pumped, Landed Casing on Bottom. Pressure up on Casing at 3 bpm to 3,200 psi and Opened HES Cementer. Circulated Bottoms Up at 7 bpm, 550 psi, No Losses. , Circulated Back Apx 20 bbls of Mud Push. Switched over to Dowell. Pumped 15 bbls of Chemical Wash at 5 bpm, 550 psi, Shut in Cement Manifold and Tested Lines to 3,000 psi, ,OK. Pumped 35 bbls of MudPush at 5.5 bpm, 725 psi. Pumped 58 bbls (120 sx) 11.5 ppg LiteCRETE Cement wI 41.00% bwoc Extender, 1.00% bwoc Dispersant, 0.20 gal/sk AntiFoam, 21.00 %bwoc Stabilizer, 0.20% bwoc Fluid Loss, 1.00% bwoc Accelerator. Pumped Cement at the Following Rates: Pumped Rate Pressure 10.0 bbls 5.70 bpm 1,040 psi 20.0 bbls 5.70 bpm 980 psi 30.0 bbls 5.70 bpm 930 psi 40.0 bbls 5.70 bpm 930 psi 50.0 bbls 5.70 bpm 950 psi 58.0 bbls 4.00 bpm 600 psi Printed: 12/11/2002 6:05:18 AM Operator: BP EXPLORATION Well: L-02 ') Field: PRUDHOE BAY l From-To Hrs Phase: Task Op. Depth (hr) 03:00-04:00 1.00 INT1 CEMT 9,953 Activity CMT ) BP EXPLORATION ) Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: 06:00 Update Code NPT Operation Report: 12 Date: 12/10/2002 Exhibit VI-4b P Dropped Closing Plug and Displaced wI 5 bbls of Water at 6 bpm, 660 psi. Switched to Rig Pumps and Displaced wI 195 bbls of Mud at the Following Rates: Pumped Rate Pressure 50.0 bbls 7.0 bpm 520 psi 100.0 bbls 7.0 bpm 540 psi 150.0 bbls 7.0 bpm 500 psi 195.0 bbls 3.5 bpm 300 psi Closing Plug Bumped wI 195 bbls Pumped. Pressured up to 1,450 psi and Closed HES Cementer, Increased Pressure to 1,700 psi and Held fl 5 minutes, OK. Cement in Place @ 0400 Hrs. Bled off Pressure, Cementer Closed. Held PJSM. RID Cement Head and Lines. Cleaned and Cleared Rig Floor. PJSM.N I D BOP Stack. 04:00-05:00 1.00 INT1 : CEMT I RD P 9,953 I I 05:00-06:00 1.00 INT1 IBOPSU] ND P 9,953 N I D BOP Stack Formation SAG RIVER Lithology SANDSTONE Item DIESEL Company FAIRWEATHER ) SPERRY-SUN " SPERRY-SUN Phase PRE SURF INT1 TOTALS Prod % Total 25.50 78.5% 65.00 100.0% 158.00 91.1% 248.50 91.7% PJSM held for all Operations Mud Log Information i Form. Top MD. 9,950.0 (ft) I Bkgrnd Gas I Conn. Gas Materials I Consumption Usage I On Hand I Item 2500¡ 8070 Personnel Company II..... Units GAL No. 2 4 2 Hours (ppm) I Trip Gas (ppm) Pore. Press (ppm) (ppg) Units . Usage : On Hand I DOYON BAROID No. : Hours 26: 2: ! ¡ Company No. Hours DOYON 5 PETROTECHNICAL RESOUR 1 Cumulative' Phase Breakdown Planned Change of Scope NPT % Total! WOW % Total Prod % Total NPT % Total I WOW I 7.00 21.5% I I 15.50 8.9% I 15.50 5.7%1 Total I Total Cost Hours I USD . I 32.50 I 122,630.00 65.00 i 461,345.58 173.501 771~086.19 271.0011,355,061.7 % Total 7.00 2.6% 0.00 0.0% Remarks 0.00 0.0% . 0.00 0.0% Printed: 12/11/2002 6:05:18 AM ) BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: Current Well Status Casing Size: 7.000 (in) Costs in: USD Casing (MD): 9,953.0 (ft) Daily Mud: 2,255 Next Casing Size: 4.500 (in) Cum. Mud: 261,833 Next Casing (MD): 13,842.0 (ft) Daily Well: 284,125 Next Casing (TVD):8,857.0 (ft) Cum. Well: 1,639,187 Operator: BP EXPLORATION Well: L-02 ) Field: PRUDHOE BAY Depth MD: 9,953.0 (ft) Est. TVD: 8,733.0 (ft) Progress: (ft) Auth Depth: 13,842.0 (ft) Hole Size: 8.750 (in) DOL/DFS/Target: 11.30/10.80/28.68 Geologist: Ray Engineer: Triolo Supervisor: MADSEN / GALLOWAY Current Status: 24hr Summary: 24hr Forecast: Comments: Program: Weather: ) Exh i bit VI-4 b Report: 13 Date: 12/11/2002 Rig Accept: 17:00 11/30/2002 Rig Release: Spud Date: 12/1/2002 WX Date: Elev Ref: SEA LEVEL KB Elev: 82.00 (ft) Tot. Personnel: 42 Cost Ahead 400,000 USD, Days Ahead 3.00 5 deg, 2 mph SSW RIH wI 6-1/8" Dirc BHA Set & Cmt'd 7" Csg @ 9,953', Chg'd Pipe Rams, Tst'd BOPE, PIU 4" DP RIH w/6-1/8" Dirc BHA, Tst Csg, Drlg Out, Displ, FIT, Drlg NO ACCIDENTS, NO INCIDENTS, NO SPILLS, 5 deg, 2 mph SSW, Visibility 20.2 Miles Last Spill Drill: 12/11/2002 Regulatory Agency Insp: N KICK WHILE DRILL (D2) 12/7/2002 Pump Slow Pump Rates (Circ) Stroke Rate pressureO Days Since Last DAFWC: 344 Last Csg Test Press.: 3,500 (psi) Last BOP Press. Test: 12/11/2002 Next BOP Press. Test: 12/18/2002 Last Divertor Drill (D3): 12/1/2002 No. Stop Cards: FIRE: 12/11/2002 LOT TVD: LOT EMW: MAASSP: Test Pressure: . ') Kick Tolerance: " Kick Volume: 2,580.0 (ft) 13.24 (ppg) 287 (psi) 475 (psi) (ppg) (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM Min.: RPM DH: Torq. on Bottom: Torq. off Bottom: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: Type: LSND 10 sec gels: Time/Lac: 01 :OO/PIT 10 min gels: Depth: 9,953.0 (ft) Fluid Loss: Temp: 84 (OF) HTHP Temp: Density: 11.10 (ppg) HTHP WL: Funnel Visc.: 40 (s/qt) Cake: ECD: (ppg) MBT: PV: 13 (cp) Lime: YP: 19 (lb/100ft2) PM: pH: 9.5 From-To Hrs Phase Task Activity Op. Depth (hr) 00:00-02:30 2.50 INT1 CEMT CMT 9,953 )1 l HSE & WellControl All Free Days: 12 Last Trip Drill (D1): Last Safety Meeting: 12/8/2002 12/12/2002 Non-compliance Issued: N WELL KILL (D5): 12/412002 Slow Pump Rates (Choke) "1 Slow Pump Rates (Kill) Stroke Rate PressureO. Stroke Rate PressureO Operational Parameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) (hr) Drilling· Fluid 6 (lb/100ft2) I Ca: 11 (lb/100ft2) I K +: 2.6 (cc/30min)! CaGI2: 180 CF) ! NaGI: 5.5 (cc/30min) ¡ CI-: 1 (/32") Sand: 19.00 (ppb) HGS: (ppb) LGS: 0.15 (mL) Pf/Mf: Operations Summary Code NPT Pump Status - Drilling and Riser PumPIType\ Eff. ¡Strokes I Liner Size \Circ. Rate 110 1 0: O¡ 0 I I i r ! , I' ! I I I ! I ': I ! 60 (mg/L) (mg/L) (%) (%) 450 (mg/L) 0.10 (%) 121.81 (ppb) 41.06 (ppb) 0.10/2.5 (mL/mL) ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: . Lost Downhole: . Lost Surface: (mV) 12.80 (%) 3.0 (%) 84.0 (%) I (bbl) (bbl) (bbl) (bbl) Operation Held PJSM wI Dowell Crews, Rig Crews and Peak Truck Drivers. Switched over to Dowell. Pumped 5 bbls of Water to Clear the Lines of Air. Shut in Cement Manifold and Tested Lines to 4,000 psi, OK. Pumped 35 bbls of MudPush at 4 bpm, 700 psi. Dropped Bottom Plug, Pumped 123 bbls (500 sx) 15.8 ppg Expando Cement wI 3.00% bwoc High Temp Expanding Agent, 0.45% bwoc Dispersant, 0.20 P Printed: 12/12/2002 5:36:13 AM ) BPEXPLORATION ,) Daily Operations Report Exhibit VI-4 b Operator: BP EXPLORATION Rig: DOYON 14 Report: 13 Well: L-02 Event: DRILL +COMPLETE Date: 12/11/2002 J Field: PRUDHOE BAY Well Type: Operations Summary From-To Hrs : Phase ! Task Activity Code NPT Operation Op. Depth (hr) 00:00-02:30 2.50 INT1 CEMT· CMT P gal/sk AntiFoam, 2.00 gal/sk GASBLOK, 0.25% bwoc Retarder, 9,953 0.20% bwoc Silica Pumped Cement at the Following Rates: Pumped Rate Pressure 20.0 bbls 5.00 bpm 1,050 psi 40.0 bbls 5.00 bpm 825 psi 60.0 bbls 5.00 bpm 700 psi 80.0 bbls 5.00 bpm 650 psi 100.0 bbls 5.00 bpm 650 psi 123.0 bbls 5.00 bpm 650 psi Dropped Top Plug and Displaced wi 5 bbls of Water at 5 bpm, 280 psi. Switched to Rig Pumps and Displaced wI 373 bbls of Mud at the Following Rates: Pumped Rate Pressure 50.0 bbls 7.0 bpm 160 psi 100.0 bbls 7.0 bpm 160 psi 150.0 bbls 7.0 bpm 160 psi 200.0 bbls 4.0 bpm 60 psi 250.0 bbls 7.0 bpm 160 psi 300.0 bbls 5.0 bpm 300 psi 350.0 bbls 5.0 bpm 800 psi 372.0 bbls 3.0 bpm 900 psi Wiper Plug Bumped wI 372 bbls Pumped. Pressured up to 1,400 psi, Held fl 5 minutes, OK. Cement in Place @ 0215 Hrs. Bled off I I Pressure, Floats Held. Reciprocated Casing while Pumping Cement, I Casing Started Hanging Up wi 250 bbls of Displacement Pumped, I I Landed Casing on Bottom. ) 02:30-03:00 ! 0.50 INT1 CEMT CIR P Pressured up on Casing at 3 bpm to 3,200 psi and Opened HES 9,953 I I Cementer. Circulated Bottoms Up at 7 bpm, 550 psi, No Losses. Circulated Back Apx 20 bbls of Mud Push. 03:00-04:00 1.00 ' INT1 CEMTi CMT P Switched over to[)owell~ Pumped 15 bbls of Chemicàl VVash ate> 9,953 bpm, 550 psi, Shut in Cement Manifold and Tested Lines to 3,000 psi, OK. Pumped 35 bbls of MudPush at 5.5 bpm, 725 psi. Pumped 58 I bbls (120 sx) 11.5 ppg LiteCRETE Cement wI 41.00% bwoc Extender, ! 1.00% bwoc Dispersant, 0.20 gal/sk AntiFoam, 21.00 %bwoc I Stabilizer, 0.20% bwoc Fluid Loss, 1.00% bwoc Accelerator. Pumped Cement at the Following Rates: Pumped Rate Pressure 10.0 bbls 5.70 bpm 1,040 psi 20.0 bbls 5.70 bpm 980 psi 30.0 bbls 5.70 bpm 930 psi 40.0 bbls 5.70 bpm 930 psi 50.0 bbls 5.70 bpm 950 psi 58.0 bbls 4.00 bpm 600 psi Dropped Closing Plug and Displaced wI 5 bbls of Water at 6 bpm, 660 I psi. Switched to Rig Pumps and Displaced wi 195 bbls of Mud at the . Following Rates: Pumped Rate Pressure 50.0 bbls 7.0 bpm 520 psi 100.0 bbls 7.0 bpm 540 psi 150.0 bbls 7.0 bpm 500 psi 195.0 bbls 3.5 bpm 300 psi Closing Plug Bumped wI 195 bbls Pumped. Pressured up to 1,450 psi and Closed HES Cementer, Increased Pressure to 1,700 psi and Held fl 5 minutes, OK. Cement in Place @ 0400 Hrs. Bled off Pressure, Cementer Closed. 04:00-04:30 0.50 INT1 CEMT RD P Held PJSM. RID Cement Head and Lines. Cleaned and Cleared Rig 9,953 Floor. ,) Printed: 12/12/2002 5:36: 13 AM Operator: BP EXPLORATION _ Well: L-02 ) Field: PRUDHOE BAY From- To I Hrs Phase ! Task Op. Depth (hr) I 04:30-05:30 1.00 INT1 IBOPSU 9,953 05:30-06:30 1.00 INT1 WHSU 9,953 06:30-07:30 9,953 07:30-08:30 9,953 08:30-10:00 9,953 19:00-11 :00 11:00-14:00 14:00-14:30 14:30-18:00 1.00 INT1' WHSU , I I I 1.00 INT1 i WHSU I I. ¡ 1.50 INT1 IBOPSUI I : 1.00 PROD1IBOPSU! I I Iii 3.00iPROD1IBOPSU¡ , I I I ! I i 0.50 IPROD1 iBOPsul Ii! 3.50 IPRO[)1IBOPSU1 ¡ ¡ I I I I I I ! ) 18:00-18:30 0.50 iPROD1 iBOPSU: 18:30-19:00 0.50 IPROD1: DRiLL I 19:00-22:00 3.00 IPROD1! DRILL 22:00-23:00 1.00 PROD1! bRILL- I 23:00-00:00 1.00 PROD1! DRILL I From-To I Hrs I Phase Task Op. Depth I (hr) I 00:00-00:30 I 0.50 IPROD1 DRILL I I I , . I , 00:30-03:00 2.50PROD1· DRILL ,) BPEXPLORATION Da i lyO pe rati on s Report Rig: DOYON 14 Event: DRI LL +COMPLETE Well Type: Operations· Summary Activity Code' NPT Operation Exhibit VI-4 b Report: 13 Date: 12/11/2002 ND P MISC P MISC P MISC P NU P MAINT P MAINT P TSTPRS P TSTPRS P Held PJSM. N I D BOP Stack. Installed and Set7" Casing on Slips. P I U Weight 195,000#, Biock Weight 55,000#, Weight to Energize Slips 30,000#, Set 110,000# on Slips. Held PJSM and Checked Cellar wI Gas Detector. Cut off 1" Casing and Prepped for Packoff. FMC Installed 7" x 9-5/8" Packoff. Tested Packoff to 4,000 psi fl 10 minutes, OK. Held PJSM. N I U BOP Stack. Changed Out Upper Pipe Rams to 2-7/8" x 5" Variable Rams. R I U and Pressured up on 9-5/8" x 7" Annulus, Formation Broke Down at 350 psi, Pumped 5 bbls of Mud into Annulus at 1.5 bpm, 450 psi. Held PJSM. Changed Out Saver Sub on Top Drive from 4-1/2" IF to 4" HT. M I U Double Valve on 9-5/8" x 7" Annulus. Cleaned Mud Pits and Loaded 4" DP into Pipe Shed. R I U Test Joint and Equipment to Pressure Test BOPE. Held PJSM. Tested BOPE. Tested Upper and Lower Rams, Blind Rams, Stand Pipe Manifold, Choke Manifold, Valves, HCR, Kill Line, Choke Line, Floor Valves and IBOP to 3,500 psi High I 250 psi Low. I Tested Annular Preventer to 3,000 psi High I 250 psi Low. All Tests Held fl 5 Min. All Pressure Tests Held wI No Leaks or Pressure Loss. Witnessing of BOPE test Waived by AOGCC Rep John Crisp. Pumped 5 bbls of Mud down 9-5/8" x 7" Annulus, 1.5 bpm, 400 psi RI DBOPE Test Equipment Ran and Set Wear Bushing. TSTPRS P PU P Held PJSM. R I U Equipment to Run 4" HT DP. RIH I U, Drifted and RIH wI 120 Joints Of 4" HT DP. Pumped 5 bbls of Mud down 9-5/8" x 7" Annulus, 1.5 bpm, 400 psi Held PJSM. Slipped and Cut Drilling Line, Serviced Top Drive. P RIGSER P POH POOH and Racked 4" HT DF' in Derrick. P Activity I 06:00 Update NPT I ... Operation I Held PJSM. POOH wI 4" HT DP and Racked in Derrick. I SIMOPS: Held PJSM wI Hot Oil Crew, R I U Hot Oil to 9-5/8" x 7" I Annulus to Freeze Protect Pressure Tested Line to 3,500 psi, OK. I Started Pumping at 0.5 bpm, 350 psi, Bullheaded Fluid into Annulus. I Staged Pump up to 5 bpm, 1,200 psi. Pumped 56 bbls of Dead Crude I down 9-5/8" x 7" Annulus to Freeze Protect to 2,200'. RID Hot Oil. I Held PJSM. M I U BHA. 6-1/8" HTC DP0796 PDC Bit,Ser# 7101485, 'dressed wI 6x10 jets, 4-3/4" SperryDrill Lobe 4/5 6.3 Stg Motor wI 1.50 deg Bent Housing, NM Float Sub, GR-Res, DM, SLD-CTN, PWD, Hang Off Collar, 3 x Flex Collars, Drilling Jars, XO. Total BHA Length - 241.71'. Set Motor Bend and Oriented to MWD. M I U Top Drive and ,Tested MWD Tools, wI 250 gpm, 1,050 psi, OK. Cleared Rig Floor. Sperry Sun Loaded Radioactive Sources into MWD Tools. RIH wI 6-1/8" Directional BHA on 4" DP to 3,000'. Picked up Single Joints of DP from Pipe Shed. Code POH P BHPULD P 03:00-03:30 0.50PROD1 DRILL' BHPULD P 03:30-06:00 2.50 PROD1 DRILL RIH RIH wI 6-1/8" Dire BHA ,) P Printed: 12/12/2002 5:36:13 AM Operator: BP EXPLORATION Well: L-02 ) Field: PRUDHOE BAY Formation SAG RIVER Lithology SANDSTONE Item DIESEL c;ompany FAIRWEATHER SPERRY-SUN SPERRY-SUN Phase PRE SURF INT1 PROD1 TOTALS Prod % Total 25.50' 78.5% 65.00 100.0% 168.00 91.6% 14.00 100.0% 272.50 92.4% PJSM held for all Operations ) Ji No. 2 4 2 ) BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: Mud Log Information ! Form. Top MD. 9,950.0 (ft) I Bkgrnd Gas . I Conn. Gas MaterialsI Consumption Usage liOn Hand I Item 2710 7460 Personnel Company Company ') (ppm) (ppm) ! Trip Gas Pore. Press ¡ Units ¡GAL Units Hours DOYON BAROID No. I Hours 26] DOYON 2! PETROTECHNICAL RESOUR Cumulative Phasé. Breakdown Planned Change of Scope NPT % Total WOW % Total Prod % Total NPT % Total WOW % Total 7.00 21.5% 15.50 8.4% 15.50 5.3% 7.00 2.4% 0.00 0.0% Remarks 0.00 0.0% 0.00 0.0% Exhibit VI*4 b Report: 13 Date: 12/11/2002 (ppm) (ppg) Usage ¡ On Hand I Total Hours 32.50 65.00 183.50 14.00 295.00 I No. Hours Total Cost USD 122,630.00 462,016.58 1,054,539.9 1,639,186.5 Printed: 12/12/2002 5:36:13 AM "- '~ Exhibit VI-5: L-110 Well InteQrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: 9/15/2001 6-3/4" Schrader Bluff Penetration Casing Diameter: 5-1/2" Well Status as of 8/2003: Oil Producer Gas Lift Cement Logs Across Schrader Bluff: None Comments: The 5-1/2" primary cement job consisted of 256 sacks (612 ft3) of cement. Floats held and the plug bumped with 2850 psi. The 5-1/2" cement job was designed to cover the Schrader Bluff sands. With a gauge hole, 2668'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 977'MD of cement above the top of the Na sand. Additional Information: Well Diagram - Exhibit VI-5 a Drilling Daily Reports (Cementing) - Exhibit VI-5 b ~' -- ~. ------ TREE = 3-1/8" 5M CIW WELLHEA D = 11" FI'v'k: 'ACTÜÄt6ï~;" ... 'KËf""êLéi ,;; .." ...^' ^" ,,,. 7'1:1 Ó;· BF. I3..EV = ,., 54.82' "1~::~~ I'~i'~~"~ ~~.....,....."..,. E3f3ÚÕ¡'¿§' ') 17-5/8" CSG, 29.7#, L-80, ID= 6.875" 1-1 2819' Minimum ID = 2.75" @ 2310' 3-1/2" HES SSSVN PERFORATION SUMMARY REF LOG: ___________ AI\X3LE AT TOP PERF: 11 @ 8467' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL OpnlSqz DATE 2-1/2" 6 8467-8521 0 09/15/01 ) I 5-1/2" CSG, 15.5#, L-80, BTC, ID= 4.950" H 13-1/2" TBG, 9.2#, L-80, IBT-M, .0087 bpf, ID= 2.992" H 15-1/2" X 3-1/2" CSG XO, ID = 2.968" H 8302' 8303' 8315' 1 FBTD H 8893' 13-1/2" CSG, 92#, L-80, NSCT, ID = 2.992" H 8992' L-110 a.','." . ~ I L IT ~) ~ SAFr )oJOTES: =---1 1015' 1-17-5/8" TAM FDRTCOLLAR 1 2310' 1-13-1/2" HES XDB BVN, ID= 2.75" 1 ~ L GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 4 4259 3433 49 KBG-2 DOME B1M 16 10/18/01 3 6969 5220 38 KBG-2 SO B1M 16 10/18/01 2 8107 6219 14 KBG-2 DMY B1M 0 08/02/01 1 8226 6335 8 KBG-2 DMY B1M 0 08/02/01 I 8251' 1-13-112" HES X NIP, ID = 2.75" 1 --i 8304' I-iTOPOF BKR FBR,ID= 4.00" 1 I 8315' 1--13-112" BKR SEAL ASSY, ID = 3.00" 1 1 8366' 1-43-112" HES X NIP, ID = 2.75" 1 I 8387' 1-13-112" HES X NIP, ID = 2.75" 1 1 8428' 1-120' PUPJT WI RA TAG I 8821' 1-410' PUPJT WI RA TAG I DATE REV BY co I'vTv1ENTS DA. TE REV BY CONIrvENTS ....~/02/01 CH'KAK ORGINAL COtvPLETION } 5/01 J UvVKK PERFS 12/30/02 DAC/KK GL V CORRECTIONS 04/08/03 DRS/TP TV D'MD CORRECllONS BOREA LIS LN rr WELL: L-110 PERrv1rr No: 2011230 AA No: 50-029-23028-00 SEC 34, T12N; R11E 2365' NSL & 3772' WEL Exhibit VI-5 a ) BP EXPLORATION Dally Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT CurrenfWellStatus Depth MD: 9,020.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 7,186.0 (ft) Casing (MD): 2,819.68 (ft) AFE No: 5M4022 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,380,000 Auth Depth: 9,099.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,386 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 180,961 DOLlDFS/Target: 15.63/15.21/13.10 Liner (MD): Daily Well: 60,707 Geologist: Liner Top (MD): Cum. Well: 1,874,649 Engineer: Allen Sherritt Supervisor: Decker I Anthony Operator: BP EXPLORATION Well: L-110 J Field: PRUDHOE BAY ) Exhibit VI,.5 b Report: 16 Date: 7/31/2001 Rig Accept: Rig Release: Spud Date: Elev Ref: 13:307/15/2001 7/15/2001 SEA LEVEL KB Elev: 77.10 (ft) Program: Tot. Personnel: 30 Cost Ahead -200,000 USD, Days Ahead -4.0 Current Status: PIU 3 1/2" Seal Assy. & RIH 24hr Summary:Wiper trip to TD. POH & LID drill string. RIU & run prod csg. 24hr Forecast: RIU & run 3 1/2" production tubing. Run LOT & freeze protect Comments: No Accidents, No Incidents, & No Spills.. Weather = 35 Deg WI wind E @ 3 mph. Days Since Last DAFWC: 985 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/29/2001 Next BOP Press. Test: 8/512001 Last Divertor Drill (D3): 7/16/2001 No. Stop Cards: Fire: 7/29/2001 LOT TVD: LOT EMW: MAASSP: Test Pressure: ) Kick Tolerance: )1 Kick Volume: 2,561.0 (ft) 13.70 (ppg) 412 (psi) 585 (psi) 10.60 (ppg) 26.3 (bbl) HSE&WellControl All Free Days: 3/16/2001 Last Envir. Incident: 15 Last Accum. Drill (D4): 7/20/2001 Last Spill Drill: 7/31/2001 Regulatory Agency Insp: N Kick While Drill (D2): 7/26/2001 Pump -'SlowPump Rates (tire) '! Stroke Rate Pressure(psi) 28 i 508 42 I 643 42 i 640 42 l 640 ¡ Operational Parametørs Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: 1 1 2 2 Last Trip Drill (D1): Last Safety Meeting: 7/31/2001 7/31/2001 Non-compliance Issued: N Slow Pump Rates (Choke) Slow Pump Rates (Kill) Stroke Rate I Pressure(psi) Stroke Rate Pressure(psi) I i ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 97 (hr) Wt Below Depth Out I Jar (ft) I 9,020.0 IHoLE OPENER, BIT SUB, DRILL COLLAR,NM STRING STAB, 2 x DRILL COLLÄR, !HWDP, DRILLING JAR, 13 x HWDP, xo Drilling Fluid 7 (lb/100ft2) : Ca: 20 (lb/100ft2) K+: 3.3 (cc/30min) CaCI2: 200 (OF) NaCI: 8.6 (cc/30min) CI-: 1 (/32") Sand: 17.00 (ppb) HGS: (ppb) LGS: (mL) Pf/Mf: No¡ I I 4 ! CLEAN OUT Weight Type Type: Time/Loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: LSND 18:00/PIT 9,020.0 (ft) CF) 10.60 (ppg) 50 (s/qt) (ppg) 20 (cp) 26 (lb/100ft2) 7.6 } ,I'· 10 see gels: 10 min gels: I Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) BHA Pump Status - Drilling and Riser Pump ITypel Eft. I Strokes ¡Liner SizeCirc. Rate I Ii 0 I: 0 \ 0 0 I Ii! I I I ! I I 1 I I I I i I Description 40 (mg/L) (mg/L) (%) (%) 800 (mg/L) (%) 94.08 (ppb) 41.68 (ppb) 14.50 (mLlmL) i ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (bbl) (bbl) 41.0 (bbJ) (bbJ) (mV) 11.00 (%) 2.0 (%) 87.0 (%) I Printed 8/1/2001 61432 AM Operator: BP EXPLORATION , Well: L-110 ) Field: PRUDHOE BAY From-To Hrs Phase ! Task hh:mm (hr) ! 00:00-01 :00 1.00 INT1 : CASE 01 :00-02:30 1.50 , INT1 I CASE 02:30-08:30 6.00 INT1 CASE 08:30-09:00 0.50 INT1 CASE 09:00-13:00 4.00 INT1 CASE I 13:00-13:30 0.50 INT1 CASE i I I 13:30-19:00 5.50 INT1 CASE! 1.ÖO I i 19:00-20:00 INT1 eASEl I 20:00-21 :00 1.00 ¡ INT1 CASE I 21 :00-21 :30 0.50 INT1 I CASE 21 :30-23:30 2.00 INT1 CASE 23:30-00:00 0.50 INT1 CASE I I I ) i,~. ' BP EXPLORATION ' Dally OperaíionsReport R~: NABORS9ES Event: DRILL+COMPLETE Well Type: DEVELOPMENT Operations. Summary Activity Code I NPT Operation ! BHALD N BHALD N RUN N RUN P RUN P CIR P RUN P CIR P RUN Þ RUN P CIR P CMT P Exhibit VI-5b Report: 16 Date: 7/31/2001 DPRB Can't - LID BHA. DPRB Clear floor, pull wear bushing, change out bails, & R/U to run csg. OPRB PJSM. R/U & re-run 3 1/2" production csg. Note - Cut shoe track & replace float equipment & centralizers Rig down 3 1/2" casing tools & rig up 5 1/2" casing tools. Can't RIH wI 5 1/2" 15.5#,L-80, BTC-M casing to 2880'. up circulating head & circulate 150 % liner volume (4 1/2 BPM@ 373 psi). Can't RIH wI 5 1/2" casing to 8228'. Obstuctiol1. Work pipe - no success. PIU &M/U swedge & circulating line. Wash csg thru tight spot 8228' to 8298'. Pump rate = 3 BPM @ 680 psi & lost 10 Bbls mud. Can't RIH wI 5 1/2" casing to 8967'. M/U landing joint & land Hgr. in casing head. Production casing landed @ 8992'. R/U cement head & lines. Break circulation & circulate hole. Displace hole to 10.4 ppg mud. PJsM. Pump 5 Bbls & presure test pumps & lines to 4000psi- ok: Pump 25 Bbl CW 100 & drop bottom plug. Pump 40 Bbl spacer (@ 11.20 ppg). 06:00 Update: ) Mix & pump cement job for 3 1/2" X 5 1/2" production casing. Full Ret Bumped plug & cmt in place @ 0200 hrs. Floats -OK , RID cement svc's & LID landing joint. Set pack-off, RILDS, & pressure test - OK. Item I Units GAL l\IIaterialsIConsÙfllption Usage. I On Hand litem 1512 4824 Personnel Company Usage I On Hand DIESEL Company BP AMOCO NABORS Anchor I Tension i R.ig Heading: VOL: Swell Height: 2 Comments: No. I Hours 21 12.ÖO BAROIO 24 12.00 3 4 Sea Heig ht: Sea OiL: Sea Period: Units No. Hours Company i . No. I Hours 12.00 ANADRILL SCHLUMBERGER I if 12.00 Anchoring IMarine 5 I 6 ¡ 7 I I , Rig H~ave: Rig Roll: Rig Pitch: 8 9 10 11 12 Riser Tension:' Riser Angle/Dir.: Current: Current Direction: Cumulative Phase Breakdown Planned Change of Scope Prod % Total NPT % Total WOW % Total Prod % Total' NPT % Total WOW % Total 117.00 98.3% 2.00 1.7% Phase SURF PRE INT1 TOTALS 103.50 69.9% 44.50 30.1 % 220.50 82.6% 46.50 17.4% ) ../ 0.00 0.0% Total Total Cost Hours USD 119.00 0.00 148.00 267.00' 0.00 0.00 0.0% 0.00 0.0% 0.00 0.0% Printed: 8/1/2001 61432 AM ) BP EXPLORATION DailyOperatio ns ··R.e port R~: NABORS9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 9,020.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 7,186.0 (ft) Casing (MD): 2,819.68 (ft) AFE No: 5M4022 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,380,000 Auth Depth: 9,099.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,140 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 182,101 DOL/DFS/Target: 16.63/16.21/13.10 Liner (MD): Daily Well: 452,823 Geologist: Liner Top (MD): Cum. Well: 2,327,472 Engineer: Allen Sherritt Supervisor: Decker I Anthony Operator: BP EXPLORATION Well: L-110 ) Field: PRUDHOE BAY ) Exhibit VI-5 b Report: 17 Date: 8/1/2001 Rig Accept: 13:307/15/2001 Rig Release: Spud Date: 7/15/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Program: Tot. Personnel: 30 Cost Ahead -150,000 USD, Days Ahead -4.0 Current Status: NID BOPE 24hr Summary: Complete long string cement job. Run 3.5" Tbg 24hr Forecast: Land Tbg, test NID - NIU tree, test Freeze protect RDMO Comments: No Accidents, No Incidents, & No Spills.. Weather = 35 Deg WI wind E @ 3 mph. Days Since Last DAFWC: 986 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/29/2001 Next BOP Press. Test: 8/512001 Last Divertor Drill (D3): 7/16/2001 No. Stop Cards: Fire: HSE& Well COntrol All Free Days: 3/16/2001 16 Last Envir. Incident: 7/31/2001 8/1/2001 Last Accum. Drill (D4): 7/20/2001 Last Spill Drill: 7/31/2001 Regulatory Agency Insp: N Kick While Drill (D2): 7/26/2001 PumpSlow'Pump Rates (Circ) Stroke Rate PressureO Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 97 (hr) DriHin9Fluid (lb/100ft2) : Ca: (lb/100ft2) , K+: (cc/30min) CaCI2: (OF) . NaCI: (cc/30min) ¡ CI-: (/32") Sand: (ppb) HGS: (ppb) LGS: (mL) Pf/Mf: 8/1/2001 LOT TVD: LOT EMW: MAASSP: Test Pressure: ) Kick Tolerance: Kick Volume: 2,561.0 (ft) 13.70 (ppg) 412 (psi) 585 (psi) (ppg) (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Type: Time/Loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: LSND 16:00/PIT 9,020.0 (ft) (OF) 8.60 (ppg) 28 (s/qt) (ppg) (cp) (lb/100ft2) 10 see gels: i 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: From-To Hrs Phase Task hh:mm (hr). 00:00-02:00 . 2.00 INT1' CASE' Activity CMT J 02:00-03:00 1.00 INT1' CASE' RD Last Trip Drill (D1): Last Safety Meeting: Non-compliance Issued: N Slow Pump Rates (Choke) Stroke Rate PressureO Slow Pump Ràtes (Kill) Stroke Rate PressureO I I : ] Operåti()nàl·..Pé\ré\meters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: II Pump Status - Drilling and Riser 'PÙmp TypeIËff.·'IStrokes Liner Size I Circ. Rate ! 0 i 0 i O. . 0 i I Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) I (mL/mL) ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: . Cum. Cuttings: Lost Downhole: . Lost Surface: (mV) (%) (%) (%) (bbl) (bbl) 30.0 (bbl) (bbl) Operations Summary Code NPT Operation P . Can't - 3 1/2" X 51/2" production casing cement job. Pump 25 Bbls CW 100, drop bottom plug, pump 40 Bbls Mud Push (@ 11.20 ppg), 109 Bbls liteCRETE cement (@ 12.0 ppg as per program), Drop top plug, swithch to rig pump & displace cement with 203 Bbls filtered sea water. Bump plug & pressure to 2850 psi. Plug down & cement in place @ 0200 Hrs. Bleed pressure & check float equipment - OK. . Rig down cement head, flush stack, break out & lay down landing joint. P Printed 8/2/2001 61956 AM I Con't RIH wI 3 1/2" tbg. Space out 3 1/2' tbg. Operation Inc @ midnight. Pllfi ëxtra jts tbg. M/LJ circulàting head,· brëâk circulation & sting into . PBR. Shut down pumps immediately after seeing pressure increase. : Con't RIH to No Go & mark tbg. 22:30-00:00 1.50 COMP RUNCO P i poH & lay down excess tbg. PIU required pups & tbg hanger. I ! Pressure test control lines to 5,000 - OK. M/U circulating head & ) I i landing joint on tbg hanger. ' 06:00 Update: . Space out 3 1/2" production tubing. Reverse circulate carr inhibitor. Land tubing. Pressure test Tubing & Casing to 4000 psi for 30 min. Shear RP.Pull Ldg. jt. Inst TWC & test NID BOPE Operator: BP EXPLORATION Well: L-110 ) Field: PRUDHOE BAY From-To Hrs hh:mm (hr) 03:00-04:00 1.00 Phase I Task I INT1 j CASE I I coMp IRUNCOI ; I I COMP !RUNCO! I I COMP I CASE i I i COMP ¡RUNcol ! I I I ! I 04:00-05:30 1.50 05:30-14:00 8.50 14:00-15:00 1.00 15:00-21 :00 6.00 21 :00-22:30 1.50 I I COMP RUNCo! I I Item DIESEL Company BP AMOCO NABORS Anchor Tension Rig Heading: VOL: Swell Height: 2 Comments: Activity í ) BP EXPLORATION Daily. Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Operations Summary Code NPT I Report: 17 Date: 8/1/2001 ) Exhibit VI-5 b Operation NU P ¡ i . ... ... . ........ I PJSM. Rig up & set pack-off. RILDS & torque to 450 ft/lbs. FMC I pressure test at 4000 psi - OK. Rig down FMC svc's. !Clear floor& rig up 31/2" tbg equipment. Make up dummy run with ! tubing hanger. ~ PJSM. Run 190Jts. 3 1/2' 9.2#, L-80, IBT-Mod tubing. RU P RUN P PRESS ITest 5.5'; X 3.5" Prod. Csg to 4000psifor 30 minutes - OK. ! PJSM wI Cameo. I¡Simultaneous Operations: 1. RIU Cameo dual control line reels, sheaves and eguipment. Hook I contollines to SSSV and test to 5000 psi.Cont. RIH wI Tbg. 2. Perform LOT on 7 5/8" X 5 1/2" annulus with 10.4 ppg. mud. I Leak off pressure = 492 psi = 14.09 ppg EMW. Established injectivity: 11 BPM @ 850 psi. initial; down to 567 psi after pumping 3 Bbls. , 2 I BPM @ 800 psi and 3 BPM @ 880 psi. Pumped 38 bbls 10.4 mud and 110 bbls seawater to clear lines. Hooked up Hot Oil and pumped 33 bbls dead crude down annulus. Pumped at 1.5 Bpm. Initial pressure 800 psi. Final pressure 1250 psi Bleed pressure, RD Hot Oil. P RUN P CIR P I Units ¡GAL MaterialsF Con$umption Usage . J On ~and I Item 11981 6048 Personnel Company Units Usage ¡On Hand Hours 12.60BAROID 12.00 No·1 Hours .. . Company... ... I No. i Hours 21 12.00 ANADRILL SCHLI.JMBERGER i 21 12.00 i ¡ i I Sea Height: Sea Dir.: Sea Period: Anchoring rMarine 5 I 6 ' 7 I 12 3 Rig Heave: Rig Roll: Rig Pitch: 9 I 10 11 ! I Riser Tension: Riser Angle/Dir.: Current: Current Direction: 4 8 Cumulative Phase Breakdown Planned Change of Scope Prod % Total ¡ NPT % Total WOW % Total Prod % Total· NPT % Total WOW % Total 117.00 98.3% 2.00 1.7% 107.50 70.7% 44.50 29.3% 20.00 100.0% 244.50 84.0%' 46.50 16.0%· 0.00 0.0% Phase SURF PRE INT1 COMP TOTALS ): 0.00 0.0% 0.00 0.0%· 0.00 0.0% Total Hours 119.00 0.00 152.00 20.00 291.00 . 0.00 Total Cost USD Printed: 8/2/2001 6:19:56 AM ) BPEXPLORATION Da ily·O pe rations >Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 9,020.0 (ft) Casing Size: 5.500 (in.) Costs in: USD Est. TVD: 7,186.0 (ft) Casing (MD): 8,991.45 (ft) AFE No: 5M4022 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,380,000 Auth Depth: 9,099.0 (ft) Next Casing (MD): (ft) Daily Mud: Hole Size: Next Casing (TVD): (ft) Cum. Mud: 182,101 DOL/DFS/Target: 17.33/16.91/13.10 Liner (MD): Daily Well: 190,093 Geologist: Liner Top (MD): Cum. Well: 2,517,565 Engineer: Allen Sherritt Supervisor: Decker I Anthony Operator: BP EXPLORATION Well: L-110 ) Field: PRUDHOE BAY ) Exhibit VI-5 b Report: 18 Date: 8/2/2001 Rig Accept: 13:30 7/15/2001 Rig Release: Spud Date: 7/15/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Program: Tot. Personnel: 30 Cost Ahead -137,600 USD, Days Ahead -4.5 Current Status: Mobilize Nabors Rig 9 ES to L-114 24hr Summary: Lnd tbg & PT tbg & csg. NID BOP stack, NIU X-mas tree, rei rig. 24hr Forecast: Comments: One Accident ( non-recordable, first aid only - see Remarks), No Incidents, & No Spills.. Weather = 35 Deg WI wind NW @ 9 mph. Days Since Last DAFWC: 987 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/29/2001 Next BOP Press. Test: 8/512001 Last Divertor Drill (03): 7/16/2001 No. Stop Cards: Fire: LOT TVD: LOT EMW: MAASSP: Test Pressure: ) Kick Tolerance: . Kick Volume: 8/2/2001 I I I 2,561.0 (ft) 13.70 (ppg) 412 (psi) 585 (psi) (ppg) (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Type: Time/loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: LSND 14:30/PIT 9,020.0 (ft) (OF) 8.60 (ppg) 28 (s/qt) (ppg) (cp) (lb/100ft2) HSE&We.IICohtrol All Free Days: Last Envir. Incident: 3/16/2001 17 Last Accum. Drill (04): 7/20/2001 Last Spill Drill: 7/31/2001 Regulatory Agency Insp: N Kick While Drill (02): 7/26/2001 Pump Slow PLJmpRates (Circ) Stroke Rate PressureO 10 see gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: From-To Hrs Phase Task Activity hh:mm (hr) 00:00-01 :00 1.00 COMPRUNCÖ LANDTH Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 97 (hr) Drilling Fluid (lb/100ft2) Ca: (lb/100ft2) K+: (cc/30min) CaCI2: (OF) NaCI: (cc/30min) CI-: (/32") Sand: (ppb) . HGS: (ppb) LGS: (mL) Pf/Mf: 01 :00-02:00 1.00 COMP RUNCO LANDTH 02:00-03:00 1.00 COMPRUNCO LANDTH ) 03:00-05:00 . 2.00 COMP RUNCO LANDTH Last Trip Drill (01): Last Safety Meeting: 7/31/2001 8/212001 Non-compliance Issued: N Slow Pump Rates (Choke) I Stroke Rate PressureO Slow Pump Rates (Kill) Stroke Rate PressureO QperåtiQnàl.·.P·~ran1êters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Pump Status - Drilling and Riser pump,lfypei Eff.. Strokesl.Line,rSize Circ',.Rate i 0 0 I 0 0 ! ' Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ftlmin) Ann. Vel. DP: (ftlmin) (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) I (mL/mL) ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (mV) (%) (%) (%) (bbl) (bbl) (bbl) (bbl) Operations Summary Code NPT Operation P , Can't - Land 3 1/2" tbg & verify spaceout. (string wt = 106 k up & 76 k dn) 'Pick up above PBR & reverse circulate carr inhibitor (3 BPM @ 480 psi). . Land tubing & RILDS. Check control line pressure - OK. P P P Pressure test surface equipment to 4000 psi - OK. Pressure test 3 1/2" tbg to 4,000 for 30 min - OK. Bleed tbg pressure to 2,000 psi. Printed: 8/3/2001 6:09:36 AM Operator: BP EXPLORATION '. Well: L-110 ) Field: PRUDHOE BAY From-To Hrs Phase I Task !! hh:mm (hr) 03:00-05:00 2.00 COMP :RUNCOI I i COMP ¡RUNCO: I I t ' coMp !RUNCoI I ; COMP' WHSU : COMP ! WHSU ! I 12:30-13:30 1.00 COMP WHSU I t I 13:30-15:00 i 1.50 COMP tRUNCO¡ I I 15:00-16:00 1.00 COMP WHSU i ¡ 16:00-17:00 1.00 COMP WHSÜ: i i 06:00 Update: 05:00-06:00 1.00 06:00-07:00 1.00 07:00-11 :00 4.00 11 :00-12:30 1.50 ) DIESEL Anchor I T . enslon ! Rig Heading: VOL: Swell Height: Activity ) BPEXPLORA TION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Operations ··Summary Code I NPT I I Report: 18 Date: 8/2/2001 '.) Exhibit VI..5 b Operation LANDTH P ND P ND P NU P PRESS P PLUG P FREEZE P ! . ,... ., . .. . . , . I Pressure test anulus to 4,000 psi for 30 min- OK. Bleed down tbg i pressure & shear RP @ 2900 psi. Note - all pressure's & times charted & chart is on file. Backout landing jointinstall TWC & pressure testfrom beio\Nto 280Ö psi - OK. : Rig down Cameo svc's. Blow down all surface lines & drain BOP I stack. I Nipple down BOP stack & adaptor flange. Nipple up adaptor & production X-mas tree. Rig up FMC svc's. Install SBMS & control lines. Pressure test adaptor ,flange & control lines to 5,000 for 15 min - OK. Fill production X-mas ¡ tree with diesel. I Rig up DSM& recover TWC. I Rig up circulating lines on casing & tubing valves. Rig up Little Red I services, pressue test pumps & lines to 3,000 psi - OK. Pump freeze I protect into annulus (45 bbls), shut valve & allow diesel to U-tube into i tubing. IlnSlallElPV&preŠSUrelesí same 101 ,OOÒ psi - OK. Rig down DSM \ Secure production X-mas tree & cellar area. Release rig to move to , L-114 @ 1700 Hrs 8/02/2001. PRESS P þ RD M~terié1ls" r Coosum ption Usage.. I On Hand .1 Item o I 6048 Personnel No. I Hours Company I No. I Hours Company 2 i 12.00 BAROID I 212.00 ÄNADRILLSCHLUI\I1BERGER 241 12.00 I I Anchoring 1 Marihe 5 i 6 \ 7 I , Rig Heave: Rig Roll: Rig Pitch: Units I Usag~1 On Hand I 1 No. 2 Hours 12.00 8 10 ¡ , I I Riser Tension: Riser Angle/Dir.: Current: Current Direction: 11 2 3 4 Sea Height: Sea Dir.: Sea Period: Comments: 12 9 Cumulative Phase Breakdown Planned Change of Scope Prod % Total' NPT % Total WOW % Total Prod % Total NPT% Total WOW % Total 117.00 98.3%1 2.00 1.7%' Phase SURF PRE INT1 COMP TOTALS 107.50 70.7% 44.50 29.3% 37.00 100.0%, 261.50 84.9% ' 46.50 15.1 % ' 0.00 0.0% 0.00 0.0% ' 0.00 0.0% . 0.00 0.0% Total I Total Cost Hours USD 119.00' 0.00 152.00 37.00: 308.00' 0.00 ) .".1 Printed 8/3/2001 6:09:36 AM .~ .~ Exhibit VI-6: L-114 WelllnteQrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: 9/13/2001 6-3/4" Schrader Bluff Penetration Casing Diameter: 5-1/2" Well Status as of 8/2003: Oil Producer Gas Lift Cement Logs Across Schrader Bluff: None Comments: The 5-1/2" primary cement job consisted of 239 sacks (571 ft3) of cement. Floats held and the plug bumped with 2100 psi. The 5-1/2" cement job was designed to cover the Schrader Bluff sands. With a gauge hole, 2342'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 763'MD of cement above the top of the Na sand. Additional Information: Well Diagram - Exhibit VI-6 a Drilling Daily Reports (Cementing) - Exhibit VI-6 b -- .~ ~. TREE = 3-1/8" 5M CIW WELLHEAD = 11"FI'vC 'Ä"è11JATÖR;' ...,..,"'".. ,........,.""',,. f<B .'·ËL'E\i·;;;-··· ..... .......... ··..·76.3'1 BF. 8..EV = 49A!" .. . ~....~" M"''''''''.........'....",.".""....'''''................""....,.....,,'''.....'''''''''~.'''''"'.~_''',· "':Ip = 1591' It:~~ö~! 17-5/8" CSG, 29.7#, L-80, 10 = 6.875" H 2637' Minimum ID = 2.75" @ 2193' 3-112" HES SSSVN PERFORA TION SUMMA. RY REF LOG: __________ ANGLEATTOP ÆRF: 15 @ 7704' I'bte: Refer to A"oductbn DB for historical perf data SIZE SPF INTER\! AL Opn/Sqz DATE 2-1/2" 6 7704 - 7750 0 09/13/01 ) 1 5-1/2" CSG, 15.5#, L-80, BTC,ID= 4.950" 1-1 13-1/2"TBG, 9.2#, L-80, IBT-M, .0087 bpf, 10 = 2.992" 1-1 15-1/2" X 3-1/2" CSG XO, 10 = 2.968" 1-1 1 A3TD 1-1 13-1/2" CSG, 9.2#, L-80, NSCT, 10 = 2.992" 1--1 I DATE ..,...~17/01 ,113/01 12/30/02 04/08/03 05/15/03 OS/28/03 REV BY COIvlv1ENTS CHIKAK ORIGINAL COMPLETION CWS/KK ÆRFS DA OKK GL V CORRECllONS DRSlTP lV D'MD CORRECllONS JCM'TLH GL V C/O MI-VTLP GL V C/O ) 7425' 7431' 7438' 8158' 8253' DA. lE L-114 SAFEn .. I L.... ~ 1 =~ 981' )TES: 1-17-5/8" TAM PORr COLLA R 1 e······.····· '~¡, . 2193' 1-i3-1/2" HES XDB BVN, 10 = 2.75" 1 ~ GA S LIFT MA. NDRELS l ST MD lVD ŒV lYÆ VLV LATCH FORr DATE 4 3695 3423 49 KBG-2 DOrvE BL 16 OS/28/03 3 6246 5226 37 KBG-2 SO BL 20 05/14/03 2 7234 6084 24 KBG-2 DrvtY BL 08/17/01 1 7353 6194 21 KBG-2 DrvtY BL 10/11/01 I 7379' 7425' 7442' 7489' 7509' 1-13-112" HES X NP, 10= 2.75" 1-1 TOP OF BKR PBR, 10 = 4.00" 1--13-1/2" BKR SEAL ASSY, D = 3.00" 1 1--13-1/2" HESXNP, 10=2.75" 1-13-1/2" HES X NP, 10 = 2.75" 7551' 1-120' RJPJT W / RA TAG 1 8146' 1-110' RJPJT W / RA TAG 1 ~ REV BY CO 1vIv18'J1S BOREALIS lJ'.JrT WELL: L-114 PERIV1IT No: 2011360 A R No: 50-029-23032 SEe 34, T12N R11 E, 2346' NSL & 3844' WEL Exhibit VI-6 a BPEXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT CurrentWell Status Depth MD: 8,270.0 (ft) Casing Size: 5.500 (in.) Costs in: USD Est. TVD: 7,155.0 (ft) Casing (MD): 8,252.06 (ft) AFE No: 5M4026 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,500,000 Auth Depth: 8,268.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,140 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 137,614 DOL/DFS/Target: 12.75/11.80/13.70 Liner (MD): Daily Well: 197,107 Geologist: F.Redella/D.Stearns Liner Top (MD): Cum. Well: 1,595,533 Engineer: Neil Magee Supervisor: Anglen I Morris Current Status: Rih 3 1/2 completion @ 4750'. 24hr Summary: Lay dn bha, run 3 1/2 X 5 1/2 csg, cmt, begin 3 1/2 completion 24hr Forecast: Run completion, test, nipple dn. Comments: No Accidents, No Incidents, & No Spills.. Weather = 36 Deg WI wind NE @ 6 mph. CF= 29 deg - Rain HSE&WellConirol All Free Days: 3/16/2001 Operator: BP EXPLORATION Well: L-114 ) Field: PRUDHOE BAY ) Program: Days Since Last DAFWC: 1000 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 8/12/2001 Next BOP Press. Test: 8/13/2001 Last Divertor Drill (D3): 8/4/2001 No. Stop Cards: Fire: 8/12/2001 I I LOT TVD: LOT EMW: MAASSP: Test Pressure: ) Kick Tolerance: Kick Volume: 3,567.0 (ft) 12.02 (ppg) 264 (psi) 301 (psi) (ppg) (bbl) Last Envir. Incident: Last Spill Drill: 8/15/2001 Regulatory Agency Insp: N Kick While Drill (D2): 8/11/2001 Pump i Slow Pump Rates (Circ) I ¡ Stroke Rate PressureO I ! i I I I ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: ) Exhibit VI-6b Report: 14 Date: 8/15/2001 Rig Accept: 06:008/3/2001 Rig Release: Spud Date: 8/4/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Tot. Personnel: 37 Cost Ahead 225,000 USD, Days Ahead 2.00 13 Last Trip Drill (D1): Last Safety Meeting: 8/13/2001 8/12/2001 Non-compliance Issued: N Pit: 8/612001 Slow Pump Rates (Choke) Slow Pump Rates (Kill) Stroke Rate PressureO Stroke 'Rate PressureO OperatiphalPararneters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 85 (hr) Wt Below I Depth Out I Jar (ft) I I HOLE OPENER,BIT SUB, DRILL COLLAR, STRING STAB, 2 x DRILL CÖU..ÄI{- HWDP, JAR, 20 x HWDP, Drillin~ Fluid 4 (lb/100ft2) . Ca: 6 (lb/100ft2) K+: 3.0 (cc/30min) CaCI2: 200 (OF) NaCI: 6.8 (cc/30min) CI-: 1 (/32") Sand: 17.50 (ppb) HGS: (ppb) LGS: 0.20 (mL) Pf/Mf: No: ! Type Weight 4 i HOLE OPENIN Type: Time/Loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: LSND 12: 001 8,270.0 (ft) (OF) 10.40 (ppg) 46 (s/qt) (ppg) 13 ( cp ) 18 (lb/100ft2) 9.1 ) I 10 see gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) BHA ! Pump Status - Drilling and Riser ! Pump ¡type! Eff. ¡Strokesl Liner Size!Circ.Rate I. ....... HI ... (%). (spm) I .. (in).. I (gpm) 1 I D 96 I 5.500 I . . 2 D 96 I 5.500 Description 20 (mg/L) (mg/L) (%) (%) 300 (mg/L) 0.10 (%) 82.32 (ppb) 44.77 (ppb) 0.20/4.0 (mUmL) i ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (bbl) (bbl) (bbl) (bbl) (mV) 10.50 (%) (%) (%) Printed 8/16/2001 55632 AM Hrs i Phase I Task (hr) ¡ 0.50 IPROD1 CASE I 1.50 PROD1 CASE ,13.00IPROD1 CASE ') BP EXPLORATION Dally Operations . Report R~: NABORS9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Operations Summary Code NPT Report: 14 Date: 8/15/2001 ) ExhibitVI.,6. b Operator: BP EXPLORATION Well: L-114 ) Field: PRUDHOE BAY I 15:00-16:30 1.50 !PROD1 CASE CIR 16:30-19:00 2.50 iPROD1 CASE CMT I I From-To hh:mm 00:00-00:30 00:30-02:00 02:00-15:00 Activity Operation PTOH P Cant lay dn bha, clear rig floor. RUN P Flow check, pullwear bshng, make dummy run csg hgr, record spaceout. Lay dn hgr / Idng jt. Flow check, commence run 5 1/2 X 3 1/2 csg as per program. Float check, fill all jts, circ at 7 5/8 shoe. Csg = 3 1/2, 9.2#, IBT, L80 5 1/2, 15.5#, BTC M, L80 Circ with hgr landed. Can not recip csg. Note 100% returns. Circ 5 bpm @ 1100 psi. Make up cmt hd, test lines, commence cmt csg as follows: Pump 10 bbl CW 100, test lines 4000 psi, pump addtnl1 0 bbls CW 100. DRop btm plug, pump 40 bbls Mud Push XL 11.2 ppg. Pump 102 bbls 12 ppg Lite Crete slurry @ 5 bpm. Drop top plug, flush lines 10 bbls H2o. Displace with rig pumps 183 bbls sea water. 2629 'strokes. Bump plug 2 bpm at 2100 psi and holding. I Final circ press 1700 psi. 2 bpm. Plug bumped at 1900 hrs. 1 Bleedpress, floats holding. rig dn all relatedcmt equip. jRelease cmt unit. ¡Install packoff I test to 4000 psi / 15 min. Will not hold press. Pull, Ire-run, re-test. Test successful. I Flow test, PJSM,rig up and rih 3 1/2 camp string as per program. i Camp assy = sealassy, GLMs, X nipples, 3 1/2, 9.2#, L80, IBT RUN P P P CMT 19:00-20:00 1.00 PROD1 CASE 20:00-22:30 2.50 PROD1 CASE P PRESS P I I 22:30-00:00 i 1.50ICOMPRUNCÖ CMPSTG I , 06:00 Update: Rih 3 112 comp assy. 150 jts tbg in hole ) BP BAROID BP Anchor I Tension Rig Heading: VOL: Swell Height: Comments: Phase PRE SURF PROD1 COMP TOTALS ,) P Item Materials I COn$Umption Usage. ..1 On Hand I Item 1224: 3744 Personnel Company No. I Hours 2411 12.00 2 12.00 i Company Hours 12.00 Nabors 12.00 SWS ANADRILL 12.00 SPERRY-SUN Anchoring} Marine 5 ; 6 i 7 Rig Heave: Rig Roll: Rig Pitch: RiserTension:' Riser Angle/Dir.: Current: Current Direction: No. 2 2 1 No. I Hours Company 21'· 12.00 Nabors 21 12.00 SWS ANADRILL 2i 12.00 2 I I I Sea Height: Sea Dir.: Sea Period: 4 3 9 10 11 12 Prod % Total' 33.00 100.0% i 21.50 100.0% 39.50 84.9% 1.50 100.0% 95.50 93.2%' Cumulative Phase Breakdown Planned Change of Scope NPT % Total WOW % Total Prod % Total' NPT % Total WOW % Total Total Total Cost Hours USD 33.00 21.50 46.50 1.50 102.50' 0.00 7.00 15.1% 7.00 6.8% 0.00 0.0% 0.00 0.0% Remarks 0.00 0.0% - 0.00 0.0% Printed: 8/16/2001 5:56:32 AM ) BP,EXPLORATION Da i lyO pe rations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 8,270.0 (ft) Casing Size: 5.500 (in.) Costs in: USD Est. TVD: 7,155.0 (ft) Casing (MD): 8,252.06 (ft) AFE No: 5M4026 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,500,000 Auth Depth: 8,268.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,140 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 138,754 DOL/DFS/Target: 13.75/12.80/13.70 Liner (MD): Daily Well: 204,871 Geologist: Liner Top (MD): Cum. Well: 1,811,670 Engineer: Neil Magee Supervisor: Anglen I Morris Current Status: Freeze protecting well 24hr Summary: Rih tbg, LOT, test csg, rih, Ind tbg, test, NU tree, test, frz protect 24hr Forecast: Freeze protect, set BPV, release rig, move L-107 Comments: No Accidents, No Incidents, & No Spills.. Weather = 34 Deg WI wind NE @ 11 mph. CF= 23 deg HSE & Well Control All Free Days: 3/16/2001 Operator: BP EXPLORATION Well: L-114 ) Field: PRUDHOE BAY Days Since Last DAFWC: 1001 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 8/12/2001 Next BOP Press. Test: 8/13/2001 Last Divertor Drill (D3): 8/4/2001 No. Stop Cards: Fire: 8/15/200 LOT TVD: LOT EMW: MAASSP: Test Pressure: ) Kick Tolerance: " Kick Volume: 3,567.0 (ft) 12.02 (ppg) 264 (psi) 301 (psi) (ppg) (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: SEA WATER : I 8,270.0 (ft) (OF) 8.80 (ppg) 28 (s/qt) (ppg) (cp) (lb/100ft2) 9.1 ExhibitVI-6 b Report: 15 Date: 8/16/2001 Rig Accept: 06:008/3/2001 Rig Release: Spud Date: 8/4/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Program: Tot. Personnel: 37 Cost Ahead 150,000 USD, Days Ahead 2.00 14 Last Envir. Incident: 8/13/2001 8/12/2001 Last Trip Drill (D1): Last Safety Meeting: Last Spill Drill: 8/15/2001 Regulatory Agency Insp: N Kick While Drill (02): 8/11/2001 Pump Slow Pump Rates (Circ) Stroke Rate PressureO 10 sec gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: From-To Hrs Phase Task Activity hh:mm (hr) 00:00-04:00 4.00 COMP RUNCO CMPSTG Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 85 (hr) DrHlin~lFlu id (lb/100ft2) I Ca: (lb/100ft2) [ K+: (cc/30min): CaCI2: (OF) NaCI: (cc/30min) I CI-: (/32") , Sand: (ppb) HGS: (ppb) LGS: (mL) Pf/Mf: 04:00-05:00 1.00 COMP RUNCO LOT 05:00-07:00 2.00 COMP RUNCO CMPSTG ) 07:00-09:00 2.00 COMP RUNCO SSSV Non-compliance Issued: N Pit: 8/6/2001 Slow Pump Rates (Choke) Slow PUmp Rates (Kill) Stroke Rate PressureO Stroke Rate PressureO i I Qperati()nál Parameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Pump Status - Drilling and Riser pum. p TY..P. el.E..ff..... StrokeslLiner Size! Circ. Rate (%) (spm) I (in) (gpm) 1 D [ 96 5.500 2 D 96 5.500 I I I I Ann. Vel. Riser: (fUmin) Ann. Vel. DC: (fUmin) Ann. Vel. DP: (ft/min) (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) I (mL/mL) I ES: I Solids: Oil: Water: Oil/Water: Daily Cuttings: ! Cum. Cuttings: : Lost Downhole: : Lost Surface: (bbl) (bbl) (bbl) (bbl) (mV) (%) (%) (%) Operations Summary Code NPT Operation P Cant rih 3 112 tbg to 2700 ft. Receive cmt compressive strengh test res u Its. Perform LOT 5112 X 7 5/8 annulus. Results = 12.02 EMW, 301 psi, 3800 ft. . Resume rih 3 1/2 tbg. while bullhead 67 bbls 10.4 mud dn 5112 X 7 5/8 annulus. Inj rate = 127 gpm @ 770 psi Follow with 34 bs dead crude. Identical injection rate. Place Control line equip on floor, rig up same, test lines 5000 psi. P P P Printed: 8/17/2001 54724 AM I 21 :00-22:30 1.50 COMP ¡RUNCO, TSTPRS 22:30-00:00 1.50 c:oMPIRUNCO¡ ND 1 ' I I Operator: BP EXPLORATION Well: L-114 ) Field: PRUDHOE BAY From-To Hrs Phase I Task I hh:mm (hr) 09:OÖ-09:30 0.50 COMP [RUNCO] I ' 09:30-13:30 4.00 COMPIRUNCO] I 13:30-16:00 2.50 COMP [RUNCO! I r , ; I i 16:00-17:00 1.00 COMP ¡RUNcol ! r I . ..' I 17:00-19:30 2.50: COMP IRUNCO¡ 19:30-21 :00 1.50 I COMP IRUNCO I Activity ) BPEXPLORATION Daily QperationsReport R~: NABORS9ES Event: DRILL+COMPLETE Well Type: DEVELOPMENT Oper~dipns Summary Code NPT Operation Report: 15 Date: 8/16/2001 Exhibit VI-6 b TSTPRS P CMPSTG P CMPSTG P sssv P CMPSTG P TSTPRS P ,Test csg to 4000 psi I 30 min. test good. I Resumerih31/2 tbg.Slow going with control lines. I Circ 20 spm while stab into PBR. Note 200 psi press increase. I Stop pump and bleed. Note 10.5 ft seal stab in. Space out, record measurements, make up pups I tbg hgr. IAttach controllines,'test t050ÖO psi. .... ! Take up I dn wts, Up 100, Dn 9Ö. Reverse circ btms up, displace I annuluswithinhibited seawater. ¡Land tbg, lock down hgr. Test tbg to 4000 psi I 30 min. 'I' Bleed tbg to 2000 psi. Test 3 1/2 X 5 1/2 annulus to 4000 psi I 30 min. I Bleed tbg slowly, RP shears at 2700 differential. i Install twc, test below check to 2800 psi. Bleed all pressures. I All tests successful. No re-rest. 1 .. ........ '. .... .. . .... [ Prepare and nipple dn bope. Set back bop. I P P 06:00 Update: Install control lines, nipple up tree, test, pull two way check, freeze protect well Item ) 2 1 Materials·rConsumptiol1 US~g1~21 On H2a5ngd21 Item Personnel Hours Company I 12.00 Nabors 12.00 SWS ANADRILL I 12.00 SPERRY-SUN ì Anchoring I Marine 5 I 6 i 7 , I ! ! Rig Heave: Rig Roll: Rig Pitch: 12 Units Units Usage I On Hand BP BAROID BP No. I Hours 2 12.00 Nabors 2 12.00 SWS ANADRILL 2 12.00 Anchor Tension r Rig Heading: VDL: Swell Height: 2 Comments: Phase PRE SURF PROD1 COMP TOTALS Prod % Total. 33.00 100.0%· 21.50 100.0% 39.50 84.9% 25.50 100.0% 119.50 94.5% ) ,I I r Sea Height: Sea Dir.: Sea Period: : 10 I I .I Riser Tension: Riser Angle/Dir.: Current: Current Direction: 3 4 8 9 11 Cumulative Phase Breakdown Planned Change of Scope NPT % Total I WOW % Total Prod % TotallNPT % Totalr WOW % Total , , Total Total Cost Hours USD 33.00 21.50 46.50 25.50' 126.50' 0.00 7.00 15.1% 7.00 5.5% 0.00 0.0% 0.00 0.0% Remarks 0.00 0.0% 0.00 0.0% Printed: 811712001547:24 AM ',-, '~ Exhibit VI-7: L-116 Welllnteqrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: 9/14/2001 6-3/4" Schrader Bluff Penetration Casing Diameter: 5-1/2" Well Status as of 8/2003: Oil Producer Gas Lift Cement Logs Across Schrader Bluff: None Comments: The 5-1/2" primary cement job consisted of 217 sacks (516 ft3) of cement. Floats held and the plug bumped with 3200 psi. The 5-1/2" cement job was designed to cover the Schrader Bluff sands. With a gauge hole, 2494'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 1067'MD of cement above the top of the Na sand. Additional Information: Well Diagram - Exhibit VI-7 a Drilling Daily Reports (Cementing) - Exhibit VI-7 b ~' ,~. ',~' TREE = 3-1/8"5MCIW WELLHEAD = 11"FMC ACi'ÜÄ'foFf;;; . .. ....... ki3:'·Ë[ÈV·; .". ",.....""".'m"yè^:Y; (3ï=:ELEV:;' ········52.5~ ":"""Q='-"'~ ~d~!J;~m ) L-116 SAFET YTES: =---4 10M' H7-5/8"TAMPORrCOLLAR 1 ..F . 2208' H3-1/2"HESXDBBVN,ID=2.75" 1 17-5/8"CSG,29.7#, L-80, 10=6.875" 1-1 2653' .. ~ Minimum ID = 2.75" @ 2208' 3-1/2" HES SSSVN GAS LIFT MA NORELS L ST MO TVO DEV TYÆ VLV LATCH PORr DATE 4 3640 3425 17 KBG-2 DOME INT 16 01/29/02 3 5491 5215 12 KBG-2 DOME INT 16 04/17/03 2 6224 5941 5 KBG-2 DMY INT 0 07/16/01 1 6342 6059 5 KBG-2 SO INT 24 04/17/03 PERFORAllON SUMMARY REF LOG: ____ ANGLE AT TOP PERF: 4 @ 6675' Note: Refer to Production œ for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 2-1/2" 6 6675 - 6720 0 09/14/01 2-1/2" 6 6734-6740 0 09/14/01 ) I I 6368' 1--13-112" HES X NIP, 10 = 2.75" I 13-1/2"TBG, 9.2#, L-80, IBT-M, .0087 bpf, 10 =2.992" l-i 6419' ~ 1 5-1/2" CSG, 15.5#, L-80, BTC, 10 = 4.950" 1-1 6421' ---i 6422' I-iTOPOF BKR FBR, 10 = 4.00" I 15-1/2" X 3-112" CSG XO,ID = 2.968" 1-1 6433' l--' I 6432' 1-13-1/2" BKR SEAL ASSY, ID = 3.00" 6662' 1-120' PUP JT WI RA TA G 1 6981' l-i 10' PLP JT WI RA TAG 1 1 PBTD H 13-112" CSG, 9.2#, L-80, NSCT, D = 2.992" H 7062' ~ 7172' I DATE --¡~. 16/01 /14/01 "~/17/01 12/30102 04108103 04/17/03 REV BY COMtvENTS Q-//KAK ORlGNAL COMR...EllON ONSlKK PERFS GC/KAK PERF CORRECTON DAOKK GLV CORRECTIONS DRSlTP TVO/I'vO CORRECTIONS JOv'IfTLH GLV UPDATE DATE REV BY CO rv1\IIENTS BOREALIS UNfT WB...L: L-116 ÆRMT f\b: 2011160 API f\b: 50-029-23025 SEC 34, T12N, R11 E, 2372' NSL & 3743' WEL Exhibit VI-7 a ) BP EXPLORATION Dai Iy .Operati ons Re pO rt Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: CurrentWell·.Status Depth MD: 7,190.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 6,983.0 (ft) Casing (MD): 2,652.77 (ft) AFE No: 5M4028 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,426,000 Auth Depth: 7,209.0 (ft) Next Casing (MD): (ft) Daily Mud: 14,522 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 156,437 DOL/DFSITarget: 13.33112.66/12.70 Liner (MD): 7,172.65 (ft) Daily Well: 377,650 Geologist: Liner Top (MD): (ft) Cum. Well: 1,813,209 Engineer: Neil Magee Supervisor: Decker I Morris Operator: BP EXPLORATION Well: L-116 ) Field: PRUDHOE BAY ) Exhibit VI..'? b Report: 14 Date: 7/14/2001 Rig Accept: 10:297/1/2001 Rig Release: Spud Date: 7/1/2001 Elev Ref: SEA LEVEL KB Elev: 76.70 (ft) Program: Tot. Personnel: 30 Cost Ahead 25,000 USD, Days Ahead -1.00 Current Status: Rih 3 1/2 tbg, 24hr Summary: Ru 5 1/2 csg, eire, cmt, set I test pkf, rih 3 112 prod string. 24hr Forecast: Rih 3 1/2 tbg, Ind hgr, test, nipple dn bope. Comments: No Accider;¡ts*No Incidents*No Spills Temp: 37 deg. Wind: 14 mph NE CF: 20 deg. HSE··&We.IIControl Days Since Last DAFWC: 968 All Free Days: 13 Last Csg Test Press.: 4,000 (psi) Last Envir. Incident: 3/16/2001 Last BOP Press. Test: 7/612001 Next BOP Press. Test: 7/13/2001 Last Accum. Drill (04): 7/6/2001 Last Divertor Drill (03): 7/3/2001 Last Spill Drill: 7/14/2001 No. Stop Cards: 3 Regulatory Agency Insp: N Fire: 7/14/2001 Kick While Drill (02): 7/8/2001 Well Kill (05): 6/12/2001 Last Trip Drill (01): Last Safety Meeting: 7/14/2001 7/14/2001 Non-compliance Issued: N Stripping: 7/7/2001 Pump Slow Pump Rates (Circ) Stroke Rate PressureO Slow Pump Rates (Choke) Stroke Rate PressureO Slow Pump Réltes (Kill) Stroke Rate PressureO LOT TVD: LOT EMW: MAASSP: .\) Test Pressure: " Kick Tolerance: Kick Volume: 2,583.0 (ft) 15.46 (ppg) 625 (psi) 813 (psi) 10.80 (ppg) 36.9 (bbl) I I Opèratjon~l Parameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Type: Time/loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: LSND 11 :OO/PIT 7,190.0 (ft) 68 (OF) 10.60 (ppg) 45 (s/qt) (ppg) 11 (cp) 18 (lb/100ft2) 9.0 Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 146 (hr) Drilling Fluid 10 see gels: 6 (lb/100ft2) ! Ca: 10 min gels: 8 (lb/100ft2) I K+: Fluid Loss: 3.5 (cc/30min)! CaCI2: HTHP Temp: 200 (OF) , NaCI: HTHP WL: 9.5 (cc/30min) I CI-: I Cake: 1 (/32") : Sand: MBT: 10.00 (ppb) HGS: Lime: (ppb) LGS: PM: 0.10 (mL) Pf/Mf: Ann. Vel. Riser: (ftlmin) Ann. Vel. DC: (ftlmin) Ann. Vel. DP: (ftlmin) I Pump Status - Drilling and Riser ¡Pump ]Type Eft. ¡Strokes Liner Size] Circ.Rate I ! I (%) ! (spm) . (in) ...1 (gpm) , 1 ! 0 ! 96 ' I 5.500 i 2 I 0 i 96 5.500 I I ! 20 (mg/L) (mg/L) (%) (%) 300 (mg/L) 0.10 (%) 101.43 (ppb) 36.95 (ppb) 0.05/0.3 (mL/mL) ! ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (bbl) (bbl) (bbl) (bbl) . Run 3.5" X 5.5" Production String. 22 Jts 3.5" & 156 Jts 5.5". Shoe set at 7172'. Plug receptacle at 7064'. Top of PBR @ 6422'. Attempted circ. 1 Jt. prior to landing. Reciprocating pipe. No returns for 1 st 95 bbls pumped then partial rtns with losses of 80 bbls/Hr. ; improving steadily to 20 bbls I Hr. by 08:30. Adding Barofibre and thinning mud. Mud thinned and wt at 10.7 ppg with 5 Ib I bbl barofibre at 12:00 Hrs. Losses < 12 bbl I Hr. From-To Hrs Phase Task Activity hh:mm (hr) 00:00-03:00 3.00 COMP CASE RUN 03:00-12:00 9.00 COMP CEMT CIR ) ~,,/ Operations Summary Code NPT P P (mV) 11.00 (%) 1.0 (%) 88.0 (%) I Operation Printed: 7/15/2001 6:0920 AM ! 14:30-16:30 2.00 IPROD1 ¡ WHSU I... i 16:30-17:30 1.00! COMP IRUNCO I I 17:30-22:30 ! 5.00 I COMP ¡RUNCOI 2230-23:30 ~ 1.00 I COMP IRUNCOI 23:3Ö-OÒ:OO i 0.501CÒl\llp IRUNCOI .. 1 ! : I : 06:00 Update: Test csg to 4000 psi, LOT 5 1/2 X 7 5/8 Annulus, inject mud I crude oil for freeze protection, install sssv, rih 3 1/2 tbg Operator: BP EXPLORATION Well: L-116 ) Field: PRUDHOE BAY From-To : Hrs Phase ¡Task i hh:mm . (hr) 12:00-14:30 2.50 COMP CEMT Activity CMT PRESS P RTIH RTIH RTIH RTIH .) BP EXPLORATION ) Dally OpèrationsReport R~: NABORS9ES Event: DRILL +COMPLETE Well Type: Operations'SUmmary Code I NPT Operation Exhibit VI-7 b Report: 14 Date: 7/14/2001 P RIU Dowell Pump 5 bbl CW100. Test lines to 4000 psi. Pump 5 bbls CW100 followed by 50 bbls 11.3 ppg. Mud Push XL Spacer. Drop wiper dart and pump 90 bbls 12.0 ppg LiteCrete Cement. Drop j Plug dart and displace with 159 bbls filtered seawater. I Bump plug with 3200 psi. Hold for 5 min, bleed off & check floats - OK. RD Cmt equip. & Landing jt. M/U packoff running tool and install Packoff. RILDS. LID running tool. Test Packoff to 5000 psi. i Clear rig floor, rig up, make ready to run camp assy. i : PJSM, MU seal assy I shoe, rih same, follow with 3 1/2, 9.3#, : L80 BTC-M, prod tbg. I Place Cameo control line equip on rig floor, prepare test csg. PJSM, test lines for csg test. nnudLog Information 1 Form. Top MD. I Bkgrnd Gas 1 Conn. Gas MäterialsI Cons umþtion Usage. . .1 On !-land I Item 1171, 6408 PersOnnel Company I I I Anchoring I Marine 5 i 6 I 7 I 1 Rig Heave: Rig Roll: Rig Pitch: Formation S Lithology SHALE (ppm) (ppg) (ppm) I Trip Gas (ppm) Pore. Press Item Units Usage ~ On Hand ! ) DIESEL 4 Company BP AMOCO NABORS No. I Hours 2]l2.00 BAROID 24: 12.00 Cumulative Phase Breakdown Planned Change of Scope Total Total Cost NPT % Total WOW % Total Prod % Total· NPT % Total ¡ WOW % Total Hours USD 0.00 31.00 43.7% 71.00 7.50 4.2% 179.50· 39.50 38.50 13.3% 0.00 0.0% 0.00 0.0% 0.00 0.0% . 0.00 0.0% 290.00. 0.00 Window I Coiled Tubing Drilling CT OD: (in) CT Daily Ftg: (ft) CT Strength: (psi) CT ID: (in) CT Cum Ftg: (ft) CT Length: (ft) Anchor Tension . Rig Heading: VDL: Swell Height: 2 Comments: Phase PRE SURF PROD1 COMP TOTALS Prod % Total 40.00 56.3% 172.00 95.8% 39.50 100.0% 251.50 86.7% Window Top: (ft) Mud Sys Ftg: (ft) Window Desc: ) 3 Sea Height: Sea Dir.: Sea Period: , I I Riser Tension: Riser Angle/Dir.: Current: Current Direction: 8 12 Printed 7/15/2001 60920 AM ) BPEXPLORATION Daily Operations Report R~: NABORS9ES Event: DRILL +COMPLETE Well Type: CurrentWèllStatus Depth MD: 7,190.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 6,983.0 (ft) Casing (MD): 2,652.77 (ft) AFE No: 5M4028 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,426,000 Auth Depth: 7,209.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,140 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 157,577 DOL/DFSlTarget: 14.33113.66/12.70 Liner (MD): 7,172.65 (ft) Daily Well: 210,390 Geologist: Liner Top (MD): (ft) Cum. Well: 2,023,599 Engineer: Neil Magee Supervisor: Decker I Morris Operator: BP EXPLORATION Well: L-116 )Field: PRUDHOE BAY EXhibiìVI-7b Report: 15 Date: 7/15/2001 Rig Accept: 10:297/1/2001 Rig Release: Spud Date: 7/1/2001 Elev Ref: SEA LEVEL KB Elev: 76.70 (ft) Program: Tot. Personnel: 30 Cost Ahead 0 USD, Days Ahead -2.00 Current Status: Moving to L-11 0 24hr Summary: Test csg, LOT, inject, rih tbg, land, test, nd bop, nu tree, test. 24hr Forecast: Freeze protect, set bpv, test, release rig, move to L-110 Comments: No Accidents*No Incidents*No Spills Temp: 44 deg. Wind: 10 mph NE CF: 20 deg. HSE&WellControl All Free Days: 3/16/2001 Days Since Last DAFWC: 969 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/6/2001 Next BOP Press. Test: 7/13/2001 Last Divertor Drill (D3): 7/3/2001 No. Stop Cards: Fire: Well Kill (05): LOT TVD: LOT EMW: MAASSP: ") Test Pressure: .' Kick Tolerance: Kick Volume: ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 146 (hr) Drillin9 Fluid (lb/100ft2) I Ca: (lb/100ft2) I K+: (cc/30min) CaCI2: (OF) NaCI: (cc/30min)' CI-: (/32") Sand: (ppb) HGS: (ppb) LGS: (mL) Pf/Mf: 7114/2001 6/12/2001 I i 2,583.0 (ft) 15.46 (ppg) 625 (psi) 813 (psi) (ppg) (bbl) SEA WATER : IPIT 7,190.0 (ft) 68 CF) (ppg) ( s/qt) (ppg) (cp) (lb/100fF) Pump 10 see gels: 10 min gels: Fluid Loss: HTHP Temp: ! HTHP WL: Cake: MBT: Lime: PM: From-To Hrs Phase Task Activity hh:mm (hr) 00:00-01 :00 1.00 COMP RUNCO TSTPRS 01 :00-02:00 1.00 COMP RUNCo' TSTPRS \ 02:00-03:30 1.50 COMP RUNCO LOT ~ " 14 Last Envir. Incident: Last Accum. Drill (04): 7/6/2001 Last Spill Drill: 7/15/2001 Regulatory Agency Insp: N Kick While Drill (D2): 7/8/2001 Last Trip Drill (01): Last Safety Meeting: 7/14/2001 7/15/2001 Non-compliance Issued: N Stripping: 7/7/2001 Slow Pump' Rates (Circ) Stroke Rate PressureO Slow Pump Rates(Chôke) Stroke Rate PressureO Slow Pump Rates (Kill) Stroke Rate PressureO Operational. Parameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Pump Status - Drilling and Riser PlIm. p ITyp.e[ E.ff..IS.tro. kesUn.e. ,r.,s.., ,iz...eClrè,' '.R. a,te I I (%) : (spm) (in) (gpm) ! 1 i 0 . 96 I I 5.500 : 2 ' 0 96 i 5.500 Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ftlmin) Ann. Vel. DP: (ft/min) (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) (mL/mL) ES: : Solids: Oil: Water: Oil/Water: . Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (mV) (%) (%) (%) (bbl) (bbl) (bbl) (bbl) Operations Summary Code NPT Operation P Test 5 1/2 X 3 1/2 tbg I csg to 4000 psi I 30 min. Test successful. P Manifold in hot oil I kill line, test same to 3000 psi, in preparation for LOT Perform LOT dn 5 1/2 X 7 5/8 annulus. 1 bpm, 5 stroke intervals. Leak off press at 404 psi ( EMW 13.61 ). Test interval 2652 - 3770 ft ( TOC ). Hold press, bleed to 264 psi and holding. P Printed: 7/16/2001 6:10:39 AM Operator: BP EXPLORATION Well: L-116 ) Field: PRUDHOE BAY From-To Hrs: Phase i Task hh:mm ¡ (hr) , , 02:00-03:30 . 1.50 : COMP [RUNCO: I I 03:30-04:00 : 0,50 I COMP HUNCO 04:00-09:00 I 5.00 i COMP [RUNCo! 'I . . ! I 09:00-14:00 5.00 I COMP ¡RUNCO¡ I I I , I ¡ I I 14:00-15:00 1.00 ICOMPIRUNCoi Activity LOT MUSLIN RUN RUN CIRREV i . 15:00-16:00 1.00 i COMP ¡RUNCO' LANDTH I ' 16:00-18:30 2.50 ! ..... i ëOMP!RUNCO , I I I I CaMP I VVHSU I COMP :WHSU 18:30-20:30 2.00 20:30-00:00 3.50 TSTPRS ND NU ,) ) BP EXPLORATION Da ilyOperati onsR.eport R~: NABORS9ES Event: DRILL +COMPLETE Well Type: Oþerations Summary Code I NPT i I P I P I P I Exhìbit VI,.? b Report: 15 Date: 7/15/2001 Operation P Cant inject 47 bbls 10.6 ppg mud, follow with 33 bbls hot oil. ,650 psi - 3 bpm. Rig dn injection equip. Release unit. i Mu sssv, test control lines to 5000psi I I Cant rih 3 1/2 tbg, installing control lines. I Sting in to pbr with slow pump, note sting in with press build. I Space out for tg hgr, make up pups, connect control lines to hgr, I test lines to 5000 psi. Test successful. Verify space out. 1 Reverse circ Corexit 3 bpm at 440 psi. I I. . ..... . . I Land tbg hgr, run in Ids. Rig up for test. I . . ¡test tbg4000 psi/ 30 min., bleed to 2000 psi. Test 31/2X 51/2 i annulus to 4000 psi I 30 min. Bleed tbg and shear RP at 2900 psi. ¡ differential. Set TWC, test below check to 2800 psi. All tests i successful. No re-tests. ! Nipple dn bope. i .. " ... .... ... ..... . I Connect control lines to ports, nipple up tree, test control lines, ! all hgr I tree seals to 5000 psi. Test succesful. P P P P P 06:00 Update: Complete tree test, freeze protect, set bpv, release rig, begin move to L-11 0 Mudtoglliformation ! Form. Top MD. I Bkgrnd Gas I Conn. Gas Mat~rié1lsICo"'SI.lI11 ption Usag9~61 On H5a4i~ I Item Personnel No. ! Hours Company 2 i 12.00 BAROID 241 12.00 ") Formation S , Lithology SHALE Item DIESEL Company BP AMOCO NABORS Anchor Tension , Rig Heading: VDL: Swell Height: 2 Comments: ¡Units I GAL 3 Sea Height: Sea Dir.: Sea Period: (ppm) I Trip Gas (ppm) i Pore. Press (ppm) (ppg) No. I Hours Company i 21 12.00 ANADRILl scHLUMSERGER i i i I No. : Hours 2! 12.00 ! 4 Anchoring'/Marine 5 6 I 7 12 Rig Heave: Rig Roll: Rig Pitch: .10 I Riser Tension: Riser Angle/Dir.: Current: Current Direction: 11 8 9 Cumulative Phase Breakdown Planned Change of Scope Total Total Cost Phase Prod % Total NPT % Total WOW % Total Prod % Total NPT % Total WOW % T ota I Hours USD PRE 0.00 SURF 40.00 56.3% 31.00 43.7% 71.00 PROD1 172.00 95.8%: 7.50 4.2% 179.50 COMP 63.50 100.0% 63.50 TOTALS 275.50 87.7% 38.50 12.3% 0.00 0.0% 0.00 0.0% 0.00 0.0% 0.00 0.0% 314.00 0.00 ) Printed 7/16/2001 6:10:39 AM .,~ '''-'' Exhibit VI-8: L-120 WelllnteQrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: 3/17/2002 6-3/4" Schrader Bluff Penetration Casing Diameter: 5-1/2" Well Status as of 8/2003: Oil Producer Gas Lift Cement Logs Across Schrader Bluff: None Comments: The 5-1/2" primary cement job consisted of 327 sacks (579 ft3) of cement. Cement returns to surface were noted during the 5-1/2" cement job and the casing tested to 2500 psi for 10 minutes. The 5-1/2" cement job was designed to cover the Schrader Bluff sands. With a gauge hole, 2177'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 589'MD of cement above the top of the Na sand. Additional Information: Well Diagram - Exhibit VI-8 a Drilling Daily Reports (Cementing) - Exhibit VI-8 b ~ '"-'. .~ TREE = 3-1/8" 5M CIW WELLHEAD = 11" FIVC 7\'êTìJA'röì=r;"····m"'. v ...m'" N1\" KB:äBï ";'" .. 7"9.1Ö' BF. EÌ. EV = --"'-'5šÃõ"ì" 'ï<oþ;;"nnn..m--. ."._,"__n~ \-Angíê'-;----S5 @ 4615' --d1~·m"·iVï5··~"" ......"..·"·..n... "''8'994';' [ßtumiVD=' 66"00' ss' ) 17-5/8" CSG, 29.7#, ~-80, ID = 6.875" H 3042' r---J Minimum ID = 2.812" @ 2220' 3-1/2" CAMCO SSSVN PERFORAllON SUMMARY REF LOG: ANGLE AT TOP PERF: 8 @ 8870' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DAlE 2-1/2" 6 8870 - 8904 0 03117/02 2-1/2" 6 8914-8920 0 03/17/02 ) 13-112"1BG, 9.2#,L-80, IBT-M, .0087bpf, ID= 2.992" 1-1 1 5-1/2" CSG, 15.5#, L-80, BTC, D = 4.950" l-i 14-3/4" X 3-1/2" CSG XO, ID = 3.000" l-i 8656' 8657' 8675' FBTD H 9358' 13-1/2" CSG, 9.2#, L-80, ID = 2.992" 1-1 9459' L-120 - e =-1 SAFET~TES: 986' 1--17-5/8" TAM PORT COLLAR I 2220' 1-13-1/2" CAMCO BP-6i SSSVN, D = 2.812" 1 ~ GAS LFT tv\I\NDRELS ST rvD TVD DEV ìYPE VLV LATCH FORT DATE L 3 4444 3417 54 KBG2-9 DOME BTM 16 03124/02 2 7394 5217 47 KBG2-9 DOME BTM 16 03124/02 1 8577 6190 17 KBG2-9 S/O BTM 20 03124/02 I I rl 1 1 '--& 8633' 1-13-1/2" BKR CMD SLIDING SLV, ID = 2.813" 1 8656' 8658' 8674' 8695' 8716' - BKR LOC SEAL ASSY, ID = 2.990" I - TOP OF BKR PBR, ID = 4.00" I IjBlM OF 3-1/2" BKRSEAL ASSY, D =2.990" H 3-1/2" HES X NIP, ID = 2.813" 1 H3-1/2" HES X NIP, ID= 2.813" 1 8790' H 16' PUP JT WI RA TAG 1 I DAlE REV BY COfvrv1ENTS DATE REV BY COMrvENTS "V15/02 ORlGINA.L COMPLETON ¿02/02 CH/TP CORRECllONS vii 17/02 CWSltlh A 00 ÆRF 03124/02 JB/KAK GLV a-tAI'JGEOUT 04/08/03 DRS/TP TVD/rvD CORRECTIONS 9215' 1-115' PUP JT W 1 RA TA G 1 BOREALIS UNIf WELL: L-120 PERMT f\b: 2020060 API f\b: 50-029-23064-00 SEC 34, T12N, R11E 2608' NSL & 3545' WB.. Exhibit VI-8 a ) BP EXPLORATION DaHyOperations Report Rig: NABORS 9ES 9-ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT CurrentWell.Status Depth MD: 9,474.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 7,157.0 (ft) Casing (MD): 3,042.1 (ft) AFE No: 5M4032 Progress: (ft) Next Casing Size: 5.500 (in) AFE Cost: 2,826,000 Auth Depth: 9,526.0 (ft) Next Casing (MD): 9,474.0 (ft) Daily Mud: Hole Size: Next Casing (TVD):7,157.0 (ft) Cum. Mud: 146,266 DOL/DFS/Target: 14.50/13.75/18.90 Liner (MD): Daily Well: 66,051 Geologist: Liner Top (MD): Cum. Well: 1,946,068 Engineer: ODENTHAL Supervisor: MASKELL Operator: BP EXPLORATION Well: L-120 ) Field: PRUDHOE BAY .~ Days Since Last DAFWC: 1182 Last Csg Test Press.: (psi) Last BOP Press. Test: 2/12/2002 Next BOP Press. Test: 2/19/2002 No. Stop Cards: Fire: 2/12/2002 I LOT TVD: LOT EMW: MAASSP: ) Test Pressure: " Kick Tolerance: Kick Volume: 2,658.0 (ft) 13.81 (ppg) 485 (psi) 623 (psi) (ppg) (bbl) Rap Daily: Rap Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: ) Exhibit VI-8b Report: 15 Date: 2/13/2002 Rig Accept: Rig Release: Spud Date: E lev Ref: 17:00 1/30/2002 1/31/2002 SEA LEVEL KB Elev: 79.10 (ft) Program: Tot. Personnel: 28 Cost Ahead 225,000 USD, Days Ahead 3.00 14 Last Trip Drill (D1): Last Safety Meeting: 2/12/2002 2/13/2002 Current Status: 24hr Summary: Fin cleanout run. RU & run 3.5/5.5" casing. 24hr Forecast: Finish run casing. Cement same. Freeze prot OA. Run tubing. Comments: No Incidents. No Injuries. No Spills. WX: Temp: -15 Deg. Wind: 14 mph E. CF: -44 Deg. Daily mud cost = $8017. Cum Cost = $150,480. HSE & Well Control All Free Days: Last Envir. Incident: 3lf6/2Ö01 Last Abandonment Drill: 1/28/2002 Last Accum. Drill (D4): 2/12/2002 Last Spill Drill: 2/13/2002 Regulatory Agency Insp: N Kick While Drill (D2): 2/8/2002 Pump Slow Pump Rates (Circ) Stroke Rate PressureO Non-compliance Issued: N Slow Pump Rates (Choke) Stroke Rate PressureO Operationa I Par.ameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 46 (hr) Wt Below Depth Out Jar (ft) 9,474.0 HOL.E OPENER, FLOAT SUB, DRILL COLLAR, NM STABILIZER, DRILL COLLAR, XO, 3 x HWDP, JAR, 18 x HWDP Drilling Fluid 7 (lb/100ft2) : Ca: 9 (lb/100ft2) . K+: 3.0 (cc/30min)' CaCI2: 200 (OF) NaCI: 8.8 (cc/30min) CI-: 1 (/32") Sand: 16.00 (ppb) HGS: (ppb) LGS: 0.15 (mL) Pf/Mf: No Type Weight 6 , HOLE OPENIN Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: LSND 21 :OO/SUC 9,474.0 (ft) (OF) 10.30 (ppg) 42 (s/qt) (ppg) 15 (cp) 15 (lb/100ft2) 8.9 ) 10 sec gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) BHA 92.77 22.51 0.05/0.4 Slow Pump Rates (Kill) Stroke Rate PressureO I Pump Status - Drilling and Riser Pump Type ,. Eff. 'I Strokes I Liner Size I Circ. Rate ! .J. 0 I 0 ! 0 i 0 : Ii: I ¡ I: I : I ' Description 40 (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) (mUmL) ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: 400 (mV) (%) 3.0 (%) 88.0 (%) I (bbl) (bbl) (bbl) (bbl) Printed: 2/14/2002 549:33 AM 06:00 Update: Cant run casing. Circ at 8000'. Mud pretty thick (100+ FV) and fair amt of sand coming back. Stage up pumps to 4 bpm. Est lost 10-12 bbl. Cant circ to clean up hole & cond mud. Run casing to bottom. Mud Loglnformatiol'1 I Form. Top MD. I Bkgrnd Gas Conn. Gas Materials I Consumption Usage Ion Hand .1 Item 01 5976 Personnel No. Hours Company . No. I Hours 1 12.00PETROTECI-ÎNICAL RESOUR : öl 2 12.00 NABORS Crew 231 12.00 Anchoring! Marine 567 Operator: BP EXPLORATION Well: L-120 ) Field: PRUDHOE BAY From-To I Hrs I Phase i Task hh:mm I (hr) I 00:00-02:00 i 2.00 ,PROD1 ¡ DRILL 'I I : 02:00-07:30 . 5.50 iPROD11 DRILL I , I I I 07:30-08:3011.00 :PROD11 DRILL : . I , ····1 08:30-09:00 0.501 COMP ! CASE I ! 09:00-10:30 1.50 COMP ¡ CASE, 10:30-10:45 0.25 COMP:CASE 10:45-16:00 5.25 COMP i CASE 16:0()-16:30 i COMP ; CASE i COMPi CASE 16:30-21 :30 COMP CASE 21 :30-22:00 22:00-00:00 : 2.00 COMP ¡ CASE I ) Formation COLEVILLE Lithology Item DIESEL Company BP NABORS Supv Anchor I Tension I Rig Heading: VDL: Swell Height: 2 Comments: Phase SURF PRE PROD1 COMP TOTALS Prod % Total 107.50 77.9% 5.00 100.0% 189.50 100.0% 15.50 100.0% 317.50 91.2%' \ / Activity ) BP EXPLORATION ) Daily Operations Report Rig: NABORS 9ES 9-ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Operations Summary Code NPT Operation Report: 15 Date: 2/13/2002 Exhibit VI-8 b CIR P I Fin pump sweep around to clean hole. Spot liner running pill. Monitor ¡well. POH for casing. I POH for casing. Work tight spots 9100, 8975-8879, 8570-8500. Cant I POH LDDP leaving 40 stands in derrick. Monitor well @ 7 5/8" shoe - 10K. LD clean out BHA PTOH P BHALD P PUL P RU P SAFETY P RUN P CIR P RUN P CIR P RUN P Pull wear ring & make dummy run with casing hanger. ! RU to run 3.5" &5.5" casing. I PJSM for running casing. : MU shoe track. Run 22 jts 3.5" casing followed by 5.5" casing to :3040', 1 Circ 1:5 csg vol to cond mud priorto run in OH. Run casing to 6000'. , ¡Break circ and clear 1.5x pipe vol to cond mud & break gels. 1 Cant running casing. No losses to this point. Fill pipe everyjt. Breák ! circ every 10 joints while running. (ppm) : Trip Gas (ppm) i Pore. Press (ppm) (ppg) I Units GAL Units Usage I On Hand Company No. ! Hours . ii 12.00 i BAROID 3 8 9 I 10 11 12 I Ris~r Tension: Riser Angle/Dir.: Current: Current Direction: 4 i Sea Height: Sea Dir.: Sea Period: Rig Heave: Rig Roll: Rig Pitch: Cumulative Phase Breakdown Planned Change of Scope NPT % Total WOW % Total Prod % Total NPT % Total' WOW % Total 1.50 1.1% 29.00 21.0% Total Total Cost Hours USD 138.00 . 5.00 189.50 15.50 348.00' 0.00 1.50 0.4%' 29.00 8.3% 0.00 0.0% . 0.00 0.0% 0.00 0.0% Printed 2/14/2002 5:49:33 AM ) BP EXPLORATION DaHyOperations Report Rig: NABORS 9ES 9-ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 9,474.0 (ft) Casing Size: 5.500 (in.) Costs in: USD Est. TVD: 7,157.0 (ft) Casing (MD): 9,459.2 (ft) AFE No: 5M4032 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,826,000 Auth Depth: 9,526.0 (ft) Next Casing (MD): 9,474.0 (ft) Daily Mud: Hole Size: Next Casing (TVD):7,157.0 (ft) Cum. Mud: 146,266 DOL/DFS/Target: 15.50/14.75/18.90 Liner (MD): Daily Well: 229,916 Geologist: Liner Top (MD): Cum. Well: 2,175,474 Engineer: ODENTHAL Supervisor: MASKELL Operator: BP EXPLORATION Well: L-120 ) Field: PRUDHOE BAY Days Since Last DAFWC: 1183 Last Csg Testpress.: . '(psi) Last BOP Press. Test: 2/12/2002 Next BOP Press. Test: 2/19/2002 No. Stop Cards: Fire: 2/12/2002 LOT TVD: 2,658.0 (ft) LOT EMW: 13.74 (ppg) MAASSP: 475 (psi) .) Test Pressure: 475 (psi) , Kick Tolerance: (ppg) Kick Volume: (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Type: Time/loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: SEA WATER 12:00/SUC 9,474.0 (ft) 100 CF) 8.50 (ppg) 28 (s/qt) (ppg) 1 5 ( cp ) 15 (lb/100ft2) Exhibit VI-8 b Report: 16 Date: 2/14/2002 Rig Accept: 17:001/30/2002 Rig Release: Spud Date: 1/31/2002 Elev Ref: SEA LEVEL KB Elev: 79.10 (ft) Program: Tot. Personnel: 28 Cost Ahead 250,000 USD, Days Ahead 3.00 15 Last H2S Drill: Last Trip Drill (D1): Last Safety Meeting: 2/14ì2002 2/14/2002 2/14/2002 C::urrentStatus: MU tubing hanger. 24hr Summary: Cmt casing - OK. Bump plug. 'Set packoff. Run Tubing. 24hr Forecast: Space out tbg. Circ clean SW. Land tbg. ND. NU. FP. ReI. Comments: No Incidents. No Injuries. No Spills. WX: Temp: -14 Deg. Wind: 11 mph E. CF: -40 Deg. Daily mud cost = $1657. Cum Cost = $152,137. HSE' & Well Control All Free Days: Last Envir. Incident: 3/16/2001 Last Abandonment Drill: 1/28/2002 Last Accum. Drill (D4): 2/12/2002 Last Spill Drill: 2/13/2002 Regulatory Agency Insp: N Kick While Drill (D2): 2/8/2002 Pump Slow Pump Rates (Circ) Stroke Rate PressureO Non-compliance Issued: N Slow Pump Rates (Choke) Stroke Rate PressureO Oper~tionalPararneters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 46 (hr) Drillin¡ Fluid 10 see gels: 7 (lb/100ft2) Ca: 10 min gels: 9 (lb/100ft2) . K+: . I Fluid Loss: (cc/30mm) I CaCI2: HTHP Temp: 200 CF) I NaCI: , HTHP WL: (cc/30min) I CI-: Cake: (/32"): Sand: MBT: (ppb) HGS: Lime: (ppb) LGS: PM: (mL) Pf/Mf: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) 20,000 From-To Hrs Phase Task Activity hh:mm (hr) 00:00-01 :30 1.50 COMP CASE RUN 01 :30-03:30 2.00 COMP CASE CIR ), }. 03:30-05:00 1.50 COMP CASE RUN Operations Summary Code NPT Slow Pump Ratês (kill) Stroke Rate PressureO i. , Pump.Status -Drilling~nd Riser ¡Pump ;Typel Eff. ¡Strokes Liner Size 1 Circ.Rate I :,' i 0 'I' 0 I 0 i 0 , I I I I ' , I I ¡ I I ! i (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) (mL/mL) ES: Solids: I Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (mV) (%) (%) 99.0 (%) I (bbl) (bbl) (bbl) (bbl) P , Continue running casing to 8000' - no problems, no losses. Operation , Circ & cond mud. Stage pump slowly up to 4.5 BPM monitoring losses. Lost approx 10 bbl mud while breaking circ slowly. Circ out barafiber and some sand plus viscous mud (100+ FV). Run casing to bottom. No further losses when RIH. MU casing hanger and landing jt. Land casing with shoe at 9459' MD. P P Printed: 2/15/2002 6:42:35 AM 08: 15-08:45 0.50: COMP I CEMT 08:45-09:15 : 0.50 ì COMP ¡ CErVn I I ì .' I. . ....1 I 09: 15-09:30 : 0.25 I COMP I CEMT¡ I ' I I 09:30-10:30 1.00 I COMP CEMT DISPL I i I I I I·· ......: 10:30-11 :00 0.50 I COMP i CEMT RD I ' 11 :00-12:00 1.00 ! COMP i WHSU SETOTR ') I I 1 12:00-13:00 1.00 I, COMP IRUNCO RU ,; 13:00-13:36 0.50 COMP RUNCO RU 23:30-00:00 I 0.50 06:00 Update: Cant run tbg and control line. Get space out in to top of Baker casing seal receptacle. MU tubing hanger & control line. Operator: BP EXPLORATION Well: L-120 ) Field: PRUDHOE BAY From-To Hrs I Phase I Task hh:mm (hr) i I 05:00-05:30 : 0.50 COMP' CEMT 05:30-06:45 : 1.25 COMP CEMT 06:45-07:00 0.25 COMP CEMT 07:00-08:15 1.25 COMP CEMT 13:30-23:00 9.50 COMP RUNCO COMP [RUNCol I COMPRUNCo! I 23:00-23:30 0.50 Formation COLEVILLE Lithology Item DIESEL Company BP NABORS Supv ) JJ Activity ') BP EXPLORATION ) Daily Operations Report Rig: NABORS 9ES 9-ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Operations Summary Code NPT Operation Report: 16 Date: 2/14/2002 Exhibit VI..B b RU P RU cement head and lines. Break circ and work pipe up to 240 klbs to break free. Reciprocate and circ at 180k up and 80k down. Circ at 4.5 BPM. Circ and cond hole for cement. Stage pump up to 5.5 BPM while continue reciprocate pipe - OK. PJSM for cement job. BP, NAD, DS, Baroid, Peak. CIR P SAFETY P CIR P CMT P CMT P CIR P Cant circ 4.5-5 BPM and recip pipe while batch up spacer and tail slurry. ! Pump 5 bbl CW100. Test lines to 4500 psi. Pump 20 bbl CW100 followed by 40 bbl Mudpush XL at 11.0 ppg. Mix & pump 70 bbl LiteCrete lead slurry at 11.9 ppg 3 bpm 580 psi followed by 33 bbl Class G at 15.8 ppg - 3 bpm 500 psi. SD pumping. Knock cap off cmt head. Install latched btm/top plug combo in head and push down inside casing - OK. Replace cap. to reciprocate up to 80% tensile for 5.5" casing - no success. Pipe appears differentially stuck. Full circ & no losses. Displace cement with seawater at 4.5-5 bpm: Lead slurry at shoe 1600 stks @ 705 psi, 5 bpm Tail slurry at shoe 2600 stks @ 1740 psi, 5 bpm. Final circ pressure at 3050 stks @ 1950 psi, 2 bpm. No losses noted during displacement. Bump plug with 2500 psi. CIP at 10:20 hrs. Bleed off pressure. Floats holding - OK. RD cement head, lines. LD landing jt, elevators. P P P Drain stack. Install packoff. RILDS. P Clear floor. RU to run tubing. P Dummy run with tbg hanger on LJ to verify spaceout. RUN MU seal assembly, siiding sleeve, i jt, #1 GLM with DCK-3 shear valve. Run 3 1/2" tubing. Install head pin. Test casing to 3500 psi -10 min. Good test. P TSTFN P RU RU control line spooling unit. attach control line to SSSVLN. Freeze protect OA - off critical path. See remarks for details. P Mud Log Information I Form. Top MD. ; Bkgrnd Gas ,Conn. Gas Materials I Consumption Units I Usage.: On Hand I Item . GAL 0 ; 5976 Personnel No. Hours Company 1 12.00 PETROTECHNICAL RESOUR 2 12.00 NABORS Crew (ppm) Trip Gas (ppm) 'Pore. Press (ppm) (ppg) Units Usage On Hand No. Hours o BAROID 23 12.00 Company No. Hours 2' 12.00 Ponted 2/15/2002 6:4235 AM #1 \~ J September 11,2003 Mark Myers, Director Division of Oil and Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, AK 99501 Sarah Palin, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Pre-read Materials Orion Participating Area/Pool Rules/Area InjHction Order Pre-application Meeting Dear Dr. Myers and Chair Palin: Attached for your review are materials that will be presented on Tuesday September 16 at the Orion Participating Area/Pool Rules/Area Injection Order Pre-application Meeting. Any questions can be directed to Jonathan Williams at 564-5854 or Gary Gustafson at 564-5304. Best Regards, :/JM} r ."~ J 1..,/ .,.,./ J ri./'{ £,.// ----. . I t¡li Brian D. Huff I GPB Polaris/Orion Subsurface Team Leader Cc: M. Vela, Exxon Mobil Corp. K. Griffin, Forest Oil Corp. D. Kruse, CPAI G.M. Forsthoff, Chevron U.S.A. Inc. G. Gustafson, BPXA