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Home My WebLink About202-205CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:Klem, Adam Cc:Germann, Shane; Nabors 7ES Company Man Subject:RE: 3S-09 P&A update PTD202-205, sundry 325-682 Date:Friday, January 23, 2026 9:39:58 AM Thanks for the update Adam. When you get a chance please send over the logs and crossplot for our analysis and records (even though FAAB failed). Your plan forward is noted and approved. Jack From: Klem, Adam <Adam.Klem@conocophillips.com> Sent: Friday, January 23, 2026 9:15 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Germann, Shane <Shane.Germann@conocophillips.com>; Nabors 7ES Company Man <NSKRWO.CM@conocophillips.com> Subject: 3S-09 P&A update PTD202-205, sundry 325-682 Jack, As discussed last night we identified a section in the C50 to perform our Formation as a barrier testing. We set a cast iron bridge plug at 6400’ (~75’ below the top of the Coyote) and then perforated in the confining layer at 5505-5507’MD and 5598-5600’MD. We set our test packer at 5558’ MD and pressured up down the drill pipe below the test packer to 830psi (giving us a 0.67psi gradient pressure), observing the IA. We observed the drill pipe pressure slowly decreasing while the IA slowly increased. We reset packer and got the same results. We then picked up the test packer above the top perf, set and tested it, it tested good. So, the FAAB test has failed for this interval. We plan to proceed as per step 13d on the sundry. The top of the Coyote is at 6325’MD, so we will perf from 6225’ (100’ above) to 6375’MD (50’ below). We will wash/jet these perfs and then place a balanced plug from the CIBP at 6400’ MD to 5305’ MD (200’ above the top perf). Thanks, Adam Klem Staff RWO/CTD Engineer ConocoPhillips Alaska 700 G St ATO 566 Anchorage, AK 99510 907-263-4529 Office 970-317-0300 Cell Adam.Klem@conocophillips.com 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9650' None Casing Collapse Structural Conductor Surface Intermediate Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 12/1/2025 3-1/2" Packer: Baker SAB-3 Packer SSSV: None Perforation Depth MD (ft): L-80 3475' 9284-9352' 9612' 5795-5836' 7" Perforation Depth TVD (ft): 108' 3504' 6013'9639' 16" 9-5/8" 79' 8965' MD MD 108' 2596' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Kuparuk River Oil Pool TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0380106 202-205 P.O. Box 100360, Anchorage, AK 99510 50-103-20432-00-00 Kuparuk River Field Kuparuk River Oil Pool- Suspended AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 8933' MD and 5590' TVD N/A Shane Germann Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: Shane.Germann@conocophillips.com (907) 263-4597 CTD/RWO Engineer KRU 3S-09 6020' 8747' 5484' 8965', 8747' N/A Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:21 am, Nov 06, 2025 Digitally signed by Shane Germann DN: O=ConocoPhillips, CN=Shane Germann, E=shane.germann@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.11.06 10:04:20-09'00' Foxit PDF Editor Version: 13.1.6 325-682 DSR-11/6/25A.Dewhurst 02DEC25 See attached conditions of approval addendum. 10-407 X 2268 psi X J.Lau 12.19.25 12/19/25 AOGCC Addendum: 10-403 Abandonments KRU 3S-08C (PTD 207-163) & 3S-09 (PTD 202-205) AOGCC Conditions of Approval: 1. AOGCC witnessed BOP and annular test to 2500 psi. 2. Approved FAAB Tools: Schlumberger Suite Array Sonic Logging Tool (ASLT) & Isolation Scanner (IBC). 3. Operator verify service providers tool calibration and procedures. 4. Send digital Acoustic Impedance AIAV/AIFAV (MRayls), Flexural Attenuation UFAV (dB/m), and CBL Amplitude (mV) data along with AI vs Flex Attenuation crossplot to the AOGCC for determination of FAAB. 5.FAAB test interval shall be no more than 100' long 6. Log acceptance criteria shall at the minimum meet the General Characteristics of Moderate to High bond quality in the attached FAAB Acceptance Criteria table. 7.Creeping Formation Acceptance Criteria 8. If FAAB criteria is net me cement isolation is required in the Coyote by either 1) suicide squeeze or 2) perf and wash followed by balanced cement plug. 9. AOGCC witness tag and PT of TOC for the Moraine, Coyote, and SC Shoe abandonment plugs. 10. AOGCC witness casing cuts before any top job commences. 11. 12. Photo evidence of cement tops post-cut. Creeping Formation Acceptance Criteria A. Description 1. The element consists of creeping formation (plastically deforming formation extruded into the wellbore). 2. Located in the annulus between casing/liner and borehole wall. B. Function 3. Must provide a continuous, permanent seal along the casing annulus. 4. Must . 5. Must resist pressures from above and below C. Design, Construction, and Selection Requirements 6. Formation may be considered a WBE only when it is known to have plastic properties and can be expected to form a seal with acceptable integrity toward axial leakage. 7. The minimum formation interval length shall be 100' MD 8. The formation shall be geologically homogeneous and laterally continuous. 9. Accepted creeping-formation types include: o Claystone, shale, salt, or any low-permeability, ductile, mobile formation with: High smectite/clay content Low cementing minerals (quartz, carbonates, etc.) Low friction angle Low cohesion 10. Excluded formations (not acceptable as WBEs): o Silt, sandstone, limestone, basalt, granite or other permeable, non-mobile formations. 11. withstand the maximum pressure that could be applied. Creeping Formation Acceptance Criteria (Continued) 12. Position and length of the creeping-bond logs, with: a. Two independent logging tools/measurements, both providing azimuthal data. , and documented. c. Log acceptance criteria established before logging operations. 13. Pressure integrity across the interval. o 14. Formation integrity testing (FIT) at the base of the interval must meet the following requirements and align with expected formation strength a. Minimum formation stress/fracture closure pressure (FCP) shall exceed the maximum wellbore pressure at formation depth E. Use 1. The creeping-formation WBE is primarily used in permanently abandoned wells. F. Monitoring 2. None required. G. Common Well Barrier Acceptance Criteria 3. Minimum contact length requirements: a. 100' MD for a single WBE. b. Must include . P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 6, 2025 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits an Application for Approval to Plug & Abandon 3S-09. This sundry covers the portion to be performed on-rig by Nabors 7ES starting in early December 2025. 3S-09 was an injector that has been shut in since early 2024. This well has been suspended with a reservoir cement plug (covered in separate 10-403). The remaining steps to P&A this well include isolating the hydrocarbon bearing intervals behind casing and pumping final abandonment cement plugs with Nabors 7ES and ultimately executing final abandonment. We are also requesting to perform Formation as a Barrier (FAAB) testing on the Coyote confining interval. This testing will likely be focused on the Seabee above the Coyote. Much of the details of the cement program to isolate the Coyote are contingent upon the results of the FAAB testing, but the methodology is described in the program. If you have any questions or require any further information, please contact me at 406-670-1939. Shane Germann Senior Rig Workover Engineer CPAI Drilling and Wells Digitally signed by Shane Germann DN: O=ConocoPhillips, CN=Shane Germann, E=shane.germann@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.11.06 10:04:41-09'00' Foxit PDF Editor Version: 13.1.6 We are also requesting to perform Formation as a Barrier (FAAB) testing on the Coyote confining interval 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 1 of 4 Pre-Rig Work Remaining 1. Abandon Kuparuk (covered in separate suspend sundry #325-594). 2. Slickline drift for punch & cutter. 3. Cut tubing and tubing punch above tagged top of cement. 4. Prepare well for rig arrival. Rig Work MIRU 1. MIRU Nabors 7ES on 3S-09. No BPV will be set for MIRU due to Nabors 7ES internal risk assessment. 2. Circulate seawater and complete 30-minute NFT. Verify well is dead. 3. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/2500 psi. Test annular to 250/2500 psi. Retrieve 3-1/2 Completion 4. Pull BPV, MU landing joint and BOLDS. 5. Pull 3-1/2 tubing string and jewelry from pre-rig cut above TOC. Log to Determine 7 TOC and FAAB Test Zone 6. MU cleanout/drift BHA, PU drillpipe and perform casing cleanout to stub. a. This step may be skipped if tubing conditions warrant or may be performed after logging. 7. Log IBC/DSLT to determine 7 TOC and Formation as a Barrier (FAAB) test zone. Isolate Moraine as follows. a. If TOC is BELOW top of Moraine, set CIBP ~75 below top of Moraine then perforate 50 into Moraine and 100 into confining zone above it to isolate for a total of ~150 cement OA plug. Perforating to be done utilizing Gator tool. Set cement retainer 50 above top perforation and cement squeeze 35 bbls (including excess) of 15.8 ppg Class G cement through retainer. Cement volumes through retainer may be adjusted based on injection capabilities through perforations. Hesitation technique will potentially be used. Lay in 100 of cement on top of retainer (3.8 bbl). WOC. Tag cement and PT to 1500 psi with state witness. b. If TOC is ABOVE top of Moraine, continue to FAAB testing. Perform Formation as a Barrier (FAAB) Testing on Coyote Confining Interval 8. Pick up FAAB testing assembly consisting of CIBP, Gator perforating tool (570 version, 4 blade), and test packer. 9. Set CIBP in 7 casing at bottom of FAAB test zone (near base of Seabee). 10. Perforate 7 casing at base of test interval utilizing Gator perforating tool. a. Three activations, oriented 45° apart and spaced 1 foot apart. 11. Pick up hole, perforate 7 production casing at top of test interval utilizing Gator perforating tool. a. Three activations, oriented 45° apart and spaced 1 foot apart. 12. Conduct injection and circulation tests between zones. 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 1 of 6 Pre-Rig Work Remaining 1. Abandon Kuparuk (covered in separate suspend sundry #325-594). 2. Slickline drift for punch & cutter. 3. Cut tubing and tubing punch above tagged top of cement. 4. Prepare well for rig arrival. Rig Work MIRU 1. MIRU Nabors 7ES on 3S-09. No BPV will be set for MIRU due to Nabors 7ES internal risk assessment. 2. Circulate seawater and complete 30-minute NFT. Verify well is dead. 3. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/2500 psi. Test annular to 250/2500 psi. Retrieve 3-1/2 Completion 4. Pull BPV, MU landing joint and BOLDS. 5. Pull 3-1/2 tubing string and jewelry from pre-rig cut above TOC. Log to Determine 7 TOC and FAAB Test Zone 6. MU cleanout/drift BHA, PU drillpipe and perform casing cleanout to stub. a. This step may be skipped if tubing conditions warrant or may be performed after logging. 7. Log IBC/DSLT to determine 7 TOC and Formation as a Barrier (FAAB) test zone. Isolate Moraine as follows. a. If TOC is BELOW top of Moraine, set CIBP ~75 below top of Moraine then perforate 50 into Moraine and 100 into confining zone above it to isolate for a total of ~150 cement OA plug. Perforating to be done utilizing Gator tool. Set cement retainer 50 above top perforation and cement squeeze 35 bbls (including excess) of 15.8 ppg Class G cement through retainer. Cement volumes through retainer may be adjusted based on injection capabilities through perforations. Hesitation technique will potentially be used. Lay in 100 of cement on top of retainer (3.8 bbl). Perform wash/jetting through perforated interval to clear annular space behind perforations. Place balanced plug from CIBP up to 200 MD above top perforation, apply squeeze pressure as necessary. Pull to safety. WOC. Tag cement and PT to 1500 psi with state witness. b. If TOC is ABOVE top of Moraine, continue to FAAB testing. Perform Formation as a Barrier (FAAB) Testing on Coyote Confining Interval 8. Pick up FAAB testing assembly consisting of CIBP, Gator perforating tool (570 version, 4 blade), and test packer. 9. Set CIBP in 7 casing at bottom of FAAB test zone (near base of Seabee) ~75 below top of Coyote formation. 10. Perforate 7 casing at base of test interval utilizing Gator perforating tool. a. Three activations, oriented 45° apart and spaced 1 foot apart. 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 2 of 4 a. Set test packer between upper and lower perforated intervals. b. Pressure up to 0.67 psi/ft equivalent BHP down drill pipe below test packer. Establish injection while holding 0.67 psi/ft constant for 30 minutes. i. If unable to achieve 0.67 psi/ft BHP, perform test at maximum achievable pressure while holding injection rate constant for 30 minutes. ii. If unable to achieve injection, hold 0.67 psi/ft constant for 30 minutes. c. Monitor casing side for entirety of test to determine pass/fail. i. If no flow or pressure increase seen on casing side, FAAB criteria is met. Continue with P&A. ii. If communication seen on casing side, attempt to establish circulation. Continue with Coyote annular isolation plug. Execute Coyote Isolation Plug 13. Isolate/plug the Coyote interval based on results of the FAAB testing. a. If no injection in perforations and no communication: i. Place 15.8 ppg Class G cement plug from CIBP to 150 feet above top perforation. WOC. Tag and PT to 1500 psi with state witness. b. If no injection in lower perforations and injection in upper perforations: i. Place 15.8 ppg Class G cement plug from CIBP to above lower perforations. ii. Retainer squeeze into upper perforations. Lay in 100 of cement on top of retainer. WOC. Tag and PT to 1500 psi with state witness. c. If there is injection and communication between upper and lower perforations: i. Set cement retainer between upper and lower perforations and perform suicide squeeze. Lay in 15.8 ppg Class G cement from retainer to 150 above top perforation. WOC. Tag and PT to 1500 psi with state witness. d. If there is injection in upper and lower perforations but no communication between zones: i. Set cement retainer 50 above top perforation and perform cement squeeze pumping 15.8 ppg Class G cement. Hesitation technique will potentially be used. Leave 100 of cement on top of retainer. WOC. Tag and PT to 1500 psi with state witness. Cement to Surface 14. Set CIBP in 7 PC at depth of OA TOC (calculated TOC at 1879 RKB, actual TOC will be determined from earlier log). a. Note: Steps 14, 16 & 17 may be performed off-rig pending timing/resources. Well will be freeze protected on the last trip out with drill pipe via hole fill from drill pipe displacement and dry hole tree installed in that scenario. 15. ND BOPE. NU tree. 16. Perforate 7 PC just above OA TOC (calculated TOC at 1879 RKB, actual TOC will be determined from earlier log). Confirm surface-to-surface circulation. 17. Circulate cement surface to surface until full cement returns observed on surface. Job is planned for 125 bbls of cement, plus excess (based on calculated TOC, will update based on actual TOC). 18. RDMO 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 2 of 6 11. Pick up hole, perforate 7 production casing at top of test interval utilizing Gator perforating tool. a. Three activations, oriented 45° apart and spaced 1 foot apart. 12. Conduct injection and circulation tests between zones. Note: 0.67 psi/ft was chosen as test pressure as this is the maximum pressure expected for the Coyote in this area. It also aligns with the approved area injection order for Coyote which has a maximum injection limit of 0.67 psi/ft. a. Set test packer between upper and lower perforated intervals. b. Pressure up to 0.67 psi/ft equivalent BHP down drill pipe below test packer. Establish injection while holding 0.67 psi/ft constant for 30 minutes. i. If unable to achieve 0.67 psi/ft BHP, perform test at maximum achievable pressure while holding injection rate constant for 30 minutes. ii. If unable to achieve injection, hold 0.67 psi/ft constant for 30 minutes. c. Monitor casing side for entirety of test to determine pass/fail. Reference FAAB acceptance criteria table at the end of this document which lists desired quantitative ranges as well as qualitative acceptance criteria for each bond quality. The goal is to achieve at least moderate to high bond quality. i. If no flow or pressure increase seen on casing side, FAAB criteria is met. Continue with P&A. ii. If communication seen on casing side, attempt to establish circulation. Continue with Coyote annular isolation plug. Execute Coyote Isolation Plug 13. Isolate/plug the Coyote interval based on results of the FAAB testing. a. If no injection in perforations and no communication: i. Place 15.8 ppg Class G cement plug from CIBP to 150 feet above top perforation. WOC. Tag and PT to 1500 psi with state witness. b. If no injection in lower perforations and injection in upper perforations: i. Place 15.8 ppg Class G cement plug from CIBP to above lower perforations. Perforate 50 into Coyote and 100 into confining zone above it to isolate for a total of ~150 cement OA plug. Perform wash/jetting through perforated interval to clear annular space behind perforations. Place balanced plug from CIBP up to 200 MD above top perforation, apply squeeze pressure as necessary. Pull to safety. ii. Retainer squeeze into upper perforations. Lay in 100 of cement on top of retainer. WOC. Tag and PT to 1500 psi with state witness. c. If there is injection and communication between upper and lower perforations: i. Set cement retainer between upper and lower perforations and perform suicide squeeze. Lay in 15.8 ppg Class G cement from retainer to 150 above top perforation. WOC. Tag and PT to 1500 psi with state witness. d. If there is injection in upper and lower perforations but no communication between zones: i. Set cement retainer 50 above top perforation and perform cement squeeze pumping 15.8 ppg Class G cement. Hesitation technique will potentially be used. Leave 100 of cement on top of retainer. Perforate 50 into Coyote and 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 3 of 4 Execute Final Abandonment Off-Rig (if not performed on-rig) 1. Set CIBP on E-line in 7 PC at depth of OA TOC (calculated TOC at 1879 RKB, actual TOC will be determined from earlier log). 2. Perforate 7 PC just above OA TOC (calculated TOC at 1879 RKB, actual TOC will be determined from earlier log). Confirm surface-to-surface circulation. 3. Circulate cement surface to surface until full cement returns observed on surface. Job is planned for 125 bbls of cement, plus excess (based on calculated TOC, will update based on actual TOC). Surface Excavation 4. DHD to perform drawdown test on tubing, IA, and OA 5. Remove well house. 6. Bleed off T/I/O to ensure all pressure is bled off the system. 7. Remove tree in preparation for excavation and casing cut. 8. If shallow thaw conditions are found, have shoring box installed during the excavation activity to prevent loose ground from falling into the excavation. 9. Cut off wellhead and all casing strings at 4 feet below original ground level. 10. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and photo document required. 11. Send the casing head with stub to materials shop. Photo document. 12. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information bead welded into the top. Photo document. AOGCC witness required. a. ConocoPhillips b. KRU 3S-09 c. PTD #: 202-205 d. API #: 50-103-20432-00-00 13. Remove cellar. Back fill cellar with gravel/fill as needed. Back fill remaining hole to ground level. 14. Obtain site clearance approval from AOGCC. RDMO. 15. Report the final P&A has been completed to the AOGCC. Photo document final location condition after work is completed 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 3 of 6 100 into confining zone above it to isolate for a total of ~150 cement OA plug. Perform wash/jetting through perforated interval to clear annular space behind perforations. Place balanced plug from CIBP up to 200 MD above top perforation, apply squeeze pressure as necessary. Pull to safety. WOC. Tag and PT to 1500 psi with state witness. Cement to Surface 14. Set CIBP in 7 PC at depth of OA TOC (calculated TOC at 1879 RKB, actual TOC will be determined from earlier log). a. Note: Steps 14, 16 & 17 may be performed off-rig pending timing/resources. Well will be freeze protected on the last trip out with drill pipe via hole fill from drill pipe displacement and dry hole tree installed in that scenario. 15. ND BOPE. NU tree. 16. Perforate 7 PC just above OA TOC (calculated TOC at 1879 RKB, actual TOC will be determined from earlier log). Confirm surface-to-surface circulation. 17. Circulate cement surface to surface until full cement returns observed on surface. Job is planned for 125 bbls of cement, plus excess (based on calculated TOC, will update based on actual TOC). 18. RDMO Execute Final Abandonment Off-Rig (if not performed on-rig) 1. Set CIBP on E-line in 7 PC at depth of OA TOC (calculated TOC at 1879 RKB, actual TOC will be determined from earlier log). 2. Perforate 7 PC just above OA TOC (calculated TOC at 1879 RKB, actual TOC will be determined from earlier log). Confirm surface-to-surface circulation. 3. Circulate cement surface to surface until full cement returns observed on surface. Job is planned for 125 bbls of cement, plus excess (based on calculated TOC, will update based on actual TOC). Surface Excavation 4. DHD to perform drawdown test on tubing, IA, and OA 5. Remove well house. 6. Bleed off T/I/O to ensure all pressure is bled off the system. 7. Remove tree in preparation for excavation and casing cut. 8. If shallow thaw conditions are found, have shoring box installed during the excavation activity to prevent loose ground from falling into the excavation. 9. Cut off wellhead and all casing strings at 4 feet below original ground level. 10. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and photo document required. 11. Send the casing head with stub to materials shop. Photo document. 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 4 of 6 12. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information bead welded into the top. Photo document. AOGCC witness required. a. ConocoPhillips b. KRU 3S-09 c. PTD #: 202-205 d. API #: 50-103-20432-00-00 13. Remove cellar. Back fill cellar with gravel/fill as needed. Back fill remaining hole to ground level. 14. Obtain site clearance approval from AOGCC. RDMO. 15. Report the final P&A has been completed to the AOGCC. Photo document final location condition after work is completed 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 5 of 6 General Well Information: Estimated Start Date: 12/7/2025 12/28/2025 Current Operations: Shut in Well Type: Injector Wellhead Type: FMC Gen V. 11 5M casing head top flange. 11 5M tubing head top flange. Scope of Work: Pull the existing 3-1/2 completion from pre-rig cut above TOC. Perform IBC/DSLT. Isolate Moraine formation. Perform FAAB testing to Coyote confining interval. Isolate Coyote formation. Pump final abandonment plug and ultimately execute final abandonment. BOP Configuration: Annular / Pipe Rams / Blind Rams / Pipe Rams Well Data Kuparuk Formation: Reservoir pressure 3/9/2024 = 2847 psi @ 5795 TVD = 9.5 ppg EMW MASP = 2268 psi Coyote Formation: Reservoir Pressure estimate from Reservoir Engineering = 1810 psi @ 4139 TVD = 8.4 ppg EMW MASP = 1397 psi Nearest Coyote offset (3S-722 on 11/27/2024) = 1790 psi a@ 4106 TVD = 8.4 ppg EMW Moraine Formation: Reservoir Pressure estimate from Reservoir Engineering = 2297 psi @ 5255 TVD = 8.4 ppg EMW MASP = 1772 psi Planned Kuparuk Reservoir plug TOC = 8747 MD Planned tubing cut depth = ~8640 MD Personnel: Workover Engineer: Shane Germann (406-670-1939) / Shane.Germann@conocophillips.com Intervention Engineer: Jill Simek (907-263-4131) / Jill.Simek@conocophillips.com 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 6 of 6 FAAB Acceptance Criteria: 3S-09 Kuparuk Producer Plug & Abandon w/FAAB Testing PTD: 202-205 Page 4 of 4 General Well Information: Estimated Start Date: 12/7/2025 Current Operations: Shut in Well Type: Injector Wellhead Type: FMC Gen V. 11 5M casing head top flange. 11 5M tubing head top flange. Scope of Work: Pull the existing 3-1/2 completion from pre-rig cut above TOC. Perform IBC/DSLT. Isolate Moraine formation. Perform FAAB testing to Coyote confining interval. Isolate Coyote formation. Pump final abandonment plug and ultimately execute final abandonment. BOP Configuration: Annular / Pipe Rams / Blind Rams / Pipe Rams Well Data Kuparuk Formation: Reservoir pressure 3/9/2024 = 2847 psi @ 5795 TVD = 9.5 ppg EMW MASP = 2268 psi Coyote Formation: Reservoir Pressure estimate from Reservoir Engineering = 1810 psi @ 4139 TVD = 8.4 ppg EMW MASP = 1397 psi Nearest Coyote offset (3S-722 on 11/27/2024) = 1790 psi a@ 4106 TVD = 8.4 ppg EMW Moraine Formation: Reservoir Pressure estimate from Reservoir Engineering = 2297 psi @ 5255 TVD = 8.4 ppg EMW MASP = 1772 psi Planned Kuparuk Reservoir plug TOC = 8747 MD Planned tubing cut depth = ~8640 MD Personnel: Workover Engineer: Shane Germann (406-670-1939) / Shane.Germann@conocophillips.com Intervention Engineer: Jill Simek (907-263-4131) / Jill.Simek@conocophillips.com Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM ( EST. 71' OF RAT HOLE ) 9,411.0 3S-09 3/19/2010 pproven Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Cement Job 3S-09 10/30/2025 famaj Notes: General & Safety Annotation End Date Last Mod By NOTE: Waivered for Water-Only Injection due to TxIA on gas 8/31/2017 pproven NOTE: Surf CSG Patch - seal weld starter head & collar; weld 45" of 16"X.374 wall conductor pipe 4/13/2010 lmosbor NOTE: 3/26/2010 pproven Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELD SURFACE 9 5/8 8.83 28.5 3,503.6 2,595.6 40.00 L-80 BTC PRODUCTION 7 6.28 26.3 9,638.7 6,012.8 26.00 L-80 BTCM Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 24.1 Set Depth 8,965.2 Set Depth 5,608.0 String Max No 3 1/2 Tubing Description TUBING Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE 8RD ID (in) 2.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 24.1 24.1 0.13 HANGER 8.000 FMC 3 1/2" GEN 5 Tbg Hanger w/ 3- 1/2" tbg. Pup (2.62') on btm FMC GEN 5 2.992 497.2 496.2 6.25 NIPPLE 4.520 3.5" Camco"DS" Nipple w/2.875" NO GO Camco DS 2.875 8,832.1 5,531.7 55.35 GAS LIFT 5.968 Camco 3.5" x 1.5" MMG w/ DCR Shear Valve, RK Latch 2.92" ID 5.968" OD Camco MMG 2.920 8,877.9 5,557.9 55.10 NIPPLE 4.520 Camco "DS" nipple w/ 2.812 no go Camco DS 2.812 8,916.4 5,579.9 54.93 SEAL ASSY 5.875 Locator Sub & PBR Seal Assembly (spaced out) 3.000 8,918.7 5,581.3 54.92 PBR 5.870 Baker 3 1/2" 80-40 PBR W/ XO Baker 2.980 8,932.1 5,588.9 54.86 ANCHOR 4.730 KBH-22 Anchor Tubing Seal Nipple 3.000 8,933.0 5,589.5 54.86 PACKER 5.956 3 1/2" x 7" Baker SAB-3 Packer 5.956" OD x 2.992" ID Baker SAB-3 2.992 8,937.9 5,592.3 54.84 EXTENSION 4.500 4-1/2" 80-40 Mill out Extension Baker 3.720 8,943.5 5,595.5 54.81 XO 4.500 X/O 3-1/2" x 4-1/2" w/ 4 1/2" collar 2.992 8,957.1 5,603.4 54.75 NIPPLE 4.540 3.5" Camco"D" Nipple w/2.75" NO GO Camco D 2.750 8,964.3 5,607.5 54.72 WLEG 4.510 3 1/2" WLEG with Shear out Sub 5" OD 2.990 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 8,862.0 5,548.8 55.17 CEMENT RETAINER FH 1 TRIP CEMENT RETAINER 10/30/2025 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 8,832.1 5,531.7 55.35 1 GAS LIFT DMY RK 1 1/2 0.0 12/21/2002 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 9,284.0 9,302.0 5,795.0 5,805.7 C-4, 3S-09 12/25/2002 6.0 IPERF 2506 PJ Chrgs, 60 deg phase 9,302.0 9,332.0 5,805.7 5,823.7 C-4, 3S-09 12/24/2002 6.0 IPERF 2506 PJ Chrgs, 60 deg phase 9,332.0 9,352.0 5,823.7 5,835.7 C-4, 3S-09 12/25/2002 6.0 IPERF 2506 PJ Chrgs, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 8,747.0 8,965.0 5,483.7 5,607.9 Plug & Abandonment PUMPED 31.5 BBL 15.8 CLASS G CEMENT W/ GASBLOCK 10/30/2025 8,965.0 9,352.0 5,607.9 5,835.7 Plug & Abandonment PUMPED 31.5 BBL 15.8 CLASS G CEMENT W/ GASBLOCK 10/30/2025 3S-09, 11/5/2025 12:50:16 PM Vertical schematic (actual) PRODUCTION; 26.3-9,638.7 IPERF; 9,332.0-9,352.0 IPERF; 9,302.0-9,332.0 IPERF; 9,284.0-9,302.0 Plug & Abandonment; 8,965.0 ftKB PACKER; 8,933.0 CEMENT RETAINER; 8,862.0 GAS LIFT; 8,832.1 Plug & Abandonment; 8,747.0 ftKB SURFACE; 28.5-3,503.6 NIPPLE; 497.2 CONDUCTOR; 29.0-108.0 KUP INJ KB-Grd (ft) 33.50 RR Date 12/17/200 2 Other Elev 3S-09 ... TD Act Btm (ftKB) 9,650.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032043200 Wellbore Status INJ Max Angle & MD Incl (°) 59.46 MD (ftKB) 4,380.31 WELLNAME WELLBORE3S-09 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE 3S-09 Pre-rig Schematic COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread (top) Thread (btm) Conductor 108 108 16 15.062 62.5 H-40 #N/A #N/A Surface 3503 2595 9.625 8.92 40 L-80 BTC BTC Production/ Intermediate 9638 6012 7 6.28 26 L-80 BTCM BTCM Surface Casing shoe at 3503' RKB Production Casing shoe at 9638' RKB C-sand perfs 9284 - 9352' RKB Conductor Production Casing(8.5" OH) Calculated/Estimated TOC: 6850' RKB , 8950' from CBL from 12/23/2002 Cement Detail/CBL (tubing tail depth) Surface Casing Estimated TOC: Surface Arctic Pack Cement Calculated TOC: 1879' RKB Shoe pumped 2/4/2008 42 bbls cmt pumped, displaced with 53 bbls diesel MIT-OA passed in 2010 after shallow SC leak patched Moraine Top: 8209' MD Base: 8464' MD Coyote Top: 6325' MD Base: 7534' MD CURRENT COMPLETION 3-1/2" 9.3# L-80 EUE 8rd Tubing to surface 3-1/2" DS nipple @ 497' RKB (2.875" min ID) 3-1/2" x 1-1/2" MMG GLM @ 8832' RKB 3-1/2" DS nipple @ 8877' RKB (2.812" min ID) Seal Assembly @ 8916' RKB Baker 80-40 PBR @ 8918' RKB KBH-22 Anchor @ 8932' RKB Baker SAB-3 Packer @ 8933' RKB (2.992" ID) MOE @ 8937' RKB (3.72" ID) XO 3.5" x 4.5" @ 8943' RKB Camco D nipple @ 8957' RKB (2.75" ID) WLEG @ 8964' RKB Confining Interval Top: 3725' MD Seabee top: 5955' MD 3S-09 Moraine Abandonment Schematic COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread (top) Thread (btm) Conductor 108 108 16 15.062 62.5 H-40 #N/A #N/A Surface 3503 2595 9.625 8.92 40 L-80 BTC BTC Production/ Intermediate 9638 6012 7 6.28 26 L-80 BTCM BTCM Perforate from 8259' up to 8109' MD CIBP at ~ 8284' MD Surface Casing shoe at 3503' RKB Production Casing shoe at 9638' RKB C-sand perfs 9284 - 9352' RKB Conductor Production Casing(8.5" OH) Calculated/Estimated TOC: 6850' RKB , 8950' from CBL from 12/23/2002 Cement Detail/CBL (tubing tail depth) Surface Casing Estimated TOC: Surface Arctic Pack Cement Calculated TOC: 1879' RKB Shoe pumped 2/4/2008 42 bbls cmt pumped, displaced with 53 bbls diesel MIT-OA passed in 2010 after shallow SC leak patched Moraine Top: 8209' MD Base: 8464' MD Coyote Top: 6325' MD Base: 7534' MD CURRENT COMPLETION Tubing Cut @ XXXX' RKB Tubing Punch @ XXXX' RKB Cement Retainer @ ~8862' RKB 3-1/2" x 1-1/2" MMG GLM @ 8832' RKB 3-1/2" DS nipple @ 8877' RKB (2.812" min ID) Seal Assembly @ 8916' RKB Baker 80-40 PBR @ 8918' RKB KBH-22 Anchor @ 8932' RKB Baker SAB-3 Packer @ 8933' RKB (2.992" ID) MOE @ 8937' RKB (3.72" ID) XO 3.5" x 4.5" @ 8943' RKB Camco D nipple @ 8957' RKB (2.75" ID) WLEG @ 8964' RKB Confining Interval Top: 3725' MD Seabee top: 5955' MD 3S-09 FAAB Schematic COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread (top) Thread (btm) Conductor 108 108 16 15.062 62.5 H-40 #N/A #N/A Surface 3503 2595 9.625 8.92 40 L-80 BTC BTC Production/ Intermediate 9638 6012 7 6.28 26 L-80 BTCM BTCM Surface Casing shoe at 3503' RKB Production Casing shoe at 9638' RKB C-sand perfs 9284 - 9352' RKB Conductor Production Casing(8.5" OH) Calculated/Estimated TOC: 6850' RKB , 8950' from CBL from 12/23/2002 Cement Detail/CBL (tubing tail depth) Surface Casing Estimated TOC: Surface Arctic Pack Cement Calculated TOC: 1879' RKB Shoe pumped 2/4/2008 42 bbls cmt pumped, displaced with 53 bbls diesel MIT-OA passed in 2010 after shallow SC leak patched Moraine Top: 8209' MD Base: 8464' MD Coyote Top: 6325' MD Base: 7534' MD CURRENT COMPLETION Tubing Cut @ XXXX' RKB Tubing Punch @ XXXX' RKB Cement Retainer @ ~8862' RKB 3-1/2" x 1-1/2" MMG GLM @ 8832' RKB 3-1/2" DS nipple @ 8877' RKB (2.812" min ID) Seal Assembly @ 8916' RKB Baker 80-40 PBR @ 8918' RKB KBH-22 Anchor @ 8932' RKB Baker SAB-3 Packer @ 8933' RKB (2.992" ID) MOE @ 8937' RKB (3.72" ID) XO 3.5" x 4.5" @ 8943' RKB Camco D nipple @ 8957' RKB (2.75" ID) WLEG @ 8964' RKB Confining Interval Top: 3725' MD Seabee top: 5955' MD 3S-09 Final P&A Schematic COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread (top) Thread (btm) Conductor 108 108 16 15.062 62.5 H-40 #N/A #N/A Surface 3503 2595 9.625 8.92 40 L-80 BTC BTC Production/ Intermediate 9638 6012 7 6.28 26 L-80 BTCM BTCM Surface Casing shoe at 3503' RKB Production Casing shoe at 9638' RKB C-sand perfs 9284 - 9352' RKB Conductor Production Casing(8.5" OH) Calculated/Estimated TOC: 6938' RKB , 8950' from CBL from 12/23/2002 Cement Detail/CBL (tubing tail depth) Surface Casing Estimated TOC: Surface Arctic Pack Cement Calculated TOC: 1879' RKB Shoe pumped 2/4/2008 42 bbls cmt pumped, displaced with 53 bbls diesel MIT-OA passed in 2010 after shallow SC leak patched Moraine Top: 8209' MD Base: 8464' MD Coyote Top: 6325' MD (4139' TVD) Base: 7534' MD CURRENT COMPLETION Tubing Cut @ XXXX' RKB Tubing Punch @ XXXX' RKB Cement Retainer @ ~8862' RKB 3-1/2" x 1-1/2" MMG GLM @ 8832' RKB 3-1/2" DS nipple @ 8877' RKB (2.812" min ID) Seal Assembly @ 8916' RKB Baker 80-40 PBR @ 8918' RKB KBH-22 Anchor @ 8932' RKB Baker SAB-3 Packer @ 8933' RKB (2.992" ID) MOE @ 8937' RKB (3.72" ID) XO 3.5" x 4.5" @ 8943' RKB Camco D nipple @ 8957' RKB (2.75" ID) WLEG @ 8964' RKB Confining Interval Top: 3725' MD Seabee top: 5955' MD 1 From:Lau, Jack J (OGC) Sent:Friday, December 19, 2025 8:57 AM To:Christianson, Grace K (OGC) Subject:KRU 3S-08C RE: Formation as a Barrier From: Germann, Shane <Shane.Germann@conocophillips.com> Sent: Monday, December 15, 2025 10:09 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Cc: Livingston, Erica J <Erica.J.Livingston@conocophillips.com>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Buck, Brian R <Brian.R.Buck@conocophillips.com> Subject: RE: [EXTERNAL]RE: Formation as a Barrier Hi Jack, Im following up on a couple ac on items from our mee ng last week. Please let me know if there are any other ques ons. De ning qualita ve acceptance criteria: Our internal SME for FAAB advised us to use the General Characteris cs in the table from the AkerBP Norway shale barrier study as our qualita ve acceptance criteria. The quan ta ve values from that table will be used as our star ng point with the acknowledgement that these may need re ned based on our tes ng. Ive re-built the table for our use while adding in the CBL amplitude ranges for 7 casing. See below. 100 min/max (100 max distance between perfora ons for pressure tes ng): Our SME was not aware of intervals of shale greater than 100 being tested. He men oned salt intervals in the UK having longer test intervals but not shale barriers. We acknowledge and understand the 100 min/max being derived from NORSOK D010.v4. 2 Thanks, Shane From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Monday, December 8, 2025 1:34 PM To: Germann, Shane <Shane.Germann@conocophillips.com >; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Cc: Livingston, Erica J <Erica.J.Livingston@conocophillips.com >; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]RE: Formation as a Barrier Greg, Shane, We would like to meet after Thursdays 10 am monthly check in to nalize the formation as a barrier criteria for wells 3S-08C and 3S-09. Please bring CPAIs proposed acceptable ranges for AI, exural attenuation, and CBL amplitude for these two wells specially. We realize that FAAB criteria will be better de ned with additional wells and testing, but a predetermined starting point should be established. 3 Jack From: Germann, Shane <Shane.Germann@conocophillips.com> Sent: Thursday, November 20, 2025 3:53 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Livingston, Erica J <Erica.J.Livingston@conocophillips.com> Subject: RE: [EXTERNAL]RE: Formation as a Barrier Hi Jack, I apologize for the late response. We wanted to make sure we were aligned with our internal strategy globally. Also, its looking like these projects will be delayed from the an cipated start mes I submi ed with the sundry. I expect Nabors 7ES will be ready to move to 3S around December 20th, but I will keep you informed as we work through the 2P project and have a clearer meline. For the logging tools, well be using a Schlumberger suite with the Array Sonic Logging Tool (ASLT) and Isola on Scanner (IBC) tool. The Digital Sonic Logging Tool (DSLT) has previously been used on 3S for logging FAAB intervals and is also acceptable, but we recently used the newer ASLT tool on the 2P projects and were happy with the performance. Acceptable ranges for AI, exural a enua on, and CBL amplitude havent been de ned, but keep in mind were in the infancy of developing FAAB criteria for the Seabee. This tes ng at 3S will help build out the acceptable ranges. We are looking for intervals that fall into moderate-to-high bond quality or be er based on the table developed from Norway tes ng. The cross plot may be processed if theres uncertainty around the material at depth. If we dont see the bond quality were looking for were not concerned about the nature of the material. Thanks, Shane Germann CTD/RWO Engineer ConocoPhillips Alaska O ice: 907-263-4597 Cell: 406-670-1939 700 G St, ATO 1494, Anchorage, AK 99501 From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Monday, November 17, 2025 12:31 PM To: Germann, Shane <Shane.Germann@conocophillips.com > Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Simek, Jill <Jill.Simek@conocophillips.com> Subject: [EXTERNAL]RE: Formation as a Barrier CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Shane, 4 Im following up on my previous email below and have a few additional questions. Please describe the supplier speci c tools planned for the Azimuthal CBL and Isolation Scanner. Will an AI vs Flex Attenuation cross plot be processed? Jack From: Lau, Jack J (OGC) Sent: Monday, November 10, 2025 2:59 PM To: 'Simek, Jill' <Jill.Simek@conocophillips.com> Cc: Germann, Shane <Shane.Germann@conocophillips.com >; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: Formation as a Barrier Thanks Jill, I appreciate the follow up.. Shane, what are the acoustic impedance, exural attenuation, and CBL amplitude ranges CPAI would accept for formation as a barrier? Jack From: Simek, Jill <Jill.Simek@conocophillips.com> Sent: Monday, November 10, 2025 2:40 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Germann, Shane <Shane.Germann@conocophillips.com >; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: Formation as a Barrier Jack, Following up from Thursday, attached are the slides from last time ConocoPhillips updated the AOGCC on Formation as a Barrier (2+ years ago!) This presentation includes examples of Formation as a Barrier log responses and geology/minerology of 3S Coyote and overburden. We plan to update this presentation for the meeting Greg will be scheduling later this month. Regarding 3S-08C, I shared your question about expected impedance, ex attenuation, and CBL amplitude ranges with Shane Germann (in cc). Shane should be able to provide more information on this and any other questions you have regarding the sundry application. Thanks, Jill Simek Well Interventions Engineer | ConocoPhillips Alaska ATO-1400 M: 907-980-7503 / O: 907-263-4131 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Originated: Delivered to:4-Dec-25Alaska Oil & Gas Conservation Commiss04Dec25-NR !"#$$%$ !&$$'($) *%+ ($)*%,-.WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED2P-447 50-103-20468-00-00 203-154 Kuparuk River WL IBC-CBL FINAL FIELD18-Nov-253S-08&50-103-20450-03-00 207-163 Kuparuk River WL Cutter FINAL FIELD 21-Nov-253S-09 50-103-20432-00-00 202-205 Kuparuk River WL Cutter FINAL FIELD 22-Nov-253S-705 50-103-20915-00-00 225-047 Kuparuk River WL TTiX-iPROF-SCMT FINAL FIELD 28-Nov-253S-721 50-103-20911-00-00 225-025 Kuparuk River WL TTiX-iPROF FINAL FIELD 1-Dec-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1Please return via courier or sign/scan and email a copy to Schlumberger."2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8" ! - +"8#!(3 . 8)"3 8#!9 3 : 8" +868 8 "8#!;" " 3 - 3" 3""+ 3 + <+3!% T41188T11189T41190T41191T411923S-0950-103-20432-00-00202-205Kuparuk RiverWLCutterFINAL FIELD22-Nov-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.12.05 11:22:02 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9650' None Casing Collapse Structural Conductor Surface Intermediate Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 265-1513 Staff P&A Engineer KRU 3S-09 6020' 9411' 5871' None N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: Joey.Roth@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 8933' MD and 5590' TVD N/A Joey Roth STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0380106 202-205 P.O. Box 100360, Anchorage, AK 99510 50-103-20432-00-00 Kuparuk River Field Kuparuk River Oil Pool ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Kuparuk River Oil Pool TVD Burst 8965' MD MD 108' 2596' 108' 3504' 6013'9639' 16" 9-5/8" 79' 3475' 9284-9352' 9612' 5795-5836' 7" Perforation Depth TVD (ft): 10/10/2025 3-1/2" Packer: Baker SAB-3 Packer SSSV: None Perforation Depth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:50 pm, Oct 01, 2025 Digitally signed by Joey Roth DN: CN=Joey Roth, E=Joey.Roth@conocophillips.com, C=US Reason: I am the author of this document Location: Date: 2025.10.01 07:33:37-08'00' Foxit PDF Editor Version: 13.1.6 Joey Roth 325-594 DSR-10/2/25 10-407 A.Dewhurst 01OCT25 June 30, 2026 AOGCC witness tag TOC and pressure test to 1500 psi. X JJL 10/9/25 X 10/10/25 Well Status and History: Procedure: Slick line / LRS Objective: Coil Tubing / Cementing: Objective: Total BBL. Cement to pump: 28 bbl. + 1bbl (top of retainer) 29 bbl 21. WOC (24 hours minimum). 22. Notify the AOGCC Inspector of the timing for the cement plug tag and test 24 hrs. in advance. Slickline / LRS: Objective: Tubular Detail: Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM ( EST. 71' OF RAT HOLE ) 9,411.0 3S-09 3/19/2010 pproven Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: WAIVER for WATER-ONLY INJECTION - SEE NOTES 3S-09 2/7/2018 pproven Notes: General & Safety Annotation End Date Last Mod By NOTE: Waivered for Water-Only Injection due to TxIA on gas 8/31/2017 pproven NOTE: Surf CSG Patch - seal weld starter head & collar; weld 45" of 16"X.374 wall conductor pipe 4/13/2010 lmosbor NOTE: 3/26/2010 pproven Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELD SURFACE 9 5/8 8.83 28.5 3,503.6 2,595.6 40.00 L-80 BTC PRODUCTION 7 6.28 26.3 9,638.7 6,012.8 26.00 L-80 BTCM Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 24.1 Set Depth 8,965.2 Set Depth 5,608.0 String Max No 3 1/2 Tubing Description TUBING Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE 8RD ID (in) 2.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 24.1 24.1 0.13 HANGER 8.000 FMC 3 1/2" GEN 5 Tbg Hanger w/ 3- 1/2" tbg. Pup (2.62') on btm FMC GEN 5 2.992 497.2 496.2 6.25 NIPPLE 4.520 3.5" Camco"DS" Nipple w/2.875" NO GO Camco DS 2.875 8,832.1 5,531.7 55.35 GAS LIFT 5.968 Camco 3.5" x 1.5" MMG w/ DCR Shear Valve, RK Latch 2.92" ID 5.968" OD Camco MMG 2.920 8,877.9 5,557.9 55.10 NIPPLE 4.520 Camco "DS" nipple w/ 2.812 no go Camco DS 2.812 8,916.4 5,579.9 54.93 SEAL ASSY 5.875 Locator Sub & PBR Seal Assembly (spaced out) 3.000 8,918.7 5,581.3 54.92 PBR 5.870 Baker 3 1/2" 80-40 PBR W/ XO Baker 2.980 8,932.1 5,588.9 54.86 ANCHOR 4.730 KBH-22 Anchor Tubing Seal Nipple 3.000 8,933.0 5,589.5 54.86 PACKER 5.956 3 1/2" x 7" Baker SAB-3 Packer 5.956" OD x 2.992" ID Baker SAB-3 2.992 8,937.9 5,592.3 54.84 EXTENSION 4.500 4-1/2" 80-40 Mill out Extension Baker 3.720 8,943.5 5,595.5 54.81 XO 4.500 X/O 3-1/2" x 4-1/2" w/ 4 1/2" collar 2.992 8,957.1 5,603.4 54.75 NIPPLE 4.540 3.5" Camco"D" Nipple w/2.75" NO GO Camco D 2.750 8,964.3 5,607.5 54.72 WLEG 4.510 3 1/2" WLEG with Shear out Sub 5" OD 2.990 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 8,832.1 5,531.7 55.35 1 GAS LIFT DMY RK 1 1/2 0.0 12/21/2002 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 9,284.0 9,302.0 5,795.0 5,805.7 C-4, 3S-09 12/25/2002 6.0 IPERF 2506 PJ Chrgs, 60 deg phase 9,302.0 9,332.0 5,805.7 5,823.7 C-4, 3S-09 12/24/2002 6.0 IPERF 2506 PJ Chrgs, 60 deg phase 9,332.0 9,352.0 5,823.7 5,835.7 C-4, 3S-09 12/25/2002 6.0 IPERF 2506 PJ Chrgs, 60 deg phase 3S-09, 9/30/2025 5:39:59 PM Vertical schematic (actual) PRODUCTION; 26.3-9,638.7 IPERF; 9,332.0-9,352.0 IPERF; 9,302.0-9,332.0 IPERF; 9,284.0-9,302.0 PACKER; 8,933.0 GAS LIFT; 8,832.1 SURFACE; 28.5-3,503.6 NIPPLE; 497.2 CONDUCTOR; 29.0-108.0 KUP INJ KB-Grd (ft) 33.50 RR Date 12/17/200 2 Other Elev 3S-09 ... TD Act Btm (ftKB) 9,650.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032043200 Wellbore Status INJ Max Angle & MD Incl (°) 59.46 MD (ftKB) 4,380.31 WELLNAME WELLBORE3S-09 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, October 17, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 3S-09 KUPARUK RIV UNIT 3S-09 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/17/2023 3S-09 50-103-20432-00-00 202-205-0 W SPT 5589 2022050 3000 210 220 220 220 16 18 18 18 REQVAR P Guy Cook 9/22/2023 MITIA to maximum anticipated injection pressure per AIO 2C.046. Testing completed with a Little Red Services pump truck and calibrated gauges. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 3S-09 Inspection Date: Tubing OA Packer Depth 150 3300 3200 3175IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC230921163201 BBL Pumped:3.4 BBL Returned:3.4 Tuesday, October 17, 2023 Page 1 of 1 9 9 9 9 9 9 9 9 9 99 9 9 9 AIO 2C.046. James B. Regg Digitally signed by James B. Regg Date: 2023.10.17 15:37:52 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:NSK DHD Field Supervisor To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Cc:Well Integrity Specialist CPF1 & CPF3; WNS Integrity Subject:10-426 forms for MT6-09 witnessed & 3S-09 non-witnessed MIT-IA"s 8-11-24 Date:Monday, August 12, 2024 7:29:51 AM Attachments:image001.png MIT KRU 3S-09 non-witnessed 08-11-24.xlsx MIT GMTU MT6-09 08-11-24.xlsx Morning, Please see the attached 10-426 forms from the AOGCC witnessed MIT-IA on MT6-09 & the non-witnessed MIT-IA on 3S-09 that were performed on 8-11-24. If you have any questions, please let me know. Thanks, Matt Miller/ Bruce Richwine DHD Field Supervisor KOC F-wing 2-14 (907) 659-7022 Office (907) 943-0167 Cell N2238@COP.com .586 37' Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2022050 Type Inj N Tubing 700 700 700 700 Type Test P Packer TVD 5590 BBL Pump 3.2 IA 500 3300 3225 3200 Interval V Test psi 1500 BBL Return 3.1 OA 12 13 13 13 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Kuparuk / KRU / 3S Pad Galle/Cook 08/11/24 Notes:MITIA to maximum anticipated injection pressure per AIO 2C.046 Notes: 3S-09 Notes: Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)2024-0811_MIT_KRU_3S-09 9 9 9 9 999 9 9 -5HJJ • • Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF3 and WNS <n2549@conocophillips.com> Sent: Tuesday, July 4, 2017 11:09 AM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: 3S-09 (,PTD 202-205) Suspect IA pressurization update Attachments: 3S-09 90-day TIO Plot 7-4-17.docx Chris, This is an update for 3S-09 (PTD 202-205), which is a WAG injector on a 30-day gas injection monitor to investigate slow IA pressurization. DHD obtained a passing diagnostic MITIA and passing packoff tests on 6/27/17. They also bled the IA for an extended drawdown test. The IA pressure has risen since the initial bleed for the drawdown test, however, so has the temperature and injection rate. The plan forward is to finish out the 30-day gas injection monitor to confirm the suspected TxIA on gas and to make the necessary operational adjustments to WAG the well to water. If TxIA communication on gas is confirmed, CPAI then intends to WAG the well to water for a 30-day monitor period to confirm integrity on water injection. If integrity is confirmed on water,the monitor will be followed by an application for an AA to allow water only injection. Please let me know if you have any questions or disagree with this plan. Attached is the 90-day TIO plot. Regards, Rachel Kautz/Travis Smith Well Integrity Supervisor,ConocoPhillips Alaska Inc. Office:907-659-7126 Cell:907-943-0450 %AHMED JUL 11201Z • • W U 7 W C7 Z Q_X N W w U W N C Q. o .1 2 N cc a 0 m Z m W W fu c' M .;:-!a) CC• N r r_ 0 0 IBJ Z N N F -ri Nr O Jaiai J o 0 Z U1 U1 r, j6aP f Y G i 1 1 1 I I i I 1 1 n 1.1.- t I W U C nsgl 7 colC R I °I V i + g p C1 E o 4'(!! U y A d o C 3 i z C QN........, r w o C 0 C M N O v n a S r. ' o f i i 11111 n ;; m �I 1 I I I it D io u y u u u u u I- c 8 $ 8 8 C y d V V of N " - n i3 -h o w isd aditrod�v • Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF3 and WNS <n2549@conocophillips.com> Sent: Monday,June 26, 2017 12:03 PM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: RE: 3S-09 (PTD 202-205) Suspect Slow IA Pressure Increase Chris, KRU 3S-09(PTD#202-205) IA pressure has elevated again during the 30-day monitoring period. As discussed below,our intent is to perform diagnostics with DHD(while the well is in its current state of gas injection). We will update you again when those diagnostics are complete with a path forward. Please let us know if you have any questions or disagree with this plan. Thanks, Travis From: NSK Well Integrity Supv CPF3 and WNS Sent: Monday,June 12,2017 12:15 PM SCANNED .,i!JL 1 r 0 To:Wallace, Chris D(DOA)<chris.wallace@alaska.gov> Cc:Senden, R.Tyler<R.Tyler.Senden@conocophillips.com> Subject:3S-09 (PTD 202-205) Suspect Slow IA Pressure Increase Chris, 3S-09 (PTD 202-205) is a WAG injector currently on gas injection and has been identified with a slowly increasing IA pressure trend. The current plan is to bleed down the IA pressure and put the well on a 30-day monitor to further scrutinize and identify if the IA pressure rise is connected to the wells thermal condition or something else. If the IA continues to look suspicious, CPAI plans to send DHD to do diagnostics and update you with the results and plan forward. Attached is a 90-day TIO plot. Please let us know if you have any questions or disagree with this plan. Regards, Rachel Kautz/Travis Smith Well Integrity Supervisor,ConocoPhillips Alaska Inc. Office:907-659-7126 Cell:907-943-0450 1 0 • Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF3 and WNS <n2549@conocophillips.com> Sent: Monday, June 12, 2017 12:15 PM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler Subject: 3S-09 (PTD 202-205) Suspect Slow IA Pressure Increase Attachments: 3S-09 90-day TIO plot.pdf Chris, 3S-09 (PTD 202-205) is a WAG injector currently on gas injection and has been identified with a slowly increasing IA pressure trend. The current plan is to bleed down the IA pressure and put the well on a 30-day monitor to further scrutinize and identify if the IA pressure rise is connected to the wells thermal condition or something else. If the IA continues to look suspicious, CPAI plans to send DHD to do diagnostics and update you with the results and plan forward. Attached is a 90-day TIO plot. Please let us know if you have any questions or disagree with this plan. Regards, Rachel Kautz/Travis Smith Well Integrity Supervisor,ConocoPhillips Alaska Inc. Office:907-659-7126 Cell:907-943-0450 scANNED JUN 2 32Q17 • ' • dwallajlagla 0 0 0 0 N .11 1 , I , I' 1, .I , I L .I. d I . I,.. 1 I ,I , 1 , I ,I. ,t , r— _ e— 1 - I ea 2 I 6 co ''? N.- ,-- ..,T- co- 2 I .....c c/" 2 . C N O r h- p L` Q Q I N h- th 11 O I',- I LQ I i-N 1I_ 1-t ~ I ui II I'I I' I I III I'I I' I I I '1 III P I I I 'I PI III I I 'I I'i I' I 2 01_ 4 o 0 0 0 Co 0 C''� N N T- � u--.) ISd • • Page 1 of 3 Maunder, Thomas E (DOA) From: NSK Prod Engr Specialist [n1139 @conocophillips.com] Sent: Thursday, January 27, 2011 9:09 AM To: Maunder, Thomas E (DOA) Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); Colombie, Jody J (DOA); NSK Prod Engr & Optimization Supv; NSK Fieldwide Operations Supt; Bradley, Stephen D Subject: FW: RE: Request for Approval Attachments: Kuparuk Gas Injector Flow back Volumes.xls Tom, Attached you will find the Kuparuk Gas Injector Flowback information per your request. Bob Christensen / Darrell Humphrey NSK Production Engineering Specialist ConocoPhiilips Alaska, Inc. F ► AtP FEU 2 8 t 011 . Kuparuk Office: 907.659.7535 Kuparuk Pager: 659.7000; #924 CPAI Internal Mail: N5K -69 This email may contain confidential information. If you receive this e-mail in error ilease notify the sender and delete this email immediately. LJ From: Maunder, Thomas E (DOA) Imailto :tom.maunderOalaska.govJ Sent: Tuesday, January 25, 2011 9:09 AM To: NSK Prod Engr & Optimization Supv Subject: RE: Request for Approval Gary/Denise, Following up on my brief conversation with Gary the other day, could one of you provide some information with regard to the flowback of these WAG injectors while TAPS was unavailable. Please copy everyoned as before with your response. Thanks in advance, Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Tuesday, January 11, 2011 9:59 AM 1 To: 'NSK Prod Engr & Optimization Supv' Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); NSK Prod Engr Specialist; Colombie, Jody J (DOA) Subject: RE: Request for Approval Gary, et al, have spoken with Commissioner Foerster and she has given her approval to proceed with the planned flowback of the listed wells as described. Volumes should be tracked /recorded as planned. At this time it is not necessary to submit Form 10 -403 for the wells. Form 10 -404 will likely need to be submitted for each well following the conclusion of this extraordinary situation. Gas disposition will also need to be reported. I will place a copy of this message in the well files. Please keep us advised of the situation. Call or message with any questions. 1/27/2011 • Page 2 of 3 • Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv jmailto:n2046@ conocophillips.comJ Sent: Monday, January 10, 2011 4:44 PM To: Maunder, Thomas E (DOA) Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); NSK Prod Engr Specialist Subject: RE: Request for Approval Tom, my estimate is that we could need this as early as tomorrow morning /afternoon. Pilots will be calibrated to meet the 25% flowing tubing pressure rule. Thanks for the timely response. Gary Gary Targac NSK Prod Engr & Optimization Supv ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7411 Kuparuk Pager: 907.659.7000; #226 CPAI Internal Mail: NSK -47 �.1 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@a alaska.govl Sent: Monday, January 10, 2011 4:38 PM To: NSK Prod Engr & Optimization Supv Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James 6 (DOA); Roby, David S (DOA) Subject: RE: Request for Approval Gary, I acknowledge your request. Do you have any best estimate of when this could be needed? Will there be any modification of the pilot settings on the "new producers "? Sundries will not be necessary. Having to ability to test is appropriate for allocation purposes. I have copied this to my colleagues so they may make necessary assessments. I do not have the authority for this approval, but based on responses to others, the AOGCC will work with you to make the appropriate decisions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [ mailto _n2046 ©conocophillips.com] Sent: Monday, January 10, 2011 4:29 PM To: Maunder, Thomas E (DOA) Cc: NSK Prod Engr Specialist; CPF2 Prod Engrs; CPF3 Prod Engrs; NSK Fieldwide Operations Supt; CPF1 &2 Ops Supt; CPF3 Ops & DOT Pipelines Supt; Bradley, Stephen D 1/27/2011 • • Page 3 of 3 Subject: Request for Approval Importance: High Tom, GKA is requesting AOGCC approval to initiate WAG injector flowbacks at Kuparuk if needed to maintain an adequate fuel gas for our turbo - machinery due to the current TAPS proration. Doing so should help ensure that we maintain life support and safety systems at each facility. At this time, it is unclear if this will become necessary as the repair status at Pump Station #1 is still evolving. As part of our planning contingency, GKA is currently configuring the 5 WAG injectors (listed below) for flowback to production via adjacent shut -in producers. The duration of the flowbacks would be directly tied to the length of the TAPS proration. This will be accomplished by hard -line connections between the Gas Injector to an adjacent shut -in producer via tree cap connections. Each well will be equipped with functional SVS which will be capable to shut -in the gas production in the event of a failure and we are in the process of completing a PHA for each of these installations. All injectors will have well testing capabilities for allocation purposes. ilowback Adjacent Estimated Prod ;as Injector PTD# SI Producer PTD# (Mscfd) aP -420 201 -182 2P -422A 202 -067 4,500 a;P -447 203 -154 2P -448A 202 -005 2,000 3U-03 185 -006 2U -02 185 -005 3,500 �5 -09 202 -205 3S -08C 207 -163 7,500 35-26 201 -040 3S -24A 204 -061 6,500 24,000 I know if AOGCC approves of this plan in th e event we have to implement it during let me k o if the O p 9 non -office PP p hours. Regards, Gary Gary Targac NSK Prod Engr & Optimization Supv ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7411 Kuparuk Pager: 907.659.7000; #226 CPAI Internal Mail: NSK -47 1/27/2011 2P -420 2P -447 3S -09 2P -420 2P -447 3S -09 PROD MTR- MTR- MTR- PROD MTR- MTR- MTR- PROD MTR- MTR- MTR - DATE -TIME HRS 2P- 420 -OIL 2P- 420 -H2O 2P- 420 - FORM_GAS HRS 2P -447 -OIL 2P- 447 -H20 2P- 447 - FORM_GAS HRS 3S -09 -OIL 3S- 09 -H2O 3S- 09- PROD_GAS BBLS BBLS MSCF BBLS BBLS MSCF BBLS BBLS MSCF 01/09/11 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 01/10/11 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 01/11/11 0.6 0.7 100.1 74.7 11.3 900.3 0.0 5975.3 10.8 2.3 0.0 865.9 01/12/11 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 8.9 1.7 0.0 866.4 01/13/11 6.9 8.1 1250.6 1056.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 01/14/11 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Totals 7.5 8.8 1350.7 1131.3 11.3 900.3 0.0 5975.3 19.7 3.9 0.0 1732.3 • • � Page 1 of 2 Maunder, Thomas E (DOA) From: Roby, David S (DOA) DO Sent: Monday, January 10, 2011 5:21 PM To: Maunder, Thomas E (DOA) Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Request for Approval All, Seems like a reasonable plan to me. There shouldn't be any impacts to ultimate recovery as the volumes of gas that would be removed from these injectors should be negligible in the grand scheme of things, assuming the proration does not go on indefinitely. On a side note. Should we require, or at least strongly encourage, all operators to develop contingency plans that we can pre- approve to handle situations like this in the future so that they and us don't have to jump through a bunch of hoops to try to get something approved in a very short period of time? Dave Roby / (907)793 -1232 om: Maunder, Thomas E (DOA) Se : Monday, January 10, 2011 4:38 PM � �� To: N Prod Engr & Optimization Supv Cc: Foers Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, Day S (DOA) Subject: RE. zequest for Approval Gary, I acknowledge your req. -st. Do you have any best estimate of when this coul• •e needed? Will there be any modifica of the pilot settings on the "new producers "? • Sundries will not be necessar Having to ability to test is appropriate for . ocation purposes. I have copied this to my colleagu so they may make necessary ass- : ments. I do not have the authority for this a. 'royal, but based on response o others, the AOGCC will work with you to make the appropriate decisions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [mail ..n2s = . @conocophillips.com] Sent: Monday, January 10, 2011 4:29 PM To: Maunder, Thomas E (DOA) Cc: NSK Prod Engr Specialist; CPF2 Pro• ngrs; CPF3 Prod Engrs; SK Fieldwide Operations Supt; CPF1&2 Ops Supt; CPF3 Ops & DOT Pipelines Su• , Bradley, Stephen D Subject: Request for Approval Importance: High Tom, GKA is requesting AP CC approval to initiate WAG injector flowbacks at Kuparuk if n: --ded to maintain an adequate fuel ga •r our turbo - machinery due to the current TAPS proration. Doing so s •uld help ensure that we maintain lif- upport and safety systems at each facility. At this ti • -, it is unclear if this will become necessary as the repair status at Pump Station #1 is stil -volving. As part o •ur planning contingency, GKA is currently configuring the 5 WAG injectors (listed below) for fill back to pros ction via adjacent shut -in producers. The duration of the flowbacks would be directly tied to the lens of the 1/11/2011 • • Page 1 of 3 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, January 11, 2011 9:59 AM To: 'NSK Prod Engr & Optimization Supv' Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); NSK Prod Engr Specialist; Colombie, Jody J (DOA) Subject: RE: Request for Approval Gary, et al, I have spoken with Commissioner Foerster and she has given her approval to proceed with the planned flowback of the listed wells as described. Volumes should be tracked /recorded as planned. At this time it is not necessary to submit Form 10 -403 for the wells. Form 10 -404 will likely need to be submitted for each well following the conclusion of this extraordinary situation. Gas disposition will also need to be reported. I will place a copy of this message in the well files. Please keep us advised of the situation. Call or message with any questions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [mailto:n2046 @conocophillips.com] Sent: Monday, January 10, 2011 4:44 PM To: Maunder, Thomas E (DOA) Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA); NSK Prod Engr Specialist Subject: RE: Request for Approval Tom, my estimate is that we could need this as early as tomorrow morning /afternoon. Pilots will be calibrated to meet the 25% flowing tubing pressure rule. Thanks for the timely response. Gary Gary Targac NSK Prod Engr & Optimization Supv ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7411 Kuparuk Pager: 907.659.7000; #226 CPAI Internal Mail: NSK -47 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Monday, January 10, 2011 4:38 PM To: NSK Prod Engr & Optimization Supv Cc: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S (DOA) Subject: RE: Request for Approval 1/11/2011 • • Page 2 of 3 Gary, I acknowledge your request. Do you have any best estimate of when this could be needed? Will there be any modification of the pilot settings on the "new producers "? Sundries will not be necessary. Having to ability to test is appropriate for allocation purposes. I have copied this to my colleagues so they may make necessary assessments. I do not have the authority for this approval, but based on responses to others, the AOGCC will work with you to make the appropriate decisions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [ mailto :n2046 @conocophillips.com] Sent: Monday, January 10, 2011 4:29 PM To: Maunder, Thomas E (DOA) Cc: NSK Prod Engr Specialist; CPF2 Prod Engrs; CPF3 Prod Engrs; NSK Fieldwide Operations Supt; CPF1 &2 Ops Supt; CPF3 Ops & DOT Pipelines Supt; Bradley, Stephen D Subject: Request for Approval Importance: High Tom, GKA is requesting AOGCC approval to initiate WAG injector flowbacks at Kuparuk if needed to maintain an adequate fuel gas for our turbo - machinery due to the current TAPS proration. Doing so should help ensure that we maintain life support and safety systems at each facility. At this time, it is unclear if this will become necessary as the repair status at Pump Station #1 is still evolving. As part of our planning contingency, GKA is currently configuring the 5 WAG injectors (listed below) for flowback to production via adjacent shut -in producers. The duration of the flowbacks would be directly tied to the length of the TAPS proration. This will be accomplished by hard -line connections between the Gas Injector to an adjacent shut -in producer via tree cap connections. Each well will be equipped with functional SVS which will be capable to shut -in the gas production in the event of a failure and we are in the process of completing a PHA for each of these installations. All injectors will have well testing capabilities for allocation purposes. ilowback Adjacent Estimated Prod ;as Injector PTD# SI Producer PTD# (Mscfd) P -420 201 -182 2P -422A 202 -067 4,500 c ,;P -447 203 -154 2P -448A 202 -005 2,000 a;U -03 185 -006 2U -02 185 -005 3,500 --tit. 31S -09 202 -205 3S -08C 207 -163 7,500 3S -26 201 -040 3S -24A 204 -061 6,500 24,000 Please let me know if the AOGCC approves of this plan in the event we have to implement it during non -office hours. Regards, Gary Gary Targac NSK Prod Engr & Optimization Supv ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7411 Kuparuk Pager: 907.659.7000; #226 CPAI Internal Mail: NSK -47 1/11/2011 MEMORANDUM TO: Jim Regg ~~~` c1~ j I ~i ~ P.I. Supervisor ~ l FROM: Bob Noble Petroleum Inspector • State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, August 10, 2010 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 35-09 KUPARUK RIV UNIT 3S-09 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv Comm Well Name: KUPARUK RIV UNIT 35-09 API Well Number: 50-103-20432-00-00 Inspector Name: Bob Noble Insp Num: mitRCN100809150640 permit Number: 202-20s-0 Inspection Date: 8/7/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min.. 30 Min. 45 Min. 60 Min. Well 3S-09 ~ Type Inj. ; ~ ` TVD ~ sss9 Ip 2so Iaao ~ Ipso Ipso ~ ~ P.T.D 2ozzoso TypeTest SPT Test psi Igao OA 30 30 30 30 InterVal4YRTST p~ P ' Tubing 3025 302s 302s 3025 Notes: ~, ~ ~,~ ~ -~es~- / ~Psr ,- ~~ .. _. Tuesday, August 10, 2010 Page 1 of 1 \J • Ms. M. J. Loveland Well Integrity Project Supervisor ConocoPhillips Alaska, Inc, ~-~ ~ ' ~Y~b ~~ ~~(I~'; ~ , ~ Q 1 P.O. Box 100360 Anchorage, AK 99510-0360 RE: Cancellation of Administrative Approval 2B.028 KRU 35-09 (PTD 2022050) Kuparuk River Oil Pool Dear Ms. Loveland: Pursuant to ConocoPhillips Alaska, Inc. (CPAI)'s request dated May 3, 2010 the Alaska Oil and Gas Conservation Commission (AOGCC) hereby cancels Administrative Approval AIO 2B.028, which allows continued water injection in Kuparuk River Unit (KRU) well 35-09. This well exhibited a shallow surface casing leak to atmosphere and CPAI did not at the time propose repairing the well to eliminate the problem. The Commission determined that water injection could safely continue in the well, but subject to a number of restrictive conditions set out in the administrative approval. CPAI has since performed a welded repair to 35-09. An MITOA was successfully conducted following repair. Consequently, Administrative Approval AIO 2B.028 no longer applies to operation of this well. Instead, injection into KRU 35-09 will be governed by provision of the underlying AIO No. 2B. DONE at Anchorage, Alaska and dated May 14, 2010. Daniel T. Seamount, Jr. Commissioner, Chair Cathy . Foerster Commissioner AIO 2B.028 cancel • • May 14, 2010 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 3, 2010 Commissioner Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 • :aim ~ r'- ~ ~ ~ ~, Y~421 Subject: 35-09 (PTD 202-205) Request for Cancellation of Administrative Approval 2B.028 Dear Commissioner Seamount: ConocoPhillips Alaska requests the cancellation of Administrative Approva12B.028. The approval, originally issued April 9th 2008, was for continued water injection with communication from the surface casing to the atmosphere via a shallow surface casing leak. The surface casing was repaired by seal welding the connections on the surface casing pup joint on April 9th 2009. Following the repair the well passed an MITOA to 1800 psi and a 10-404 Sundry was filed. Please call Perry Klein or myself at 659-7043 if you have any questions. ~,, Sincerely, ,~ MJ oveland ConocoPhillips Well Integrity Project Supervisor Cc~naeoPh~llips aaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 17, 2010 Mr. Dan Seamount Alaska Oil & Gas Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Dan Seamount: ~u ~ ~n ~~ 5-f ~,:~ ~ ~~ v ~~A ~`~ fiFR2~2010 Dons. Oommissio~ anch~ragp c~ ,~~ ao~~ o ~- 3 Enclosed please fmd a spreadsheet with a list of wells from the Kuparuk field (KRin. Each of these wells was found to have a void in the conductor. These voids were filled with cement if needed and corrosion inhibitor, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10-404, Report of Sundry Operations. The cement was pumped January 16, March 21, 2010. The corrosion inhibitor/sealant was pumped Apri115, 16 and 17, 2010. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call Perry Klein or MJ Loveland at 907-659-7043, if you have any questions. Projects Supervisor I~ ConocoPhillips Alaska Inc. Surtace Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Kuparuk Field 4/17/2010 26. 2E_ 2G_ 2H_ 2K_ 2M_ 2V_ 2W_ 2X_ 2Z tli 3S P0~'c Well Name API # PTD # Initial top o cement Vol. of cement um ed Final top of cement Cement top-off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft al 28-05 50029210670000 1840040 24" n/a 24" n/a 4.2 4/16/2010 2B-08 50029210790000 1840260 21" 3.30 7" 1/16/2010 2.5 4/16/2010 2B-16 50029211460000 1841140 92" 0.65 3/21/2010 2.5 4/16/2010 2E-10 50029212460000 184,2300 SF n/a n/a Na 5.9 4/16/2010 2E-17 50029224190000 1931740 8'9" 1.50 19" 1/16/2010 3.4 4/16/2010 2G-13 50029211600000 1841290 SF Na 22" n/a 3.4 4/16/2010 2H-07 50103200450000 1851700 SF n/a 17" Na 2.1 4/15/2010 2H-09 50103200500000 1852590 SF Na 17" Na 2.5 4/15/2010 2H-15 50103200340000 1840860 SF n/a 17" Na 2.5 4/15/2010 2H-16 50103200350000 1840870 SF n/a 17" Na 2.5 4/15/2010 2K-19 50103201180000 1891090 53" 0.50 9" 1/16/2010 2.1 4/15/2010 2M-07 50103201780000 1920800 SF n/a 17" Na 3.4 4/15/2010 2M-08 50103201840000 1921010 SF n/a 17" Na 2.1 4/15/2010 2M-20 50103201690000 1920480 SF n/a 17" Na 2.5 4/15/2010 2M-22 50103201700000 1920490 SF n/a 17" Na 2.5 4/15/2010 2M-28 50103201740000 1920700 SF Na 18" Na 2.1 4/15/2010 2V-o6 50029210540000 1831790 SF Na 19" Na 7.6 4/16/2010 2V-10 50029213100000 1850480 SF n/a 19" Na 2.5 4/16/2010 2V-16 50029212960000 1850330 SF n/a 21" Na 5.1 4/16/2010 2W-03 50029212740000 1850110 SF n/a 37" Na 4.2 4/16/2010 2X-11 50029211880000 1841640 SF Na 1T' Na 6 4/17/2010 2Z-11 50029213790000 1851380 SF n/a 19" Na 2.5 4/15/2010 2Z-12A 50029213800100 1951480 SF Na 19" n/a 2.5 4/15/2010 2Z-13A 50029213600100 2061700 SF n/a 22" n/a 4.25 4/15/2010 2Z-19 50029218820000 1881300 SF n/a 16" n/a 2.1 4/15/2010 3S-09 50103204320000 2022050 SF Na 45" Na 23 4/17/2010 • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 15, 2010 Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Dear Mr.Seamount: • Enclosed please find the 10-404 Report of Sundry Operations for ConocoPhillips Alaska, Inc. we113S-09 PTD 202-205 Sundry 310-043 surface casing repair. Please call Perry Klein or MJ Loveland at 659-7043 if you have any questions. ConocoPhillips Well Integrity Projects Supervisor . •, a Enclosures c 1 .y~ iy- ~,_ ~ ;"~, {,, '^~€ .. ©ConocoPhillips Alaska, Inc This photo is copyright by ConocoPhillips Alaska, Inc. and cannot be released or published without express written consent. c...i~ "j ~,.- '- "., .~. ,3"" _ ~r _ ,~, a R- '~ ; , ,. I ~f~ STATE OF ALASKA LASKA AND GAS CONSERVATION COMMISSI~ APR ~ `~ ORT OF SUNDRY WELL OPERATIONS 1. Operations Perform Flo p~ tYll air w ell SC patch t7 ~~7~66 dfl ~ Plug Perforations [ Stimulate G Other ~ Alte Pull Tubing ~ FZ'rforate New Pbol ~( Waiver ~ Time Extension (Mange Approved Program ~ Operat. Shutdow n ~ Perforate ~ Re-enter Suspended Well 2.Operator Name: 4. Current Well Status: Sri. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development ~ Exploratory [ 202-205 3. Address: Stratigraphic ~ ServiceLW~, ~. API Number: P. O. Box 100360, Anchora e, Alaska 99510 50-103-20432-00 7. Property Des'ig~iation: 8. Well Name and Number: ADL 380106 ALK 4623 ~ 3S-09 9. Field/Pool(s): Kuparuk River Field / Kuparuk Oil Pool 10. Present Well Condition Summary: Total Depth measured 9650 feet Plugs (measured) None true vertical 6020 feet Junk (measured) None Effective Depth measured 0 feet Packer (measured) 497, 8933 true vertical 0 feet (true verucal) 496, 5589 Casing Length Size MD ND Burst Collapse CONDUCTOR 108 16 108 108 0 0 SURFACE 3504 9.625 3504 2596 5750,~ __. 3090 PRODUCTION 9639 7 9639 6013 7240 5410 Seal welds at the bottom of starter head and the top and bottom of the 1st surface casing collar @ 36" Perforation depth: Measured depth: 9284-9352 True Vertical Depth: 5795-5836 Tubing (size, grade, MD, and TVD) 3.5, L-80, 8965 MD, 5608 TVD Packers & SSSV (type, MD, and TVD) NIP - CAMCO 'DS' LANDING NIPPLE WIT NO GO PROFILE @ 497 MD and 496 TVD PACKER -BAKER SAB-3 PACKER 8933 and 5589 TVD Nipple -Type Not Found (Manual Entry Required) @ 0 MD and 0 TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation NA NA NA NA NA Subsequent to operation NA NA NA NA NA 13. Attachments Well Class after proposed work: Copies of Logs and Surveys run Exploratory ~ Development ~j Service X .Well Status after work: Oil I' i Gas~"i WDSPL [~ Daily Report of Well Operations GSTOR r WAG r GASINJ ~ WINJ ~ SPLUG [j 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 310-043 contact Perry Klein/MJ Loveland Printed Name Perry Klein Title Well Integrity Project Supervisor Signature Phone: 659-7043 Date Submit Original Only Form 10-404 Revised~P96~"S APR 2 ~ 1~~~~ ~ Y~2~ l ~ `~ Y~~~~ • • ~~1~~~ 3S-09 APR 2 3 2010 DESCRIPTION OF WORK COMPLETED SUMMARY al ~ ~~ eons. ~ommssior Date Event Summary 03/31/10 04/03/10 04/09/10 04/12/10 04/13/10 Marked for two windows 18" X 24". Drilled 3/4" -pilot holes (8). Cut windows with sawzall and removed 15 gallons of sealant and filler. Cleaned surface casing for inspection. Tried to locate leak with nitrogen purge. Held 200 psi for 10 min with no leaks observed, increased to 400 psi for 10 min. Have displacement of oxygen between starter head and flutes. Increased purge to 600 psi, noticed more oxygen dispacement in flutes/starter head area. Checked using "snoop" no bubbles noted but did notice bubbles around first collar. Area of oxygen displacement in flutes and bubbles from collar are both on left hand side of well between 7 and 8 o'clock. Held 600 psi for 30 min with very little loss of pressure (20 psi). Bled OA to zero, took pictures of areas. Cut and removed landing ring/conductor, overall length is 42". Cleaned surface casing for inspection. Pressured up surface casing to 400 psi with nitrogen. Nitrogen leaking by @ threads of starter head and pup. Also saw bubbles on top of first collar but no nitrogen. Bled off nitrogen. T/I/O = 0/0/0. Seal weld starter head and collar. Welding was performed per M.E. specs. Allow welds to cool down over night and Kakivik will inspect in morning. T/I/O = SI/0/0. MIT-OA (passed) Post SC repair (Seal Weld ), T/I/0= SI/0/0. OA-FL NS. Pressured up OA with 1.5 bbl diesel, Re pressured OA several times prior to initiating test.T/I/0= SI/0/1800. 15 ~, min T/I/0= SI/0/1725. 30 min T/I/0= SI/0/1700. 45 min T/I/0= SI/0/1700. 60 min T/I/0= SI/0/1700. Bled OA, T/I/0= SI/0/260. Denso wrap is installed. Welded 45" of 16" X .375 wall conductor pipe. Initial T/I/O = SI/0/250. Placed gripstrut over cellar and demobe equipment. Ready to top-off conductor with cement and sealant. Final T/I/O = SI/0/250. l~( ~- ~ ,' ~,N U ~~ P # 4 ~. -~ ~, ~ ~ ~ ~ f ~;~ ~~~ ~~; ..~ Fig ~ >{ •I • • 4~ ~ , ~~; j ~~~~~~'0 ~ 0~ ~~0~0~~ ~a _a&~ ~.~;= ~. ~~ , d~.~w. Yom, ~'~ ~©ConocoPhillips Alaska:,.,lnc~~~ ~'~~~ ' ~~ ~..~4~: v- "his hoto is co r-i h t p pY 9 t bY. ~~ ~~ ~ ConocoPhillips Alaska,- Inc. ~ ~~~ .,,~;~ ~~ ~ ~ and cannot be released or ~ ~, ~,h ~~a~ published without express ° ~~ ~~__ ~w T~ written consent. ~~ ~~ ~ ~ ~ ~l" ~ , ~ , x ~. ~` ~~ , ;, ;. ~:. • Ms. MJ Loveland Wells Integrity Project Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510 Re: Kuparuk River Field, Kuparuk Oil Pool, 35-09 Sundry Number: 310-043 \J ~oa_aos Dear Ms. Loveland: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. Chair DATED this ~ day of February, 2010. Encl. • ConocoPhillips P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 11, 2010 Commissioner Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Seamount: • Enclosed please find the 10-403 Application for Sundry Approval for ConocoPhillips Alaska, Inc. we113S-09 PTD 202-205 for surface casing repair. Please call Perry Klein or myself at 659-7043 if you have any questions. ConocoPhillips Well Integrity Projects Supervisor Enclosures ' STATE OF ALASIG4 ~' ~~ ~ to ~~~~' " ED ALAS~IL AND GAS CONSERVATION COMMIS ~~~•1° FEg 1 6 2010 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon r Plug for Redrill r Pf,rforate New Fool r Repair w ell ~ , Change A~~q~gram r ~ "~~° ~' Suspend (- Plug Perforations r Ft:rforate r Full Tubing [' lyc~~te nsion Tim e Operational Shutdow n r Re-enter Susp. Well r Stimulate r Alter casing Other: SC patch '1r 2. Operator Name: 4. Curcent Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Devebpment r Exploratory ~ 202-205 3. Address: Stratgraphic r" Service r 6. API Number: P. O. Box 100360, Anchora e, Alaska 99510 50-103-20432-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name and Number: where ownership or landownership changes: Spacing Exception Required? Yes r No ~ 3S-09 ' 9. Property Designation: 10. Field/Pool(s): ADL 380106 ALK 4623 Kuparuk River Field / Kuparuk Oil Pool ' 11. PRESENT WELL CONDITION SUMMARY Total depth MD (ft): Total Depth TVD (tt): Effective Depth MD (ff): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9650 6020 Casing length Size MD TVD Burst Collapse CONDUCTOR 108 16 108' 108' SURFACE 3504 9.625 3504' 2596' 5750 3090 PRODUCTION 9639 7 9639' 6013' 7240 5410 Perforation Depth MD (tt): 9284-9352 Perforation Depth TVD (tt): 5795-5836 Tubing Size: 3.5 Tubing Grade: L-80 Tubing MD (tt): 8965 Packers and SSSV Type: Packers and SSSV MD (tt) and TVD (ft) PACKER -BAKER SAB-3 PACKER NIP - CAMCO'DS' LANDING NIPPLE WITH NO GO PROFILE 8933 TVD= 5589 497 TVD= 496 12. Attachments: Description Summary of Proposal ~ 13. Well Class after proposed work: Detailed Operations Program ~ BOP Sketch r Exploratory r Development r Service ~ • 14. Estimated Date for Commencing Operations: 15. Well Status after proposed work: 3/1/2010 Oil r Gas r WDSPL r Plugged r 16. Verbal Approval: Date: WINJ r GINJ r WAG ~ Abandoned ~ Commission Representative: GSTOR r SPLUG r 17. I hereby certify that the foregoing is true and come to the best of knowledge. Contact: Perry Klein/MJ Loveland Printed Name /~ .~ L ~ tJ t. ~Cc /! L>' Title: Well Integrity Project Supervisor Signature Phone: 659-7043 Date O~ / C mmi 1 Sundry Number: Conditions of approval: Notify Commission so that a representative may witness ~~~ •- )~ Plug Integrity r BOP Test r Mechanica~l/ IntegrityTest r Location Clearance r ~vt ri~-c .~. p ~t-v~a oE' a c.t.~ •-,.e..~'~' ° `` !t !~~ c /'e~ "'c.'r Other: I _ U /Uvf.'-~y 1h5~ot~r as ~~4rin~.(1. Subsequent Form Required: /\ j ~l ~ 9~ COMMISSIONER APPROVED BY THE COMMISSION Z'~~ ~a Date: ~~! ~/ ~~ Submit in Duplica~ ~6/~ , s ~. /(~.~ C_~ ConocoPhillips Alaska, Inc. Kuparuk We113S-09 (PTD 202-205) SUNDRY NOTICE 10-403 APPROVAL REQUEST 02/11/10 This application for Sundry approval for Kuparuk well 35-09 is for the repair of a surface casing leak. The well is a WAG injector and was drilled and completed in 2002. On December 4, 2007, a surface casing leak was confirmed and reported to the AOGCC. Diagnostics confirmed a leak in the surface casing at a shallow, but unknown depth. With approval, repair of the surface casing will require the following general steps: 1. Shut-in and secure well. Set positive pressure plug and fluid pack the IA as needed to remove all gas. Freeze protect the T and IA. Perform mechanical integrity test and draw down test on tubing plug to verify barrier. 2. Excavate wellhead location if required. 3. Install nitrogen purge equipment. 4. Cut away the conductor casing and remove cement around surface casing leak for inspection. 5. Notify AOGCC Field Inspector of repair operation so they may witness the damage. 6. Repair damaged surface casing integrity. Repair options include sleeve patch, seal weld, lap patch, deposition weld and will be determined after inspection of the casing damage. 7. QA/QC the repair welds and MIT-OA to verify integrity 8. Install anti-corrosion coating on exposed surface casing. 9. Patch the conductor and top off the conductor void with cement and corrosion inhibiting sealant. 10. Backfill gravel around the wellhead. 11. Remove plugs and return the well to production. 12. Submit 10-404 report of repair operations to AOGCC. • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Thursday, December 03, 2009 Jim Regg P.I. Supervisor ~~ ` 12' 3l Ug SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 3S-09 FROM: Boll NOble KUPARUK RIV UNIT 35-09 Petroleum Inspector Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv ~~ Comm Well Name: KUPARUK RIV UNIT 35-09 API Well Number: 50-103-20432-00-00 Inspector Name: Bob Noble Insp Num: mitRCN091202082338 Permit Number: 202-205-0 Inspection Date: 11/29/2009 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. -T 35-09 I YP ~. '' W ~TVD 5589 I IA ~ 570 , 2990 -- 2930 ~ -- 2930 -- ~ zozzoso ~Yp srT~Test psi ~ z99o ~ pA ~ 0 P.T1D T eTest ----- _-~_---1- ~-- 1 - ~ ---~-- 0 --- 0 0 ~ Interval REQvAIt / P/F P ~ Tubing ~ I77s _ ~ ~77s ~ ~77s I77s _ Notes: ASP 'N1 r v~ . Te ~u j~ -~ ,-~ ~ 5 ~ ~~ ~~ Z- ~,L ~ J ~. ~. ~~ Thursday, December 03; 2009 Page 1 of 1 • ~ R`~a STATE OF ALASKA ~~ ~ ~ ~~~~ ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIOIs~~ ~"! ~` ~~ ~~~~~ ~Ir~mAss~~~a 1. Operations Performed: Abandon ^ Repair Well ^ Plug Perforations ^ Stimulate ^ Other ~ remedial cement Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extension ^ Change Approved Program ^ Operat. Shutdown^ Perforate ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number: ConocoPhilllps Alaska, InC. Development ^ Exploratory ^ 202-205 / ' 3. Address: Stratigraphic ^ Service Q ~ 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20432-00 7. KB Elevation (ft): 9. Well Name and Number: RKB 57' 3S-09 ` 8. Property Designation: 10. Field/Pool(s): ADL 380106 ALK 4623 Kuparuk River Field /Kuparuk Oil Pool 11. Present Well Condition Summary: Total Depth measured 9650' feet true vertical 6020' feet Plugs (measured) Effective Depth measured feet Junk (measured) true vertical feet Casing Length Size MD TVD Burst Collapse Structural CONDUCTOR 108' 16" 108' 108' SURFACE 3447' 9-5/8" 3504' 2596' 5750 psi 3090 pSi PRODUCTION 9582' 7" 9639' 6013' 7240 psi 5410 psi Perforation depth: Measured depth: 9284-9302, 9302-9332, 9332-9352 da~a~ ~~ a nfl t~ true vertical depth: 5795-5806, 5806-5824, 5824-5836 `v~~~ ~i~K ~° ~' 2u~1~ Tubing (size, grade, and measured depth) 3-1/2" , L-80, 8965' MD. Packers &SSSV (type & measured depth) Baker SAB-3 packer Packer=8933 SSSV= Camco DS landing nipple SSSV= 49T -°--- - 12. Stimulation or cement squeeze summary: NA Intervals treated (measured) Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casin Pressure Tubin Pressure Prior to well operation NA Subsequent to operation NA 14. Attachments 15. Well Class after proposed work: Copies of Logs and Surveys run _ Exploratory ^ Development ^ Service^ ' Daily Report of Well Operations _X 16. Well Status after proposed work: Oil^ Gas^ WAG^~ GINJ^ WINJ ^ WDSPL^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 307-376 Contact Perry Klein/MJ Lov land Printed Name MJ Lov land Title Well Integrity Supervisor Signature Phone 659-7043 i, ~ Date J L ( ~ Q U ~i~ ~j. .~ Z ~Z7 • v~$ ~~$. . _ ~± ~~- f t. ~` •~ °t ~~~~ /".' ~(~ Submit 'ginal my Form 10-404 Revised 04/2004 ,- z,~~ i • 3S-09 DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 2/4/2008 iPUMPED OA SHOE. PLACED 42 BBLS 15.8 PPG EXPANSIVE CLASS G IN 7" X 9 5/8" (ANNULUS. 2/11/2008 MITOA -Failed, suspect failure is due to SC leak near surface. Summary Pumped 1000' OA shoe, will continue with SC leak diagnostics and subsequent 10-403 for additional repairs • • ~. ~. ~ ~ ~. l ~ ~ SARAH PAL/N, GOVERNOR ~5~ OI~ .cu~L ~ 333 W. 7th AVENUE, SUITE 100 COI~T5ER'QATIOI~IT COi1II-IISSIOIIT ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 Martin Walters FAx (so7) 27s-7642 Problem Well Supervisor Conoco Phillips Alaska, Inc PO Box 100360 Anchorage, AK 99510 ~~~r~~~ ~~.c ~ ~. 2oa~ Re: Kuparuk River Field, Kuparuk River Oil Pool, 35-09 Sundry Number: 307-376 Dear Mr. Walters: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission shown, a person affected by it may file with the Commissionf an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DATED this ,day of December, 2007 Encl. ~U~- ~~~~ Sincerely, ~ ~~ ~~e~ ~ 1~1~~~ ~ ~a i~ S11ATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ~:w~ SEC 1 '7 2~1~7 APPLICATION FOR SUNDRY APPROVAL~~~~~ ~;f ~ ~~~ ~"~r~. ~~~~,~~~~,~~, 20 AAC 25.280 ~E?t;l;~r~,-:,43 _ 1. Type of Request: Abandon ^ Suspend ^ Operational Shutdown ^ Perforate ^ Waiver ^ Other /^ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Remedial cmt Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development ^ Exploratory ^ 202-205 - 3. Address: Stratigraphic ^ Service ^ 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20432-00 '" 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name and Number: where ownership or landownership changes: Spacing Exception Required? YeS ^ NO^ 3S-09 r 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL 380106 ALK 4623 RKB 57' Kuparuk River Field / Kuparuk Oil Pool - 12. PRESENT WELL CONDITI ON SUMMARY Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9650' ~ 6020' ° Casing Length Size MD ND Burst Collapse CONDUCTOR 108' 16" 108' 108' SURFACE 3447' 9-5/8" 3504' 2596' 5750 Si 3090 Si PRODUCTION 9582' 7" 9639' 6013' 7240 psi 5410 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9284-9302, 9302-9332, 9332-9352 5795-5806, 5806-5824, 5824-5836 3-1 /2" ~-80 8965' Packers and SSSV Type: Packers and SSSV MD (ft) Baker SAB-3 packer Packer=8933' SSSV= Camco DS landing nipple SSSV= 497' 13. Attachments: Description Summary of Proposal ~ 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^ Service 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: 12/12/07 Oil ^ Gas ^ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG Q GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Brent Rogers/Martin Walters Printed Name Martin Walters , Title: Problem Well Supervisor Signature ~ Phone: 659-7224 Date: 12/05/07 Commission Use Onl Sundry Number: Conditions of approval: Notify Commission so that a representative may witness ~ ~ '~ Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: .; ~~ ~.,.1?EC 2 ~ 2D07 Subsequent Form Required: ~('~ APPROVED BY / / Approved by: M TONER THE COMMISSION i Date: i Form 10-403 Revised 06/2006 ~ ~' ~' ~ ~"~ L 1 ~„ /g,/r Submit jrf Duplicate /'s'ue Y / (~/ .~' 1> l Z ~ / $, 07 • • ConocoPhillips Alaska, Inc. Kuparuk We113S-09 (PTD 2022050) SUNDRY NOTICE 10-403 REQUEST 12/05!07 The purpose of this Sundry Notice is to notify the AOGCC of ConocoPhillips Alaska, Inc., intent to pump a cement shoe in the surface casing of Kuparuk wag injection we113S-09. A surface casing cement shoe was not pumped at the time of original completion in 2002. 35-09 has been shut-in since a suspected surface casing leak was reported. The cement shoe is required in order to pressure test the surface casing to verify integrity of the surface casing after a report of a suspected surface casing leak and the initial diagnostics were unable to locate a leak and confirm the report. The well's primary barrier is the 3.5" tubing. The well's secondary barrier is the 7" production casing and packer. If the cement shoe remediation is successful (resulting in a passing MIT-OA), there will be confirmation of the integrity of the surface casing. If the cement shoe remediation is unsuccessful (resulting in a failing MIT-OA), further diagnostics will be undertaken to identify the location and severity of the leak. Pending results, an administrative relief request may be submitted for approval to return the well to water only injection. With approval, the OA cement shoe will require the following general steps: 1. Bleed IA to < 1.00 psi. 2. Pump 42 bbls of cement into the OA. 3. Displace cement with 71 bbls of water and diesel freeze protection for a calculated cement top at 2504' MD. 4. Wait 48 hrs on cement 5. MITOA to 1800 psi. 6. Submit 10-404 to AOGCC. NSK Problem Well Supervisor 12{12/2007 ~ • ConocoPhillips Alaska, Inc. KRU 3S-09 - 3S-09 l TS 53 d 9284 API: 501032043200 Well T e: INJ An e : TUBING (oB9s5 SSSV T e: Ni le Ori Com letion: 12/17/2002 An le TD: 51 de 9650 , oD:3.5o0, Annular Fluid: Last W/O: Rev Reason: TAG FILL ID:2.992) Reference L : 24.13' RKB Ref Lo Date: Last U date: 5/27/2005 Last Ta : 9434 TD: 9650 ftKB SURFACE Last Ta Date: 5/21/2005 Max Hole An le: 59 de 4380 (o35oa, Casln Strin -ALL STRINGS oD:s.sz5, w1 aa oo Descri lion Size To Bottom TVD Wt Grade Thread : . ) CONDUCTOR 16.000 0 108 108 62.50 H~0 WELD SURFACE 9.625 0 3504 2596 40.00 L-80 BTC PRODUCTION 7.000 0 9639 6013 26.00 L-80 BTCM Tubin Strin -TUBING Size To Bottom TVD Wt Grade Thread 3.500 0 8965 5608 9.30 L-80 EUE8RD Perforations Summa RODUCTION Interval TVD Zone Status Ft SPF Date T e Comment (o-ss39, oD:7.oo0, 9284 - 9302 5795 - 5806 C-4 18 6 12/25/2002 IPERF 2506 PJ Chrgs, 60 deg hase w1:2s.oo> 9302 - 9332 5806 - 5824 C-4 30 6 12/24/2002 IPERF 2506 PJ Chrgs, 60 deg hase 9332 - 9352 5824 - 5836 C-4 20 6 12/25/2002 IPERF 2506 PJ Chrgs, 60 deg hase Gas Lift MandrelsNalves St MD TVD Man Mfr Man Type V Mfr V Type V OD Latch Port TRO Date Run Vlv Cmnt_ NIP 1 8832 5532 CAMCO MMG DMY 1.5 RK 0.000 0 12/21!2002 (ea7B~a7s, Other lu s e ui .etc. -JEWELRY OD:4.520) De th TVD T e Descri lion ID 24 24 HANGER FMC 3.5" GEN 5 TBG HANGER w/3.5" TBG PUP ON BTM 2.993 497 496 NIP CAMCO'DS' LANDING NIPPLE WITH NO GO PROFILE 2.875 8878 5558 NIP CAMCO 'DS' LANDING NIPPLE W/NO GO PROFILE 2.812 8919 5581 PBR BAKER PBR 800 2.980 PBR 8932 5589 Anchor Ni le BAKER KBH-22 ANCHOR TUBING SEAL 2.993 (asls$9zo, 8933 5590 PACKER BAKER SAB-3 PACKER 3.250 OD:5.870) 8937 5592 EXTENSION BAKER MILLOUT EXTENSION 3.720 8957 5603 NIP CAMCO'D' NIPPLE W/NO GO PROFILE 2.750 Anchor _ - 8964 5607 WLEG BAKER PUMP OUT SUB -sheared 12/22/2002 2.990 Nipple (a9328933 8965 5608 TTL 2992 , oD:a.7ao> General Notes Date Note PACKER (ea33Ba37, 12/18/200 Tree: FMC /GEN 5 / 5M 5" EUE 8rd Thread 75" ACME w/3 Tree Ca Connection: T 5 OD:5.950) NIP (8957$958, OD:4.540) WLEG (8964$965, OD:4.510) TTL (89658966, OD:3.500) Perf (9284-9302 ) Perf (9302-9332) . . 35-09 (PTD 2022050) suspect S~k • Page 1 of 1 Regg, James B (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com) Sent: Tuesday, December 04, 2007 1:52 PM ~ ~,~~~.-~,~~ ~ To: Maunder, Thomas E (DOA); Regg, James B (DOA) ~,C'~~1 Cc: NSK Well Integrity Proj; NSK Problem Well Supv; CPF3 Prod Engrs; Targac, Gary; CPF3 DS Lead Techs; Cawvey, Von Subject: 3S-09 (PTD 2022050) suspect SC leak Attachments: 3S-09 schematic.pdf; 3S-09 90 day TIO plot.jpg Tom & Jim, Kuparuk injector 3S-09 (PTD 2022050) was reported on 12/01/07 as having a suspected surface casing leak. Immediate action taken was to shut the well in and bleed the OA down as low as possible with the open OA shoe which was 20 psi. The TIO at the time of the report was 2900/1375!490. Initial diagnostics have been unable to confirm a surface casing leak. Diesel was pumped down the OA in an attempt to find the suspected leak. When the pumping first started a small amount of fluid pooled up in the conductor (less than a cup), however an injection rate of 1.5 BPM @ 1300 psi with a total of 6.8 barrels pumped and no more fluid to surface up the conductor than the initial amount. Following the injection test, Nitrogen was purged down the OA with no more fluid or nitrogen to surface up the conductor. Following the purge the OA FL was found at 30 feet. It is ConocoPhiilips intent to submit a 10-403 Sundry application for a OA cement shoe in order to continue with diagnostics. With the open OA shoe there has been no confirmation as to whether there is a small surface casing leak or the report of the suspected leak is due to swamp gas coming up through the cement in the conductor. Attached is a schematic and 90 day TIO plot. «3S-09 schematic.pdf» «3S-09 90 day TIO plot.jpg» Please let me know if you have any questions. Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7224 Cell Phone (907) 943-1999 Pager (907} 659-7000 pgr. 909 ~~"wi~~ ~1 ~ ~ ~ ~~~~ /~ /, 12/17/2007 • • r'~, ~~ f~~ Conac~f~fa"sflips Afasfca, fnc. KRU 3S-09 3S-09 TuBwG ~ API: 501032043200 Well T e: INJ An le TS: 53 de 9284 (oass5, ~ ~= i' ~i SSSV T e: Ni to Ori Com letion: 12/17/2002 An le TD: 51 de 9650 oD:3.5o0, ~'~ Annular Fluid: Last W/O: Rev Reason: TAG FILL iD:2.ssz) Reference Lo : 24.13' RKB Ref Lo Date: Last U date: 5/27/2005 Last Ta : 9434 TD: 9650 ftK8 SURFACE ~. Last Ta Date' . 5/21/2005 Max Hole Angle: 59 d ea Ca) 4 80 3 (os5o4, o _ ;~,. __ . _ Casin String -ALL STRINGS _ _ _ _ oss25, wt:ao oo) I ~ ~ Descri lion Size To Bottom TVD Wt Grade Thread . CONDUCTOR 16.000 0 108 108 62.50 H-40 WELD SURFACE 9.625 0 3504 2596 40.00 L-80 BTC PRODUCTION 7.000 0 96 39 6013 26.00 L-8n RTCM . _ _ Tuhin Strin -TUBING __ _ __ _ ~' Size To Bottom TVD Wt Grade Thread 3.500 0 8965 5608 9.30 L-80 EUE8RD ~. ~ ~ Perforations Summa RoDUCTION ---•z ,r- • - t Interval TVD Zone Status Ft SPF Date T e _ Comment (o-ss3s, ~ ` 9284 - 9302 5795 - 5806 C-4 18 6 12/25/2002 IPERF 2506 PJ Chrgs, 60 deg 00:7.000, wt 2s oo ~ ~ ' hase G : . ) 8302 - 9332 5806 - 5824 C-4 30 6 12/24/2002 IPERF 2506 PJ Chrgs, 60 deg ~ hase 9332 - 9352 5824 - 5836 C-4 20 6 12/25/2002 IPERF 2506 PJ Chrgs, 60 deg __ .phase - Gas Lift MandrelsNalves _ St MD TVD Man Man T e YP V Mfr V T e YP V OD Latch _ Port TRO Date Vlv Mfr Run Cmnt MP a~ - 1 8832 5532 CAMCO MMG DMY LS RK 0.000 0 12 /21/2002 (8a7a-8979, _ _ Other. lu s, a ui ., etc. -JEWELRY OD:4.520) De th TVD T e _ _ _ __ Descri lion ID ' ~' 24 24 HANGER FMC 3.5" GEN 5 TBG HANGER w/3.5" TBG PUP ON BTM 2.993 • 497 496 NIP CAMCO'DS' LANDING NIPPLE WITH NO GO PROFILE 2.875 - 8878 5558 NIP CAMCO 'DS' LANDING NIPPLE W/NO GO PROFILE 2.812 8919 5581 PBR BAKER PBR 80-40 2.980 8932 5589 Anchor BAKER KBH-22 ANCHOR TUBING SEAL 2.993 P6R Ni le - lasts-as2o, 8933 5590 PACKER BAKER SAB-3 PACKER 3.250 OD:5.870) 8937 5592 EXTENSION BAKER MILLOUT EXTENSION 3.720 8957 5603 NIP CAMCO'D' NIPPLE W/NO GO PROFILE 2.750 Anchor Ni l '- - = ' 8964 5607 WLEG BAKER PUMP OUT SUB -sheared 12/22/2002 2.990 pp e (8932933, - - 1 ' 8965 5608 TTL _ _ 2.992 OD:4.7ao) General Notes Date Note PACKER 12/18/200 Tree: FMC /GEN 5 / SM (8933.8937, OD:5 950) ~ Tree Ca Connection: To 5.75" ACME w/3.5" EUE 8rd Thread . ,l f NIP ~ , (8957958, OD:4.540) - M1E ~~ WLEG (8964965, OD:4.510) ' TTL (8965966, OD:3.500) Pert - (9284-9302) ~ ' ~ Perf ~ - ', (9302-9332) -f . ~ - Kam( 3 S ~ c~~ • MEMORANDUM . State of Alaska . Alaska Oil and Gas Conservation Commission TO: Jim Regg/~7 Ç;'0í 'bJ ~{) /()Ço P.I. Supervisor 17 c- (' { DATE: Wednesday, August 30, 2006 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 3S-09 KUPARUK RIV UNIT 3S-09 ~_~os ~OO' FROM: Jeff Jones Petroleum Inspector Sre: Inspector Reviewed By: P.I. Suprv ,--T8(¿- Comm NON-CONFIDENTIAL Well Name: KUPARUK RIV UNIT 3$-09 API Well Number 50-103-20432-00-00 Inspector Name: Jeff Jones Insp Num: mitlJ060829124726 Permit Number: 202-205-0 Inspection Date: 8/2212006 Rei Insp Num Packer Depth Pretest Initia I 15 Min. 30 Min. 45 Min. 60 Min. Well 38-09 Type Inj. w TVD 5590 IA 1125 1810 1800 1780 1780 P.T. 2022050 TypeTest SPT Test psi 1500 OA 590 630 630 630 630 Interval 4YRTST P/F P ~/ Tubing 2340 2350 2350 2350 2350 Notes 0.7 BBLS diesel pumped. I well house inspected; no exceptions noted. SCANNED SEP 0 3 2006 Wednesday, August 30, 2006 Page I of I . . WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 June 02, 2003 RE: MWD Formation Evaluation Logs 3S-09, AK-MYV-2219300 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Rob Kalish, Sperry-Sun Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518 3S-09: Digital Log Images: 50-103-20432-00 1 CD Rom SCANNED AUG 3 1 2005 -~ .j:t ¿)Od -80s- ILl I oCJ . Conoc:JPt,illips Alaska . P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 7, 2006 t1' ,,J- Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 ~ö~...~oS 3S- Dq Dear Mr. Maunder: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor by surface casing annulus. The voids that were greater than 6 feet were first filled with cement to a level of 2.5 feet. The remaining volume, 2.5 to 6 feet of annular void respectively was coated with a corrosion inhibiter, RG2401, then filled with a viscous hydrocarbon based sealant, RG casing filler, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10-404, Report of Sundry Operations. The cement top-fill operation was completed on November 18, 2003 and was previously reported to the Commission as follows. Schlumberger Well Services mixed 15.7 ppg Arctic set I in a blender tub. The cement was pumped into the conductor bottom and cemented up via a hose run to the existing top of cement. The corrosion inhibitor and sealant were pumped in a similar manner August 4 -5, 2006. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call Jerry Dethlefs or myself at 907-659-7043, if you have any questions. Sincerely, J ~:~ ConocoPhillips Well Integrity Supervisor Attachment ~ . . ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Kuparuk Field Au ust 7,2006 Well Name Initial top Vol. of cement Final top of Cement top PTD # of cement um ed cement off date ft bbls ft Corrosion inhibitor/ sealant date 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 . . "" MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _ Inserts\Microfilm _ Marker.doc rJ.t.i J~ .l~~ ~ DATA SUBMITTAL COMPLIANCE REPORT 1/6/2005 Permit to Drill 2022050 Well Name/No. KUPARUK RIV UNIT 3S-09 Operator CONOCOPHILLlPS ALASKA INC Sf; uJ. L¡ ~. M~:L. API No. 50-103-20432-00-00 MD 9650-'" TVD 6020 .... Completion Date 12/24/2002 / Completion Status 1-01L Current Status WAGIN -~ --~ ----. REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes ---- ---_._-~--~ DATA INFORMATION Types Electric or Other Logs Run: GR/Res Well Log Information: (data taken from Logs Portion of Master Well Data Maint) Log/ Electr Data Digital Dataset Type Med/Frmt Number Name ¿;zo . t:.r5-'----- Directional Survey Log Log Run Scale Media No 1 Interval OH 1 Start Stop CH Received Comments 0 9650 Open 1/3/2003 '" .~ Rpt Directional Survey 0 9650 Open 1/3/2003 JOg r;:~~=~:~~~= Blu 9150 9350 Case 1/10/2002 0-t:6g' ressure Blu 9150 9350 Case 1/10/2002 ~ ~meniEva¡uai¡on . 5 Col 8900 9410 Case 2/7/2003 v<óg (/See Notes 5 Blu 8680 9070 Case 2/7/2003 ¡t.Jewelry ~.. tU1ij;ciiorÍProfÎle' 5 Blu 8975 9390 Case 5/8/2003 la(~ £.A1'666 LIS Verification 51 9612 Open 4/17/2003 Rpt LIS Verification 51 9612 Open 4/17/2003 ..-tog ~jection Profile 5 Blu 8975 9400 Case 9/28/2003 Injection ProfilelWarmback .~ I Survey PSP FBS - CFS - ! \ Gradio/PresslT emp/GRlCC L I ~og /~;~diometer : .Blu 8975 9400 Case 9/28/2003 Injection ProfilelWarmback Survey - PSP FBS- CFS - ./ / Gradio/PresslT emp/GRlCC L ,Pg è,¡Pressure 5 Blu 8975 9400 Case 9/28/2003 Injection ProfilelWarmback Survey - PSP FBS- CFS - G radio/PresslT emp/G RlCC 0emperature L YLog 5 Blu 8975 9400 Case 9/28/2003 Injection ProfilelWarmback Survey-PSPFBS-CFS- G radio/PresslT em pIG RlCC L ._-~---~--- DATA SUBMITTAL COMPLIANCE.REPORT 1/6/2005 Permit to Drill 2022050 Well Name/No. KUPARUK RIV UNIT 3S-09 MD .9650 . a.e(/ --~- TVD 6020 Completion Date 12/24/2002 ~'sing collar locator Well Cores/Samples Information: Name Interval Start Stop ADDITIONAL INFORMATION Well Cored? Y /~ Chips Received? 'Y tN' Analysis Received? Comments: ~. Compliance Reviewed By: '~ Operat()rCONOCOPHILLlPS ALASKA INC Completion Status 1-01L ~.,/ Blu Sent Received Daily History Received? Formation Tops API No. 50-103-20432-00-00 Current Status WAGIN UIC Y 8975 9400 Case 9/28/2003 Injection ProfilelWarmback Survey - PSP FBS- CFS - Gradio/Press/T em pIG R/CC L Sample Set Number Comments ~N (])IN Date: .~ Ä'7 J~~~- "-"'". ') STATE OF ALASKA) . ~ ALASKA OIL AND GAS CONSERVATION COMMISSION ~Ó~- ~Ô S Mechanical Integrity Test I.. .\ i \2uq 1 \4' 0 't Email to:Tom_Maunder@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;andJim_Reg~@~~min.state.ak.us OPERATOR: ConocoPhillips Alaska Inc. FIELD 1 UNIT 1 PAD: . KRU 38-09 DATE: 07/11/04 OPERATOR REP: Brake I Rogers AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. Well 3S-09 Type Inj 8 T.V.D. 5590 Tubing 2150 2150 2150 2150 Interval 0 P.TD.2022050 Type Test P Test psi 1500 Casing 450 3000 3000 3000 P/F P Notes: Diagnostic OA: 250 I 400 I 400 I 400 Well Type Inj T.V.D. Tubing Interval P.T.D. Type Test Test psi 1500 Casing P/F Notes: Well Type Inj TV.D. Tubing Interval P.TD. Type Test Test psi 1500 Casing P/F Notes: Well Type Inj TV.D. Tubing Interval P.T.D. Type Test Test psi 1500 Casing P/F Notes: Well Type Inj T.V.D. Tubing Interval P.TD. Type Test Test psi 1500 Casing P/F Notes: Test Details: TYPE INJ codes F = Fresh Water Inj G = Gas I nj S = Salt Water Inj N = Not Injecting TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance Test during Workover 0 = Other (describe in notes) MIT Report Form Revised: 05/19/02 2004-0711_MIT_KRU_3S-09.xls 7/14/2004 ') .' ConocJPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 26, 2003 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 ) Fl~Cl2lt i /. ".' V~" A '''. . 0 'r" 'u !Ii1ka~8Gas '200J ~Ca . Dear Mr. Maunder: Enclosed please find a spreadsheet with a short list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor by surface casing annulus. The voids were filled with cement to the top of the circulation ports in the conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place. The top-fill operation was completed on November 18,2003. Dowell-Schlumberger batch-mixed Arctic Set I cement to 15.7 ppg in a blender for each well. The cement was pumped from the bottom of the void to the top of the conductor on each well via high-pressure hose. The attached spreadsheet presents the well name, top of cement depth prior to filling, and the number of sacks used on each conductor. Please call Nina Woods or me at 907-659-7224, if you have any questions. :;;; ~I w~ / ,¿/ ConocoPhillips Alaska, Inc. Surface Casing by Conductor Annulus Cement Top-off ConocoPhillips Problem Well Supervisor Kuparuk Field Attachment :t:.\- '\ ~ ~~~ ~,~C""\. ~~ ~,'-<t~~\-. +0 Cf ~\\ 'o~<::-~\' cA~~ ~cd~~ ~I..XL<!O.<¡,~r.ù \ \ '-/ ~~ ""-«. ,,~d -\0 s.<:>~. À\\ o~+~ \'T~<"" ~-\-""s~~ ~G:..'"'1 f'.QO-\ +~<ê. Su~~... ~o.Çù,-\-~(L' Q.~.\\o,", f'.<l.~S&~''i, fr)!.¥7I~ Á-a~ Well Well Toe Volume Sacks Name PTD# Type ft BBlS Cement 38-03 2030910 Prod 8 0.6 3.6 38-07 2021870 Prod 8 1.5 9.1 38-09 2022050 Inj 14 2.5 15.1 38-10 2022320 Prod 12 1.5 9.1 38-14 2022210 Inj 3 1.5 9.1 3S-15 2022540 Prod 8 0.8 4.8 3S-17 A 2030800 Prod 12 1.1 6.6 38-18 2022060 Prod 10 1.1 6.6 38-19 2030960 Prod 5 1.1 6.6 3S-21 2030310 Inj 5 0.5 3.0 38-22 2030110 Inj 7 0.9 5.4 38-23 2030450 Prod 2 0.3 1.8 Scblumbergel' NO. 2967 Schlumberger Technology Corporation, by and through is Geoquest Division 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth 09/25/03 Company: Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Well Field: Date BL Color 09/01/03 1 09/02/03 1 09/05/03 1 08/01/03 1 08/02/03 1 08/06/03 1 08/07/03 1 08/20103 1 08/23/03 1 08/14/03 1 Job# Log Description 2X-14 ')~4 -I.~ PROD PROFILE/DEFT 2A-24 1 q ~ - I L PROD PROFILE 3F-15 t~J:)-(5L:. INJECTION PROFILE 3S-24 /J.C~-:;' -Q . INJECTION PROFILE 3S-09 /~ r:~ -:~15 INJECTION PROFILE 3H-07 l.~~i-~'--(...lINJECTION PROFILE 2K-11 ~q -/ 5 S8HP SURVEY 1 D-1 03 (~~ 'tj - 10 INJECTION PROFILE 1C-174 -:£~ - ,/" -r INJECTION PROFILE 18-102 r90g-~ 23432 USIT ~~\.. ~.~ SIGNED: ,~'~\ ~.Y\ -\ '\~ 0 ~~~ ~ ~ DATE: Kuparuk CD ~ .~ .?'-. ~-.I~ 1t'-"'" ..;ij" ~ ~.S'-~ ~ \.t :~~ ~- Ù.'-"-"":\.., >~ ~=" !~ . iF"'" ~i~,ß ~ b# .~ ~>~ ~.~ ~;¡t ~~""Q -:I ".:'t9 ~ ~rp ? R l:O(ß }~i~~SK¡j Gi~ ,2t Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. i\.f1chor~ge C;omm;~on ~~, C' Schlumbepgep NO. 2765 Schlumberger Technology Corporation, by and through is Geoquest Division 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth 05/05/03 Company: Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Well Job# Log Description Date BL Color 35-21 ("~n..1--0~~' SBHP 5URVEY 04/18/03 1 1B-08A I q 7'1 ~ I INJECTION PROFILE 04/17/03 1 35-09 ~Q.-;)~ OS INJECTION PROFILE 04/07/03 1 35-10 dCB- .3 Ô) PRODUCTION PROFILE 04/08/03 1 1G-13 ~5- JL/o PRODUCTION PROFILE 04/09/03 1 3S-21 ()3Ó;j-=st SCMT 04/18/03 1 1C-174 t3- . "Î 23113 USIT 04/01/03 1 1G-03 J 'd-14::¡ INJECTION PROFILE 04/24/03 1 1C-135 ¿;( df- ~n PRESS/TEMP SURVEY 04/23/03 1 / '/: SIGNE~ f~ll~ DATE: Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. Kuparuk CD ~. ~ RECEIVED N1AY 08 2003 ,ÀJa~a ot: & Gas Cons. Commi5eion Anchorage .He: [FW(J: 38-09 Water Injection]--PTD 202-205 ) ) Subject: Re: [Fwd: 35-09 Water Injection]--PTD 202-205 Date: Wed, 30 Apr 200307:32:12 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Daniel E Hensley <Dan.E.Hensley@conocophillips.com>, "Christopher J. Alonzo" <Chris.Alonzo@conocophillips.com>, CPF3 Prod Engrs <n1223@conocophillips.com> Dan, Chris, et ai, I have examined the information submitted on 38-09 and agree that the information demonstrates that the water is being confined to the intended zone. We look forward to the follow-up diagnostics that you indicate will be performed in about mid August. Please call me if you have any questions at 793-1250. Tom Maunder, PE AOGCC > > Subject: Re: 3S-09 Water Injection > Date: Tue, 29 Apr 2003 16:34:57 -0800 > From: "Daniel E Hensley" <Dan.E.Hensley@conocophillips.com> > To: Winton Aubert <Winton_Aubert@admin.state.ak.us> > CC: "CPF3 Prod Engrs" <n1223@conocophillips.com>, > "Daniel E Hensley" <Dan.E.Hensley@conocophillips.com>, > "Christopher J. Alonzo" <Chris.Alonzo@conocophillips.com> > > Winton > > Attached below you will find the E-line log from the 3S-09 IPROF & > Temperature Survey (PDS file) completed on 04/07/03. A baseline > temperature survey was conducted while injecting water into well 3S-09, > then the well was shut-in and warm-back temperature passes were conducted > 15, 30, 60, and 120 minutes after shut-in. Based on the results of the > warm-back temperature passes, there is NO indication of out of zone > injection on well 3S-09. > > In addition, the well 3S-09 injection conditions (injection pressure, > injection temperature, injection rate, inner annulus pressure, and outer > annulus pressure) have NOT been unusual or anomalous. > > Also, on 02/23/03, well 3S-09 PASSED the state witnessed MIT on the inner > annulus. > > To complete the condition of approval for water injection into weIl3S-09, > we will complete a follow-up temperature survey on we1l3S-09 after 6 (six) > months of water injection (approximately mid-August 2003) and submit > results to the A OGCC. > > Please give me a call if you'd like to discuss. > > Thanks > Dan Hensley > Palm Surveillance Engineer > ConocoPhillips Alaska > 907-265-1606 > Dan.E.Hensley@conocophillips.com > > (See attåched file: 3S-09_IPROF.PDS) > > > Winton Aubert <Winton_Aubert@admin.state.ak.us> 1 of 4 4/30/20037:32 AM Re: [FW\":J: 38-09 Water Injection]--PTD 202-20f .) ) > > > > To: Daniel E Hensley/PPCO@Phillips > cc: Camille 0 Taylor <cammy_taylor@admin.state.ak.us>, Michael L Bill <mike_bill@admin.state.ak.us>, Daniel Seamount > <dan - seamount@admin.state.ak.us> > Subject: 3S-09 Water Injection > > > Dan, > > AOGCC hereby approves water injection in well 3S-09 on a conditional basis. > Please submit the following to the > Commission as conditions of approval:. > > (1) an acceptable down hole temperature survey obtained after 15 days > of injection; > (2) a follow-up down hole temperature survey obtained after 6 (six) > months of injection; > (3) results of an MIT (notify AOGCC North Slope Inspectors for > witness). > > Also, if you encounter any problems or unusual injection conditions, you > must cease injection, shut in well > 38-09, and notify the Commission. > > Winton Aubert > AOGCC > 793-1231 > > Daniel E Hensley wrote: > > > Winton » > > Thanks in advance for your time in reviewing the well 3S-09 information > > provided below. » > > As mentioned in our previous conversation, ConocoPhillips Alaska believes > > that the cement bond log (SCMT) ran on well 3S-09 shows adequate cement > to > > provide isolation of injected fluids to the approved interval (Kuparuk C4 > > Sand). Since the cement bond log (SCMT) ran on well 3S-09 shows > > approximately 8 - 10 feet of excellent cement quality and the remainder > of > > the interval showing less than excellent cement quality, I respectfully > > request your review of the information. In addition, the well 3S-09 > cement > > bond log (SCMT) was ran with 1700 psi wellhead pressure and 3000 psi > > wellhead pressure. Based on the VDL and cement mapping image from the > > SCMT, the cement quality improved with increased wellhead pressure which > is > > indicative of a microannulus effect. » > > Background Information/Timeline > > Well 3S-09 was drilled as an initial DS 3S development well and > > completed as a 7" long string with 3.5" tubing injection well. > > Drilling operations occurred on well 3S-09 from 12/04/02 - 12/17/02. > > Cemented 7" casing per plan on 12/15/02, except unable to reciprocate > > casing while cementing. > > Based on reservoir quality, decided to pre-produce injection well 01/29/200309:42 AM 2of4 4/30/20037:32 AM . Re: [Fwd: 38-09 Water Injection]--PTD 202-20F ...) ) > 35-09 > > for reservoir data gathering opportunity. > > Post-rig wellwork activities, which includes cement bond log, occurred > > on well 3S-09 from 12/21/02 - 12/25/02. > > Intermittent production from well 3S-09 from 12/26/02 to 01/20/03. > > Intermittent production only because of high produced gas rates. > > Well 3S-09 shut-in on 01/20/03 for surface facility conversion from > > producer to injector. > > Plan to start-up water injection system on DS 3S on approximately > > 02/01/03. Will complete state witnessed MIT on the annulus of well > > 3S-09 shortly after initiating injection into the well. » > > Attached below you will find the well 3S-09 cement bond log, wellbore > > schematic, well plan, outer annulus pressure trends, and drilling summary > > report. If you have any questions or recommendations, please give me a > > call at 265-1606. » > > Thanks > > Dan Hensley > > Palm Surveillance Engineer > > ConocoPhillips Alaska > > 907-265-1606 > > Dan.E.Hensley@conocophillips.com » > > (See attached file: ScmL VDL_lmage_020.PDS)(See attached file: > > ScmL VDL_lmage_019.PDS)(See attached file: 3S-09.pdf)(See attached file: > > 38-09 Well Plan.doc)(See attached file: 3S-09 Outer Annulus Pressure > Trends > > 01-21-03.doc)(See attached file: 3S-09 Drilling Summary Report.doc) » » >------------------------------------------------------------------------ > > Name: ScmLVDL_lmage_020.PDS > > ScmLVDL_lmage_020.PDS Type: PDS File > (application/x-unknown-content-type-pdsfile) > > Encoding: base64 » > > Name: ScmL VDL_lmage_019.PDS > > ScmL VDL_lmage_019.PDS Type: PDS File > (application/x -unknown-content-type-pdsfile) > > Encoding: base64 » » » » » » » » » > > Name: 3S-09 Outer > Annulus Pressure Trends 01-21-03.doc > > 3S-09 Outer Annulus Pressure Trends 01-21-03.doc Type: WINWORD File > (application/msword) » » » Name: 3S-09.pdf 3S-09.pdf Type: Portable Document Format (application/pdf) Encoding: base64 Name: 3S-09 Well Plan.doc 3S-09 Well Plan. doc Type: WINWORD File (application/msword) Encoding: base64 Encoding: base64 Name: 3S-09 Drilling Summary > Report.doc > > 3S-09 Drilling Summary Report.doc Type: WINWORD File > (application/msword) » Encoding: base64 30f4 4/30/20037:32 AM Re: [F,^öd: 38-09 Water Injection]--PTD 202-20F ) > > ------------------------------------------------------------------------ > Name: 3S-09 IPROF.PDS > 3S-09_IPROF.PDS TyPe: PDSView Document (application/x-unknown-content-type-PDSView.Document) > Encodmg:base64 Maunder <tom maunder@admin.state.ak.us> 'oleum Engineer Oil and Gas Conservation Commission 40f4 4/30/20037:32 AM ~. LrlI~1 ~:!~:I ~ I Tl ~ ~~ ,.--" ./"' <- ....., f~ } )/ { ~ > ~ ;0 r--- ') ? ~') . .-1 C CCl [01] (P01 CCl) iH' Annotations not supported at this X-Coordinate. . . I -- - - ... . f ..: , , ~ " " 0 A ~ I ¿ . ~ . 4. . ... EIII:;ì '-I 'T~---, I ¡ I ! . . --: ' TCM ~ ~IILC INJfCTI""G ./ i"'¿ro> 1~ MI~ ^~-"'R ""IIIJT I~ i " r .- ; --: 'T :MÞ aq 'utIN ^F'T:R ~ IU- IN ~ It. ..... b'}.A\.. ti~ M r" At-' t: K'\¡ H I., I I fJ , .1 I ,l 1 I r- T C M r 120 M I ~ ^F' T C r ~ I..J T I ~ ,:..~ J /' : I ,,' " ;. .. / ,r<"- : ({ I" . i: j ,: ¡ r ¡ ~ \ ~ l \ \ 1 ~ ... ~ , ., ; . ~ \ '=. \ \ \ ~ ~ \ \ ~~~ ..~ . è. ""¿~ ., J~ ¡ ~> I 1 } '" g:m f . .... \.. \ " '"' , \. '.. \. ,..... \ '\ \ ".. '. " ' \. '- ~_...-- ;ì::~~';n .~~'HJ~CTI~ ---~ ",<':.':oo...,.'t[MP 1G I,uN AFT-::R 9/1Ul' IN " ',' ",,*~~~p~n t.1~N ~n\! ~11r'lN "'".>. '. '"*."'-~- r~1i r 8~ MI . A~T~r ~II~T I . -......" ".,"', ,,'-ç"'-- I t:Mt-' 1:¿L"Mlroo At- t:K"SHL.' ,roo "" ',.".. ......" ,... ..... "-....... ~ ". '': ". '.~...~.~.;'~Z)~" '"........"" ","-.. ,'\, ...., ''1 ....... '" . . ,~- -, \." - ,.-. "'. - ~, --- ¿ ) í ,- LR n 1t-~-..~--~~"'V"""~~..., OPEN B,~j3'l2P~~r~~JJ£"~T!!Pl- - - - - - - - - -- f n r: I~ r: ., .1 nn Iw 8.25 -File Complete H ~ÍI -.. .M"" .. --~------ "'''1'\''''' 7n f ..... - . ...... -.. - ! J or~. """"':"'. I I cSÍIIo - - - . -. .. f .......- ~<s -O~ d-Od--d-OS ~ ''''-~~-'''''"-'''-~ A ...... ./'>?~~ ) <QæðÞ5 II &;(Pfp WELL LOG TRANSMITfAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Lisa Weepie 333 West 7th Avenue, Suite 100 Anchorage, Alaska March 27, 2003 RE: MWD Formation Evaluation Logs 38-09, AK-MW-22193 1 LDWG formatted Disc with verification listing. API#: 50-103-20432-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COpy OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Speny-Sun Drilling Service Attn: Jim Galvin 6900 Arctic Blvd. Anchorage, Alaska 99518 Date: Signed~&.Q¡~ RECEIVED APR 1 7 2003 Aíaalœ Qi & Gas Coos. Comm~ Anchorage ) ') STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown- Pull tubing - 2. Name of Operator ConocoPhillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface 2495' FNl, 972' FEl, Sec. 18, T12N, R8E , UM At top of productive interval 2527' FSl, 1718'FEl, Sec. 8,T12N, R8E,UM At effective depth At total depth 2534' FNl, 3735' FWl, Sec. 8, T12N, R8E , UM 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Size CONDUCTOR 80' 16" SURFACE 3475' 9-5/8" PRODUCTION 9611' 7" Perforation depth: measured 9302' - 9232', 9332' - 9352' true vertical 5806' - 5764', 5824' - 5836' Stimulate - Alter casing - 5. Type of Well: Development - Exploratory - Stratigraphic - SeNice_X (asp's 476286,5993919) (asp's 480818, 5998930) (asp's 481012,5999144) 9650 feet 6020 feet Plugs (measured) 9468 feet 5906 feet Junk (measured) Cemented 83 sx ArcticCrete 398 sx AS Lite, 300 sx LiteCrete 295 sx Class G w/GasBlok Tubing (size, grade, and measured depth) 3-1/2",9.3#, L-80 Tbg @ 8965' MD. Packers & SSSV (type & measured depth) Baker SA B-3 packer @ 8933' MD. Cameo DS Land Nipple @ 497' 13. Stimulation or cement squeeze summary C" htt...tb n fj l \81*P . ~ R~ Intervals treated (measured) N/A~:> n Y Treatment description including volumes used and final pressure \\J <2...1l Ctrn VE-R'("4?p. K II - Q3 14. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Met Water-Bbl N/A - Pre produced Injector Subsequent to operation 15. Attachments Copies of Logs and Surveys run - Daily Report of Well Operations - Oil- Gas- 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ,4-Jt5 Prior to well operation N/A Signed Mike Mooney ." ~ ry ~1 S B F l Form 10-404 Rev 06/15/88 . N/A Title: Wells Team Leader Plugging - Perforate - Repair well - Other _XX 6. Datum elevation (DF or KB feet) RKB 28 feet 7. Unit or Property name Change Well Type Kuparuk Unit 8. Well number 3S-09 9. Permit number I approval number 202-205 I 10. API number 50-103-20432 11. Field 1 Pool Kuparuk Oil Pool Measured Depth 108' 3504' 9639' True vertical Depth 108' 2596' 6013' ~ Casing Pressure Tubing Pressure 11800 Suspended - Service _MW AG Injector_XX Questions? Calf Mike Mooney 263-4574 Date 3/~ 5 Prepared by Sharon Allsup-Drake 263-4612 MAR ~ 4 SUBMIT IN DUPLICATE We1l3S-09 (I) Temperature Survey - CORRECTION Z.OL }¿c9S Subject: Well 3S-09 (I) Temperature Survey - CORRECTION Date: Tue, 25 Feb 2003 10:17:15 -0900 From: "Daniel E Hensley" <Dan.E.Hensley@conocophillips.com> To: winton_aubert@admin.state.ak.us CC: "CPF3 Prod Engrs" <n1223@conocophillips.com>, "Daniel E Hensley" <Dan.E.Hensley@conocophillips.com>, "Christopher J. Alonzo" <Chris.Alonzo@conocophillips.com> . ) 8ee below in red font. Dan Hensley Palm Surveillance Engineer ConocoPhillips Alaska 907-265-1606 Dan.E.Hensley@conocophillips.com ----- Forwarded by Daniel E Hensley/PPCO on 02/25/2003 10:15 AM ----- Daniel E Hensley 02/25/2003 10:10 AM To: winton aubert@admin.state.ak.us cc: CPF3 Prod Engrs/PPCO@Phillips, Daniel E Hensley/PPCO@Phillips, Christopher J. Alonzo/PPCO@Phillips 8ubject: Well 38-09 (I) Temperature 8urvey Winton As we discussed on the phone earlier, well 38-09 was brought on sea water injection on 02/11/03. As a condition of approval for water injection into well 38-09, the AOGCC and CPA1 agreed to complete "an acceptable down hole temperature survey obtained after 15 days of injection". Although the well 38-09 temperature survey procedure had been completed and the work had been scheduled after 15 days of injection (scheduled on approximately 02/26/03), the Nabors 7E8 drilling rig completed a development well ahead of schedule and moved on to well 38-08 last night which prevents well service access to well 38-09. The estimated drilling days for well 38-08 is 17.8 days. Therefore, CPA1 will complete the well 38-09 temperature survey as soon as the Nabors 7E8 drilling rig completes the well 38-08 and moves to the next scheduled well, 38-21, in the D8 38 drilling program. After moving to the next scheduled well in the drilling program, the Nabors 7E8 drilling rig interference will not be a problem for well service activity on well 38-09. To note, the well 38-09 injection conditions (injection pressure, injection temperature, injection rate, inner annulus pressure, and outer annulus pressure) have NOT been unusual or anomalous. Please give me a call if you'd like to discuss. Thanks Dan Hensley Palm Surveillance Engineer ConocoPhillips Alaska 907-265-16U6 Dan.E.Hensley@conocophillips.com ) MEMORANDUM ) State of Alaska Alaska Oil and Gas Conservation Commission TO: Randy Ruedrich ~ ~/63 Commissioner 1./ 2- ~9v\^ SUBJECT: Me.Ch.an......i..C. allntegrity Tests THRU: Tom Maunder : I v \ ~ ,Conoco Phillips P.L Supervisor a. ~ b....;Q~§ Pad KRU . FROM: Chuck Scheve Petroleum Inspector NON. CONFIDENTIAL DATE: February 23,2003 Packer Depth Pretest Initial 15 Min. 30 Min. Well 38-09 Type Inj. 8 T.V.D. 5590 Tubing 2325 2325 2325 2325 Interval I P.T.D. 202-205 Type test P Test psi 1398 Casi ng 0 1875 1800 1800 P/F f Notes: Well 38-14 Type Inj. S TV.D. 5555 Tubing 2250 2250 2250 2250 Interval I P.T.D. 202-221 Type test P Test psi 1389 Casi ng 775 1900 1850 1850 P/F f Notes: Well 38-26 Type Inj. S TV.D. 5749 Tubing 2400 2400 2400 2400 Interval I P.T.D. 201-040 Type test P Test psi 1437 Casi ng 25 1625 1600 1580 P/F f Notes: Well Type Inj. TV.D. Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: Well Type Inj. TV.D. Tubing Interval P.T.D. Type test Test psi Casi ng P/F Notes: Type INJ. Fluid Codes Type Test Interval F = FRESH WATER INJ. M= Annulus Monitoring 1= Initial Test G = GAS INJ. P= Standard Pressure Test 4= Four Year CYCle s = SALTWATER INJ. R= Internal Radioactive Tracer Survey V= Required by Variance N = NOT INJECTING A= Temperature Anomaly Survey W= Test during Workover D= Differential Temperature Test 0= Other (describe in notes) Test's Details I traveled to Conoco Phillips 38 Pad in the Kuparuk River Field and wi1nessed the initial MIT on wens 38-09, 38-14 and 38-26, The pretest tubmg and casing pressures were observed and found to be stable. The standard annulus pressure test was then performed with all three wells demonstrating good mechanical integrity. M.I.T.'s performed: ~ Attachments: Number of Failures: .Q Total Time during tests: 5 hours cc: MIT report form 5/12/00 L.G. MIT KRU 3S Pad 2-23-03 CS.xls 2/27/2003 02/06/03 Schlumbepgep NO. 2490 Schlumberger Technology Corporation, by and through is Geoquest Division 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth Company: Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk Well Job# Log Description Date BL Sepia CD Color --.. 1C-22 ~D~~d~ 23042 3S-09 aDd'd05 23004 SCMT SCMT 01/12/03 12/23/02 1 1 ~' SIGNEc)}~ ~ ) DATE: RECEIVED FEB 0 7 2003 Alaska Oil & Gas Cons. CommIaion Anchorage Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. Scblumbepgep NO. 2840 Schlumberger Technology Corporation, by and through is Geoquest Division 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth 01/31/03 Company: Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Well Job# Log Description Date BL Sepia 1R-14 Ji5.. / rs J LEAK DETECTION LOG 01/09/03 1 2G-15 184-1'&1 LEAK DETECTION LOG 01/08/03 1 1G-11 J~~'/~ I LEAK DETECTION LOG 01/10103 1 1A-08 I ì r¡( -aiD LEAK DETECTION LOG 01/07/03 1 2U-02 I~'OOS LEAK DETECTION LOG 01/11/03 1 2N-349A dOD-/3'1 INJECTION PROFILE 12/20/02 1 3S-09 riœ.-dD5 JEWELRY LOG/PSP 12/24/02 1 1C-22 aOd'~d-;) PERF RECORD & POST PERF SBHP 01/17/03 1 3S-1 0 1°~ 'd3ö) PERF/JEWELRY/PSP 01/15/03 1 1Y-21 I 3- IDd STATIC PRESSITEMP LOG 01/14/03 1 1Y-34 Ie :3..0'1 I STATIC PRESSITEMP LOG 01/14/03 1 SIG~ ú~ DATE: Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. Kuparuk CD Color .'"-"" .~ RECEIVED FE8 07 2003 AJa8iœ or¡ & Gas Cons. Commi88ion Anctun.ge ) ) Randy Thomas Greater Kuparuk Team Leader Drilling & Wells ConocóPhillips P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-6830 January 17, 2003 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Report for 3S-09 (202-205) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Well Completion Report for the recent drilling operations on the Kuparuk well 3S-09. If you have any questions regarding this matter, please contact Scott Lowry at 265-6869. Sincerely, .~~ - ..--...... R. Thomas Greater Kuparuk Team Leader CPAI Drilling RL T/skad RECfi E t" t.: 1)0' n" L ",j Alaska Oil & Commission Anchorage ') STATE OF ALASKA ) ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of well Classification of Service Well Oil 0 Gas 0 2. Name of Operator ConocoPhillips Alaska, Inc. 3. Address P. O. Sox 100360, Anchorage, AK 99510-0360 4. Location of well at surface Suspended 0 Abandoned 0 Service 0 Pre-Produced Injector 7. Permit Number 202-205 1 8. API Number 50-1 03-20432 2497' FNL, 974' FEL, Sec. 18, T12N, R8E, UM At Top Producing Interval 2527' FSL, 1718' FEL, Sec. 8, T12N, R8E, UM At Total Depth 2744' FSL, 3735' FWL, Sec. 8, T12N, R8E, UM (ASP: 481012,5999145) 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. RKS 28 feet ADL 380106 ALK 4623 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., S.~~ Or Aband. 15. Water Depth, if offshore December 4,2002 December 13, 2002 I December~2002 ~ 1> N/A feet MSL 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 20. Depth where SSSV set 9650' MD 16020' TVD 9468' MD 15906' TVD YES 0 No 0 Land Nipple @ 497' 22. Type Electric or Other Logs Run GR/Res 23. (ASP: 476286, 5993919) 9. Unit or Lease Name Kuparuk River Unit 10. Well Number (ASP: 480818, 5998930) 3S-09 11. Field and Pool Kuparuk River Oil Pool Kuparuk River Field 16. No. of Completions 1 21. Thickness of Permafrost 1700' MD 16" WT. PER FT. 62.5# 40# 26# GRADE S L-80 L-80 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 108' Surface 3504' Surface 9639' HOLE SIZE CASING SIZE 42" CEMENTING RECORD 83 sx ArcticCrete AMOUNT PULLED 7" 8.5" 398 sx AS Lite, 300 sx LiteCrete 295 sx Class G w/GasBlok 9.625" 12.25" 24. Perforations open to Production (MD + TVD of Top and Bottom and interval, size and number) 3.5" TUBING RECORD DEPTH SET (MD) 8965' PACKER SET (MD) 8933' 25. SIZE 9302' - 9232' MD 5806' - 5764' TVD 6 spf 9332' - 9352' MD 5824' - 5836' TVD 6 spf 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED N/A 12/26/2002 2.5 hours Flow Tubing Casing Pressure pressure 2423 ps not available 28. PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Pre-Produced Injector Production for OIL-BBL GAS-MCF Test Period> 149 1338 Calculated OIL-BBL GAS-MCF 24-Hour Rate> 1340 12794 CORE DATA W A TER-BBL 0 W A TER-BBL CHOKE SIZE GAS-OIL RATIO 9677 27. Date First Production December 26, 2002 Date of Test Hours Tested 0 25% OIL GRAVITY - API (corr) not available Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. t: 'io.. N/A ,& 6~ Form 1 0-407 Rev. 7-1-80 RBDMS BFt CONTINUED,QN.REVEF3SE ~,IDE;, Submit in duplicate FEB 3 29. ) 30. ) FORMATION TESTS GEOLOGIC MARKERS MEAS.DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity. GOR, and time of each phase. NAME Top Kuparuk Base Kuparuk 9283.5' 9352' 5795' 5836' Annulus left open - freeze protected with diesel. 31. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey 32. I hereby certify that the following is true and correct to the best of my knowledge. Questions? Call Scott Lowry 265-6869 Signed~~ , - :~oJes Title KUDaruk Drilling Team Leader Date l (¿ ,/0 .~ Prepared by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 ') ') Page 1 of 7 ConocoPhillips Alaska Operations Summary Report Legal Well Name: 3S-09 Common Well Name: 3S-09 Event Name: ROT - DRILLING Contractor Name: N1268@ppco.com Rig Name: Nabors 7ES Date From - To Hours Code Sub Phase Code 12/3/2002 18:00 - 19:30 1.50 MOVE DMOB MOVE 19:30 - 21 :30 2.00 MOVE MOVE MOVE 21 :30 - 00:00 2.50 MOVE MOVE MOVE 12/4/2002 00:00 - 02:30 2.50 MOVE MOVE MOVE 02:30 - 07:30 5.00 WELCTL NUND SURFAC 07:30 - 08:30 1.00 DRILL OTHR SURFAC 08:30 - 09:00 0.50 DRILL PULD SURFAC 09:00 - 09:30 0.50 WELCTL BOPE SURFAC 09:30 - 12:00 2.50 DRILL PULD SURFAC 12:00 - 13:30 1.50 DRILL OTHR SURFAC 13:30 - 14:30 1.00 DRILL OTHR SURFAC 14:30 - 00:00 9.50 DRILL DRLG SURFAC 12/5/2002 24.00 DRILL DRLG SURFAC 00:00 - 00:00 12/6/2002 00:00 - 08:00 8.00 DRILL DRLG SURFAC 08:00 - 10:45 2.75 DRILL CIRC SURFAC 10:45 - 13:30 2.75 DRILL TRIP SURFAC 13:30 - 14:15 0.75 DRILL REAM SURFAC 14:15 - 16:30 2.25 DRILL TRIP SURFAC 16:30 - 18:30 2.00 DRILL PULD SURFAC Spud Date: 12/4/2002 Start: 12/4/2002 End: 12/17/2002 Rig Release: 12/17/2002 Group: Rig Number: Description of Operations Move out open top tank and injection skid - move out ball mill and pit complex. Pull subbase off well, set on surface stack on 3S-09, move rig over hole. Spot pits and ball mill, ru water, air and mud lines. Lay herculite, Spot injection skid. Hook up steam lines. Build berms. Rig accepted @ 0200 hrs 12/4/2002 NU 20" surface diverter stack. Mixing spud mud. Pickup around rig. Pickup 6.6" flex DC's. MU & stand in derrick. Function test diverter. Accumulator prill. Test Koomey unit. Witness of diverter test waived by AOGCC inspector Chuck Scheeve Makeup BHA # 1. Orient tools. Fill hole, check fl leaks. Problems wi air boots on riser leaking. Repair air boot to hold spud mud. Spud @ 1430 hrs. Drill fl 108' to 997' (889') TVD = 989' ART = 3.4 hrs AST = 4 hrs Drill wi up to 35 k on bit, 60 rpm rotary, MM ?? RPM, 150-162SPM, 450-475 GPM, 1600 psi, PU wt to 73 k, SO wt to 73 k, torque off bttm to 2,500 ft/lb, torque on bttm to 3500 ft/lb Directional drill 12 1/4" hole fl 997' to 2996' (1999') TVD @ 2996' = 2325' AST = 10.5 hrs ART = 4.75 hrs Pumped sweeps @ approx 1300', 1800' and 2300'. Vis in 140 to 180 VIS out 120-300 Mud losses started while drilling in West Sak Formation while pumping @ 560 gpm. From 1700 hrs to midnight losses = 350 bbl. Drill wi up to 35 k WOB, 60-100 rpm, MM 63-84,143-191 spm, 1250- 2400 psi, PU wt 75-85 k, SO wt 75-81 k,Rot wt 75-85 k. Note: from midnight to 0600 12/6/2002: Losses of 40-50 bbls Directional drill 12 1/4" hole fl 2996' to 3515' (519') TVD = 2601' ART = 3.14 hrs AST = .86 hrs Drill wi 35 k WOB, 90-100 rpm, MM 82-85,190 spm, 2500 psi, PU wt 100, SO wt 80 k, Rot wt 85 k CBU, pumped 40 bbls 10.6 ppg - 300+ FV sweep with 2.5 ppb Barafiber - circ hole clean 650 gpm I 2975 psi I 100 rpm. Moderate increase in cuttings (sand) with sweep back - 3.5 x BU total pumped. Flow check well static. Blow down TD - line up on trip tank. POH to 1620' - Wiped tight spots clean @ 1720' & 1700' (20k over) worked tight hole from 1650' to 1620' - over pull increased from 20k to 35K. RIH to 1756'. Backream from 1756 to 1661' - 564 gpm 11630 psi I 80 rpm moderate amount of cuttings back, no increase at BU. Continue to POH - wiped tight spot @ 1580' (15k over) - POH to hwdp 3-5K over. Flowcheck well, static. Stand back hwdp and flex collars. LD BHA - UBHO, stab, puser and H/O sub, flex collar, NM stab, FS, bit Printed: 12/18/2002 10:55:48 AM ) ') Page 2 of 7 ConocoPhillips Alaska Operations Summary Report Legal Well Name: 3S-09 Common Well Name: 3S-09 Event Name: ROT - DRILLING Contractor Name: N1268@ppco.com Rig Name: Nabors 7ES Date From - To Hours Code Sub Phase Code 12/6/2002 16:30 - 18:30 2.00 DRILL PULD SURFAC 18:30 - 20:30 2.00 CASE RURD SURFAC 20:30 - 21 :00 0.50 CASE SFTY SURFAC 21 :00 - 00:00 3.00 CASE RUNC SURFAC 12/7/2002 00:00 - 03:00 3.00 CASE RUNC SURFAC 03:00 - 04:00 1.00 CASE CIRC SURFAC 04:00 - 05:30 1.50 CASE RUNC SURFAC 05:30 - 06:30 1.00 CASE CIRC SURFAC 06:30 - 07:30 1.00 CASE RUNC SURFAC 07:30 - 08:00 0.50 CEMENT RURD SURFAC 08:00 - 12:00 4.00 CEMENTCIRC SURFAC 12:00 - 13:30 1.50 CEMENT PUMP SURFAC 13:30 - 14:00 0.50 CEMENT DISP SURFAC 14:00 - 15:00 1.00 CEMENT OTHR SURFAC 15:00 - 16:30 1.50 CASE RURD SURFAC 16:30 - 19:30 3.00 WELCTL NUND SURFAC 19:30 - 20:30 1.00 WELCTL NUND SURFAC 20:30 - 22:30 2.00 WELCTL NUND SURFAC 22:30 - 00:00 1.50 WELCTL NUND SURFAC 12/8/2002 6.00 WELCTL NUND SURFAC 00:00 - 06:00 Start: 12/4/2002 Rig Release: 12/17/2002 Rig Number: Spud Date: 12/4/2002 End: 12/17/2002 Group: Description of Operations and motor. Clear tools from floor and clean up trip mess. RU long casing bails, RU Frank's fillup tool and Nabors casing equipment. PJSM wI crew on running 9 5/8" casing. Run 9 5/8", 40#/ft, L-80, BTC casing. Jt 34 in hole @ midnight. Depth 1463'. Continue RIH wI 9 5/8" 40#/ft L-80 BTC . Wash fl 1520' to 2008' as needed. PUW 115K SOW 70-75 Condition mud and circ initial rate 5 bpm @ 275 psi final rate 6 bpm wI 315 psi - final PUW 1 05K I SOW 75-80K - total volume pumped 250 bbls. Continue RIH w/9 5/8" 40#/ft L-80 BTC fl 2080' to 3080'. Displacement dropped to 75% of calculated. Circ and cond mud - initial 1.2 bpm I 317 psi final 4 bpm 1210 psi PUW 125k SOW 95k. 133 bbls total pumped. Continue RIH w/9 5/8" 40#/ft L-80 BTC fl 3080' to 3475'. Total of 81 joints 9 5/8" casing in hole, MU hanger and landing joint - land casing SOW 100k. Tam port collar @ 1018' Float collar @ 3415' Float shoe @ 3504' UD Frank's FC-1fill-up tool. Blow down top drive. MU Dowell cement head. Establish circ @ 1.5 bpm 150 psi - stage pumps up to 8 bpm - circ and cond mud - reduced FV from 122 to 50 - YP from 30 to 14. Final circ press 440 psi- last 100 bbls pumped wI 5 ppb nut plug for marker. PJSM. Line up to cementers - Pumped 5 bbls CW 100 - Test lines to 3000 psi - Pump additional 45 bbl of CW 100. Drop bttm plug, follow wI 50 bbl 10.5 ppg Mud Push XL with 2 gals die marker. Pumped 316 bbls of 10.7 ppg ASLite lead, follow by 125 bbls 12.0 ppg LiteCRETE tail. Drop top plug, displaced 20 bbls of FW from cementers. Swiched to rig pumps: displaced wI 9.4 ppg mud @ 8 bpm 390 psi to 682 psi wI 220 bbls pumped - Slowed rate to 4 bpm I 468 psi last 19 bbls pumped. Bumped plugs to 980 psi - floats held. Reciprocated pipe untilllast 90 bbls of displacement - full returns throughout - had 60 bbls of 10.8 ppg cement returns to surface. CIP @ 1344 hrs 12/7/2002. Wash out 20" diverter system wI retarder (011 O).RlD cement equipment. Backout landing joint, UD same. Blowdown all lines. Remove casing elevators. Change out casing bails to drilling bails. PJSM. N/D 20" diverter system. (Time to remove slip on head 1.5 hrs). Bring FMC csg head and FMC tubing spool into cellar. Set drilling spool in cellar. Attempt to pickup 13 5/8" BOP stack from stump with Kevlar slings. Removed wire rope slings to avoid having to use safety chain wrapped around Hydril. NO go. Rig back up wI wire rope slings. *Need to be able to safely pick BOPE. Attempt to install BOPE. Could not raise stack high enough to clear drilling spool wI present rigup. Remove 13 5/8" 5m x 11" 5m x-o spool. NU DSA. PU BOP stack fl stump with winches. Stack 135/8" BOPE on FMC wellhead. FMC Printed: 12/18/2002 10:55:48 AM ) ) ConocoPhillips Alaska Operations Summary Report Legal Well Name: 3S-09 Common Well Name: 3S-09 Event Name: ROT - DRILLING Contractor Name: N1268@ppco.com Rig Name: Nabors 7ES Date From - To Hours Code Sub Phase Code 12/8/2002 00:00 - 06:00 6.00 WELCTL NUND SURFAC 06:00 - 06:30 0.50 WELCTL OTHR SURFAC 06:30 - 10:30 4.00 WELCTL BOPE SURFAC 10:30 - 11 :30 1.00 WELCTL OTHR SURFAC 11 :30 - 12:00 0.50 RIGMNT RGRP SURFAC 12:00 - 12:30 0.50 RIGMNT RSRV SURFAC 12:30 - 13:30 1.00 WELCTL BOPE SURFAC 13:30 - 16:30 3.00 DRILL TRIP SURFAC 16:30 - 18:00 1.50 DRILL TRIP SURFAC 18:00 - 20:00 2.00 DRILL PULD SURFAC 20:00 - 22:00 2.00 DRILL PULD SURFAC 22:00 - 00:00 2.00 DRILL TRIP SURFAC 12/9/2002 00:00 - 02:00 2.00 DRILL TRIP SURFAC 02:00 - 03:00 1.00 DRILL CIRC SURFAC 03:00 - 04:00 1.00 DRILL OTHR SURFAC 04:00 - 05:30 1.50 CEMENT DSHO SURFAC 05:30 - 07:30 2.00 DRILL CIRC SURFAC 07:30 - 08:30 1.00 DRILL OTHR SURFAC 08:30 - 11 :00 2.50 DRILL DRLG PROD 11 :00 - 12:00 1.00 DRILL CIRC PROD 12:00 - 21 :00 9.00 DRILL DRLG PROD 21 :00 - 21 :30 0.50 DRILL CIRC PROD 21 :30 - 00:00 2.50 DRILL DRLG PROD 12/10/2002 00:00 - 09:30 9.50 DRILL DRLG PROD Page 3 of 7 Start: 12/4/2002 Rig Release: 12/17/2002 Rig Number: Spud Date: 12/4/2002 End: 12/17/2002 Group: Description of Operations energize seal and test to 1000 psi fl 10 min.OK. Torque bolts on 7" casg flange and 3 1/2" tubing spool and DSA to BOP stack. Working on top drive IBOP valve and acctuator while NU BOPE. RU to test BOPE. Test BOPE to 250 psi low and 5000 psi high. Annular was tested to 250 psi low and 3500 psi high. Witness of test waived by AOGCC inspector John Crisp. RID testing equipment. Install wear bushiing. Blow down choke manifold, choke and kill lines. Install two manual TIW valves and clamps on top drive shaft. New valve on order, as well as accuator fl lower IBOP fl top drive. Lubricate rig and top drive. Test upper IBOP to 250 psi low and 5000 psi high. PU 81 joints of 5" drill pipe from pipe shed;run in hole as picked up. POOH wI 2574' of 5" drill pipe (81 joints=27 stands). Stand back drill pipe in derrick. PU BHA # 2. Orient and upload MWD data. Held PJSM on sources. PU stand of flex dc's. UD top single. Shallow test MWD. Load sources and PU top single DC. Pump @ 456 gpm wI 745 psi RIH wI BHA # 2 and 5" HWDP. Rotate 2 stands through TAM port collar. Continue to PU 5" dp fl pipe shed on top of BHA and RIH. Continue picking up 5" Dp on top of BHA # 2, running in hole to tag TOC @ 3405'. Circulate and condition cement contaminated mud @ 9.5 bpm wI 1100 psi. Pumped 350 bbls (2 ann volumes) RU to test 9 5/8" 40 #/ft L-80 casing. Test casing fl 30 min., chart test. Pumped total of 51 strokes= 3 bbl. Blow down lines. Drill wiper plugs,float equipment, shoe track & 20' new formation to 3535'. Condition mud. Change over to 9.3 ppg LSND mud. Clean possum belly at shale shakers. CBU. RU to perform LOT @ 3535' MD. TVD = 2611'. Test to EMW of 18 ppg wI 1180 psi. RID and blowdown lines. Directional drill 8 1/2" hole fl 3535' to 3838' (303') TVD = ART = .75 hrs AST = .25 hrs Change out shaker screens. Rotate @ 120 rpm & recip,pump @ 350 gpm Directional drill 8 1/2" hole fl 3838' t 4924' (1086') TVD = 33501' ART = 4.5 hrs AST = .5 hrs Pumped sweeps every 300' fl ECD control. ED's still reached 12.7 ppg. Drill wI 10-15 k WOB, 120 rpm, pump 550 gpm, MM 181 rpm, 2150 psi, PU wt 135 k, SO wt 74 k, Rot wt 96 k Circ and pump hi vis sweep fl ECD control. ECD's dropped to 11.3 ppg. Directional drill 8 1/2" hole f/4924' to 5115' (191') TVD = 3460' ART = 2.0 hrs @ 150 fph to control ECD's. Drill wI 10-20 k WOB, 120 rpm, pump 571 gpm, MM 188 rpm, 2250 psi, PU wt 138 k, SO wt 76 k, Rot wt 98 k Drill81/2" hole from 5,115' to 6,163' MD I 4,046' TVD, AST .5 Hr, ART 5.5 Hrs, 1 0-15K WOB, 120 RPM's, ROT Wt 102K, Up Wt 165K, Dn Wt Printed: 12/18/2002 10:55:48 AM ) ') ConocoPhillips Alaska Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 3S-09 3S-09 ROT - DRILLING N 1268 @ ppco.com Nabors 7ES Date Sub From - To Hours Code Code Phase 12/10/2002 00:00 - 09:30 9.50 DRILL DRLG PROD 09:30 - 10:00 0.50 DRILL CIRC PROD 10:00 - 22:00 12.00 DRILL DRLG PROD 22:00 - 23:30 1.50 DRILL CIRC PROD 23:30 - 00:00 0.50 DRILL TRIP PROD 12/11/2002 00:00 - 03:30 3.50 DRILL TRIP PROD 03:30 - 05:00 1.50 RIGMNT RSRV PROD 05:00 - 07:00 2.00 DRILL TRIP PROD 07:00 - 08:00 1.00 DRILL CIRC PROD 08:00 - 00:00 16.00 DRILL DRLG PROD 12/12/2002 00:00 - 10:30 10.50 DRILL DRLG PROD 10:30 - 13:30 3.00 DRILL CIRC PROD 13:30 - 17:30 4.00 DRILL WIPR PROD 17:30 - 19:00 19:00 - 19:30 1.50 DRILL WIPR PROD 0.50 DRILL WIPR PROD 19:30 - 21 :30 2.00 DRILL CIRC PROD Page 4 of 7 Start: 12/4/2002 Rig Release: 12/17/2002 Rig Number: Spud Date: 12/4/2002 End: 12/17/2002 Group: Description of Operations 82K, Off Btm Torque 8.5K, On Btm 10K, 575 GPM's @ 2,800 Psi Average ROP 200-225 fph ECD's increased from 12.2 ppg to 12.8 ppg Pumped 40 bbls 300+ FV sweep @ 6068'. Fin Circ Sweep Out of Hole & replaced worn Shaker Screens, ECD's @ 12.2 ppg with sweep around 0.58 ppg reduction. Drill 8 1/2" hole from 6,163' to 7,496' MDI 4,788' TVD, AST 1 Hr, ART 6.25 Hrs, 10-15K WOB, 120 RPM's, ROT Wt 126K, Up Wt 190K, Dn Wt 90K, Off Btm Torque 11-12K, On Btm 13-15K, 237 SPM, 575 GPM's @ 2,800 Psi, Ave 55 Units BGG, Ave ECD with 10.0 ppg Mud 11.8 ppg ** Noticed steady down trend in ECD after drilling into C-40 average from 12.4 to 11.8 ppg. Pumped Weighted Sweep & Circ Hole Clean for Wiper Trip final ECD 11 .5 ppg Monitored Well-Static, Began Wiper Trip to Shoe, POOH 3 Stds to 7,200' with No Problems Cont Wiper Trip, Ratty From 5,780-5,700 Worked Back Thru with No Problems, POOH to 5,593' & Pumped Dry Job & Blew Down Top Drive, Cont POOH to 3,495' Up Inside 9 5/8" Csg Shoe with No Problems Serviced Top Drive, Blocks & Crown, Inspected Derrick Due to Nut That Fell to Rig Floor, Found Nut Had been left from a Previous Repair RIH to 7,401' with No Problems Est Circ Washed 95' to Btm, with No Problems, Pumped 40 bbl High Vis Sweep & Circ Out, Max Gas on Btms Up 280 Units Drill 8 1/2" hole from 7,496' to 8,542' MDI 5,371' TVD, AST 4.25 Hr, ART 6.15 Hrs, (10.4 Hrs Total) 10-15K WOB, 120 RPM's, ROT Wt 136K, Up Wt 2000K, Dn Wt 98K, Off Btm Torque 12-13K, On Btm 12-15K, 500 GPM's @ 2,600 Psi, Off Btm, 2,750 psi On, Raised Mw to 12.0+ ppg per Plan, ECD with 12.0+ ppg Mud Ave 13.4 ppg, Control Drlg at Ave 1 OO'lHr to Maintain 13.4 ECD, BGG Initially Ave 100 Units and have increased to 200-250 Units Max Gas 510 Units from 8,380' MDI 5,284' TVD Drill 8 1/2" Hole from 8,542' to 9,232', ART 7.25 Hrs, AST -0- with 10-15K WOB,120 Rpm's, 472 Gpm's @ 2,800 Psi, with 13.3 ECD, Had 4,500 Units BGG (lag time corrected drill depth 9163' md 15723' tvd) Circ & Raise MW to 12.3 ppg, Circ @ 480 Gpm's @ 2,825 psi & 115 Rpm's Rot Wt 142K, PU Wt 220K, Dn Wt 102K Torque on Btm 14-15K, Off Btm 14K, BGG Down to 220 Units Monitored Well-Static, Attempt to POOH, Had Tight Spot F/9,140'-9,118', MU Top Drive & Backreamed @ 60 Rpms, 475 Gpm's @ 2,825 Psi, POOH F/9, 118'-8,538' with 20-40K over, Worked Thru Tight Spot @ 8,538', Pulled 50K Over, MU Top Drive & Backreamed F/8,580'-8,476' @ 325 Gpm's, 1,800 Psi & 60 Rpms, POOH F/8,476'-8,425' with 30-50K, MU Top Drive & Backreamed Out F/8,476'-8,068' @ 445 Gpm's, 2,490 Psi @ 100 Rpm's, Torque Steady @ 15,000 Ft#'s Last 2 Stds, POOH F/8,068'-7,400' with 10-20K Over & No Other Problems Monitored Well-Static, TIH to 9,110' With No Problems Est Circ @ 500 Gpm's, 2,940 Psi & 70 Rpm's, Washed 122' F/9, 110' to 9,232', No Problems Circ & Cond Mud, Btm Up Max Gas 2,400 Units, Circ @ 500 Gpm's 2,940 Psi & 100 Rpm's, 12.3 ppg MW in, Mud on Balance Mud Scale Printed: 12/18/2002 10:55:48 AM .) ) ConocoPhillips Alaska Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 3S-09 3S-09 ROT - DRILLING N 1268 @ ppco.com Nabors 7ES Date Sub From - To Hours Code Code Phase 12/12/2002 19:30 - 21 :30 2.00 DRILL CIRC PROD 21 :30 - 22:30 1.00 DRILL DRLG PROD 22:30 - 23:30 1.00 DRILL CIRC PROD 23:30 - 00:00 0.50 DRILL DRLG PROD 12/13/2002 00:00 - 00:30 0.50 RIGMNT RGRP PROD 00:30 - 01 :30 1.00 RIGMNT RGRP PROD 01 :30 - 05:30 4.00 DRILL DRLG PROD 05:30 - 08:00 2.50 DRILL CIRC PROD 08:00 - 10:00 2.00 DRILL WIPR PROD 10:00 - 11 :30 1.50 DRILL WIPR PROD 11 :30 - 15:00 3.50 DRILL CIRC PROD 15:00 - 00:00 9.00 DRILL TRIP PROD 12/14/2002 00:00 - 02:00 2.00 DRILL TRIP PROD 02:00 - 02:30 0.50 DRILL CIRC PROD 02:30 - 04:30 2.00 DRILL TRIP PROD 04:30 - 05:30 1.00 DRILL TRIP PROD 05:30 - 09:30 4.00 DRILL TRIP PROD 09:30 - 10:00 0.50 DRILL TRIP PROD 10:00 - 12:00 2.00 CASE RURD PROD 12:00 - 19:00 7.00 CASE RUNC PROD 19:00 - 20:00 1.00 CASE CIRC PROD Page 5 of 7 Start: 12/4/2002 Rig Release: 12/17/2002 Rig Number: Spud Date: 12/4/2002 End: 12/17/2002 Group: Description of Operations Showed .5 Mud Cut at 2,400 Units, Gas Dropped Out in 2K Stks Back To an Ave BGG of 200 Units Drill 8 1/2" Hole F/9,232' to 9,330' MDI 5,822' TVD, ART 1 Hr, AST -0-, Est Top of KUP "C" Sand 9,284' MD/5,795', BGG up to 2,000 Units F/9,304' MD/5,807' TVD Circ Btms Up after Drilling Into Top of Kup, Max Gas was 2,000 Units F/9,304', Ave BGG Before 200 Units, After Btms Up gas Back Down to 200 Units, Mud Gas Cut .4 ppg from 12.3 ppg at 2,000 Units Gas, Circ at 500 Gpm's, 2,950 psi & 100 Rpm's, with 12.3 In & Out & 13.2 ECD, Drill 8 1/2" Hole F/9,330' to 9,371' MDI 5,846' TVD, ART 1 Hr, AST -0-, 10-15K WOB, 500 Gpm's, 3,150 Psi, 100 Rpm's, Rot WT, 143K, PU Wt 235K, Dn Wt, 102K, Off Btm torque, 15-16,000 Ft#'s, On Btm 16-18,000 Ft#'s, ECD Ave 13.3 ppg, BGG Ave 220 Units, Base of KUP "C" Sand @ 9,353' MD/5,836' TVD SCR's Went Down & Lost Rig Power, Re-established Power, Had Problem with Clean Power Invertor Est Circ & Worked Pipe While Trouble Shooting SCR's and Getting PVT System Back on Line, Circ @ 500 Gpm's @ 3,000 psi & 100 Rpm's Drilled 8 1/2" hole F/9,371, to 9,650' MDI 6,020' TVD, 7" Csg Point, ART 3.25 Hrs, 15-20K WOB, 115 Rpm's, 500 Gpm's @ 3,150 psi, ROT Wt 144K, PU Wt 215K, Dn WT 110K, 15K Torque Off Btm, 17K On Btm, Ave BGG 200 Units Pump 40 bbl High Vis Sweep & Circ Out, Circ Hole Clean, Rotated @ 120 Rpm's & Reciprocated Pipe, Pumped 1,590 bbls (3.4 x Annulus Volumes) at 500 Gpm's @ 3,025 psi, ECD 13.3, BGG 200 Units, Monitored Well POOH to 7,782' with No Problems RIH to 9,555' with No Problems, Did not have to pump or backream on wiper trip Est Circ, Washed 95' to Btm @ 9,650', Circ & Cond Mud for 7" Csg, Max Gas on Btms up 960 Units. Began POOH to Run 7" Csg, Pulled 35K Over at 5,782', MU Top Drive & Backreamed Out From 5,782' to 5,587' @ 500 Gpm's @ 2,450 psi & 100 Rpm's, Cont POOH, Pulled 25K Over @ 3,742', MU Top Drive to Backream Out at Report Time. Backreamed out of Hole from 3,742' to 3,510', Circ @ 510 Gpm's, 2,300 PSi @ 100 Rpm's, Pulled Bit Up Into 9 5/8" Csg RIH to 3,687' & Circ Hole, @ 535 Gpm's @ 2,500 Psi & 120 Rpm's, Had Good Amount of Cuttings Back, Circ Hole Clean, POOH 2 Stds to 3,490', Monitored Well @ Shoe-Static, Pumped Dry Job & POOH to BHA Monitored Well @ BHA, Stood Back HWDP & Changed Out Drlg Jars LD Flex Dc's, Removed Nuclear Sources, Downloaded MWD/LWD & LD BHA & 81/2" Bit Pulled Wear Bushing & Cleared Rig Floor RU Nabor Csg Equipment Along with GBR Fill-up Tool, Changed Out Elevator Bails, Held Pre-Job Safety Mtg. MU 7" Float Shoe, 4 Jts of 7" 26# L-80 BTC Mod Csg, Float Collar, Tested Float Equip, Thread Locked Btm 5 Conn, RIH with 83 Jts 7" Csg to 3,500', PU Wt 90K, SIO 40K Circ Btms Up @ Shoe, Init Rate 3 Bpm @ 615 Psi, Final Rate 7 Bpm @ 715 Psi, PU Wt 95 K, SIO 60K Printed: 12/18/2002 10:55:48 AM ) ) ConocoPhillips Alaska Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 38-09 38-09 ROT - DRILLING N 1268 @ ppco.com Nabors 7ES Date 8ub From - To Hours Code Code Phase 12/14/2002 20:00 - 23:00 3.00 CASE RUNC PROD 23:00 - 23:30 0.50 CASE CIRC PROD 23:30 - 00:00 0.50 CASE RUNC PROD 12/15/2002 00:00 - 02:00 2.00 CASE RUNC PROD 02:00 - 03:00 1.00 CASE CIRC PROD 03:00 - 06:30 3.50 CASE RUNC PROD 06:30 - 07:00 07:00 - 11 :00 0.50 CASE RURD PROD 4.00 CEMENTCIRC PROD 11 :00 - 13:30 2.50 CEMENT PUMP PROD 13:30 - 15:30 15:30 - 16:45 16:45 - 17:30 17:30 - 18:30 2.00 CASE RURD PROD 1.25 CASE DEQT PROD 0.75 CMPL TN RURD CMPL TN 1.00 CMPL TN PULD CMPL TN 18:30 - 00:00 5.50 CMPL TN RUNT CMPL TN 12/16/2002 00:00 - 04:00 4.00 CMPL TN RUNT CMPL TN 04:00 - 05:30 1.50 CMPL TN DEQT CMPL TN 05:30 - 07:00 1.50 CMPL TN PCKR CMPL TN Page 6 of 7 Start: 12/4/2002 Rig Release: 12/17/2002 Rig Number: Spud Date: 12/4/2002 End: 12/17/2002 Group: Description of Operations Cont RIH with 7" Csg, RIH with 49 Add Jts (132 Total) to 5,510' with Full Returns, PU Wt 120K, SIO 60K, Ave MU Torque 7,600 Ft#'s to Base of Diamond Circ Btms Up, Final rate 6 Bpm @ 690 Psi, Up Wt140K, SIO 82K, Ave 82 Units BGG, Very Few Cuttings on Btms Up Cont RIH with 7" Csg to 5,800' with No Problems and Good Returns RIH with 44 Jts of 7",26#, L-80 BTC Mod Csg (176 Jts Total) to 7,300' lost 10k SOW in last 10 jts ran - PU Wt 175K, SIO Wt 75k Circ Btms Up, Initial rate 3.0 bpm @ 687 psi -Final Rate 6 Bpm @ 830 Psi, Had Very Little Cuttings Back, mwt in 12.3 mwt out 12.6 - 12.3 ppg. Ave BGG 110 Units, PU Wt 185K, SIO Wt 90K Fin RIH with 7" Csg, Ran a Total of 231 Jts of 7" 26#, L-80 BTC-Mod, Landed Csg in Hanger with Float Shoe @ 9,638' and Float Collar @ 9,469', Ran Bow Spring Centralizers, Straight Blade's and Centralizing Guides per Well Plan, No Problems RIH and Had Full Returns Final PU Wt, 275K, SIO Wt 88K Gt # 230) RD GBR's Fill-up Tool & MU Cement Head, Blew Down Top Drive Circ & Cond Mud for Cementing, Init Circ Rate 1.5 bpm @ 800 psi, staged up to 5.5 bpm, Init Press 1,160 Psi, Final Press 775 Psi, Attempted to Reciprocate after Est Circ, Worked Pipe Up to 375K with No Movement, Relanded Csg In Hanger, 410 Units Gas @ Btms Up, Circ & cond mud Lowered YP from 40 to 19, FV from 154 to 49, maintained 12.3 ppg mud wt in. Full returns throughout. PJSM Line up to cementers - pumped 2 bbls of FW and tested lines to 3500 psi. Pumped 10 bbls of CW 100, dropped btm plug - reload cmt head wI btm I top plugs. Pumped 40 bbls of 13.3 ppg MudPush XL, dropped 2nd btm plug- pumped 63 bbls of 15.8 ppg G wI adds - flushed cement line to head - drop top plug and displaced cement with 361 bbls of seawater @ 6 bpm 180-1203 psi -reduced rate to 3 bpm 1180 - 1588 psi with tail slurry at shoe bumped plugs to 2650 psi - floats held - full returns throughout - CIP @ 1320 hrs. Bled back 3.5 bbls. LD cement head - flush stack - RD casing tools - LD landing joint. Install and test packoff 250/5000 psi. PJSM. Ru to run 31/2" tubing. MU 3 1/2" completion equipment: WLEG wI shear out sub I pup- Camco "d" nipple wI 2.75" no go - 2 pups - xo 3.5" X 4.5" - Mill out ext - Baker SAB-3 packer - KBH-22 Tubing anchor - Baker 80-40 PBR - Locator sub - pup - 1 jt 31/2",9.3#, L-80 tbg - Camco "DS" nipple wI 2.813 profile - 1 jt tubing - pup - Camco MMG wI DCR shear valve - pup ,"Þ RIH with Completion equipment - 4613' (145 jts) run @ midnight. PUW 65K SOW 48K. RIH wI Completion string (283 Jts total). PU jt #284 to put packer on depth. RU circ head and line - pressure test 7" casing to 3500 psi, bled to 3470 psi in 30 min. Drop ball - Mu pump in sub - position packer to depth on down stroke - pumped ball down 1.5 bpm @ 82 psi. Pressure tubing to 2500 psi for 5 min, no loss, increase pressure to 3000 psi, hold 5 min. Increase pressure to shear out ball seat - surface indication seen @ 3450 psi, bleed off pressure. PU to shear PBR, pipe free (PBR sheared). Set down 25k on packer, pressure up tubing to 3800 psi, no additional shear observed. Printed: 12/18/2002 10:55:48 AM ) ') Page 7 of 7 ConocoPhillips Alaska Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 3S-09 3S-09 ROT - DRILLING N1268@ppco.com Nabors 7ES Date Sub From - To Hours Code Code Phase 12/16/2002 07:00 - 08:00 1.00 CMPL TN SOHO CMPL TN 08:00 - 10:00 2.00 CMPL TN DEQT CMPL TN 10:00 - 15:00 5.00 CMPL TN NUND CMPL TN 15:00 - 16:30 1.50 CMPL TN SEQT CMPL TN 16:30 - 17:30 1.00 CMPL TN FRZP CMPL TN 17:30 - 18:00 0.50 RIGMNT RGRP CMPL TN 18:00 - 22:00 4.00 CMPL TN OTHR CMPL TN 22:00 - 23:00 1.00 CMPL TN OTHR CMPL TN 23:00 - 00:00 1.00 CMPL TN FRZP CMPL TN 12/1 7/2002 00:00 - 03:30 3.50 CMPL TN FRZP CMPL TN 03:30 - 04:00 0.50 RIGMNT RSRV CMPL TN 04:00 - 06:00 2.00 CMPL TN RURD MOVE Start: 12/4/2002 Rig Release: 12/17/2002 Rig Number: Spud Date: 12/4/2002 End: 12/17/2002 Group: Description of Operations RD pump in sub, lay down Jt # 184 and pup - MU hanger and LJ, land tubing with WLEG @ 8965', top of Pkr @ 8933', locator sub 2" above PBR. RU and tesat tubing to 3520 psi, bled to 3510 in 15 min. bleed off tubing to 1500 psi, pressure up Annulus to 3500 psi, bled to 3480 psi in 15 min. Bled tubing off and sheared RP valve in GLM. RD pump in hose, LD LJ, blow down lines. Install TWC. NO BOPE, NU adaptor flange and tree. Test adaptor flange and tree to 5000 psi for 10 min. RU and pull TWC. RU lines to wellhead to freeze protect Tubing and 3 1/2" X 7" annulus. Prepare to lay down drill pipe. Repair electronic safety sensor on pipe skate. Lay down 75 joints of 5" drill pipe from derrick. Pumped 140 bbls of diesel to diplace tubing to RP valve and Freeze protect annulus to 1850' tvd. RU lubricator and install BPV, RD lubricator and install plug and cap on tree. RU and attempt to perform LOT down 9 5/8" X 7" annulus, pressure up to 750 psi with very slight bleed off. Cont to Attempt Injectivity Test, Press up to 900 Psi, Cont to Roll Pump holding 900 Psi with No Success, Bled Off Press, RU Little Red & Cont to Pump on Annulus with Diesel Slip & Cut 130' of Drlg Line Shut Down Little Red & Bled Press from Well, Moved Out Injection Skid, Ball Mill, Inj Diesel tank & Rig Fuel Storage Tank While Attempting to Inject, Fin Cleaning Mud Pits& Preparing for Rig Move RELEASED RIG @ 06:00 Hrs 12/17/02 Printed: 12/18/2002 10:55:48 AM Date 12/21/02 12/22/02 12/23/02 12/24/02 12/25/02 ') 35-09 Event History ) Comment REPLACED SHEARED SOV WI DV @ 8832' RKB, PT IIA TO 3000#, UNABLE TO SHEAR BAKER PUMP OUT SUB @ 8964' RKB, IN PROGRESS [GLV, PT TBG-CSG] SHEARED BAKER SUB @ 8964' RKB,TAGGED FILL @ 9430' RKB, PT TBG TO 3000# HELD DRIFTED TBG WI 24' OF 2.65" DUMMY GUN'S [TAG, PT TBG-CSG] SLlMHOLE CEMENT MAPPING COMPLETED FROM 9430' ELM TO 8900' ELM AT 1700 PSI WELLBORE PRESSURE AND 3000 PSI WELLBORE PRESSURE WI REPEAT PASSES - LOGGED JEWELRY LOG WHILE POOH - GOOD CEMENT LOGGED FROM 9248' - 9256' ELM (8') [MIT] RIH WI 30 FT 2506PJ 6SPJ 60DEG PHASED PERF GUN. PRESSURE UP WHP TO 100 PSI FOR UNDERBALNCED PERFORATING. FIRE GUNS, INTERVAL SHOT 9302-9232 FT, POOH 0 PSI WHP WHEN GUNS ARRIVE AT SURF. RIH FOR PRESSURE TEMP LOG - TAKE STOP COUNTS AT 9318' (BHP= 3500.9) PERF. WI 2.5" HSD, PJ GUNS. SHOT 20 FT AND 18 FT. INTERVALS: 9332-9352' AND 9284-9302'. LOG POST PERF. STATIC BHPrT @ 9318' @ 3502 PSI AND 9118' @ 3450 PSI. POOH, RDMO, NOTIFIED DSO OF STATUS. WELL READY TO BRING ON. Page 1 of 1 1n/2003 ) AOGCC Lori Taylor 3010 Porcupine Drive Anchorage, AK 99501 DEFINITIVE Re: Distribution of Survey Data for Well 3S-09 Dear Lori Taylor Enclosed are two survey hard copies and one disk Tie-on Survey: Window / Kickoff Survey Projected Survey: ) 26-Dec-02 0.00' MD 0.00' M D (if applicable) 9,650.00' MD Please call me at 273-3545 if you have any questions or concerns. Regards, William T. Allen Survey Manager Attachment(s) RECEIVED JAN o. 3 00t.7\ l...JV.., AIa8ka OJ & Gal Coni. Commie8ion ~ élOd-¿)D5 Sperry-Sun Drilling Services Western North Slope ConocoPhillips Kuparuk 35 Pad 35-09 Job No. AKMW22193, Surveyed: 13 December, 2002 Survey Report 27 December, 2002 Your Ref: 501032043200 Surface Coordinates: 5993919.05 N, 476285.95 E (70023' 40.2623" N, 150011'34.6042" W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 Surface Coordinates relative to Project H Reference: 993919.05 N, 23714.05 W (Grid) Surface Coordinates relative to Structure: 75.51 N, 169.29 W (True) Kelly Bushing: 56.5Oft above Mean Sea Level Elevation relative to Project V Reference: 56. 50ft Elevation relative to Structure: 0.40ft 5pe,-,,-,y-!5u,, DRILL.ING SERVices A Halliburton Company DEFNTIVE ~ .,--", Survey Ref: svy10003 Sperry-Sun Drilling Services Survey Report for Kuparuk 3S Pad - 3S-09 Your Ref: 501032043200 Job No. AKMW22193, Surveyed: 13 December, 2002 ConocoPhillips Western North Slope Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) 0.00 0.000 0.000 -56.50 0.00 0.00 N O.OOE 5993919.05 N 476285.95 E 0.00 MWD Magnetic 110.00 0.600 16.100 53.50 110.00 0.55N 0.16 E 5993919.60 N 476286.11 E 0.545 0.52 198.23 1.310 16.100 141.72 198.22 1.97 N 0.57 E 5993921.01 N 476286.52 E 0.805 1.84 290.32 3.540 30.520 233.72 290.22 5.43 N 2.30 E 5993924.47 N 476288.27 E 2.492 5.58 379.89 5.590 34.880 323.00 379.50 11.39 N 6.20E 5993930.42 N 476292.19 E 2.320 12.62 470.38 5.910 40.400 413.03 469.53 18.55 N 11.74 E 5993937.56 N 476297.75 E 0.706 21.66 .~. 557.23 7.020 42.110 499.33 555.83 25.89 N 18.20 E 5993944.89 N 476304.23 E 1.297 31.43 654.34 9.070 42.210 595.48 651.98 35.97 N 27.32 E 5993954.93 N 476313.39 E 2.111 45.02 745.15 9.250 42.320 685.13 741.63 46.67 N 37.05 E 5993965.60 N 476323.14 E 0.199 59.48 834.24 11 . 140 42.100 772.81 829.31 58.35 N 47.64 E 5993977.25 N 476333.77 E 2.122 75.25 927.32 13.120 45.810 863.81 920.31 72.38 N 61.24 E 5993991.24 N 476347.42 E 2.285 94.78 1023.74 16.020 43.410 957.12 1013.62 89.68 N 78.24 E 5994008.48 N 476364.47 E 3.072 119.00 1122.44 20.470 42.910 1050.83 1107.33 112.23 N 99.36 E 5994030.96 N 476385.66 E 4.511 149.89 1213.95 23.680 42.910 1135.63 1192.13 137.41 N 122.77 E 5994056.07 N 476409.15 E 3.508 184.27 1308.74 27.200 41.580 1221.21 1277.71 167.57 N 150.11 E 5994086.14 N 476436.60 E 3.762 224.97 1403.46 31.710 42.450 1303.67 1360.17 202.15 N 181.30 E 5994120.62 N 476467.89 E 4.783 271.54 1498.05 35.570 42.950 1382.40 1438.90 240.64 N 216.84 E 5994159.00 N 476503.55 E 4.091 323.92 1593.41 38.970 43.080 1458.28 1514.78 282.86 N 256.23 E 5994201.09 N 476543.07 E 3.566 381.65 1688.02 41.920 42.580 1530.27 1586.77 327.87 N 297.94 E 5994245.97 N 476584.93 E 3.137 443.01 1782.23 49.470 40.700 1596.03 1652.53 378.26 N 342.65 E 5994296.22 N 476629.80 E 8.140 510.37 1880.64 51.500 41.970 1658.64 1715.14 435.25 N 392.79 E 5994353.05 N 476680.12 E 2.290 586.28 1975.99 54.820 43.570 1715.81 1772.31 491.24 N 444.62 E 5994408.88 N 476732.13 E 3.732 662.57 2071.34 55.100 43.380 1770.55 1827.05 547.90 N 498.33 E 5994465.36 N 476786.02 E 0.336 740.60 2166.54 56.570 43.280 1824.01 1880.51 605.19 N 552.38 E 5994522.49 N 476840.25 E 1.547 819.34 .~ 2261.41 56.530 42.710 1876.31 1932.81 663.09 N 606.36 E 5994580.21 N 476894.41 E 0.503 898.48 2359.73 56.780 41.160 1930.35 1986.85 724.19 N 661.25 E 5994641.14 N 476949.49 E 1.341 980.61 2451.26 57.970 40.720 1979.70 2036.20 782.42 N 711.76 E 5994699.21 N 477000.19 E 1.362 1057.69 2546.25 57.870 42.030 2030.15 2086.65 842.81 N 764.96 E 5994759.43 N 477053.58 E 1.173 1138.17 2641.87 58.550 41.720 2080.53 2137.03 903.33 N 819.21 E 5994819.78 N 477108.02 E 0.763 1219.44 2740.88 58.960 41.200 2131.88 2188.38 966.77 N 875.25 E 5994883.04 N 477164.27 E 0.611 1304.09 2831.91 56.910 40.290 2180.21 2236.71 1025.21 N 925.61 E 5994941.31 N 477214.80 E 2.406 1381.22 2926.41 56.590 38.130 2232.02 2288.52 1086.43 N 975.56 E 5995002.38 N 477264.95 E 1.941 1460.15 3022.24 56.040 39.140 2285.17 2341.67 1148.72 N 1025.35 E 5995064.51 N 477314.93 E 1.048 1539.77 3118.09 57.930 39.280 2337.40 2393.90 1210.99 N 1076.15 E 5995126.62 N 477365.94 E 1.976 1620.06 3212.46 58.450 37.710 2387.14 2443.64 1273.76 N 1126.07 E 5995189.23 N 477416.05 E 1.517 1700.11 27 December, 2002 - 8:49 Page 20f5 DrillQuest 3.03.02.004 Sperry-Sun Drilling Services Survey Report for Kuparuk 3S Pad - 3S-09 Your Ref: 501032043200 Job No. AKMW22193, Surveyed: 13 December, 2002 ConocoPhillips Western North Slope Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings .Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) ,(ft) (ft) (ft) (O/100ft) 3307.41 58.510 38.660 2436.78 2493.28 1337.38 N 1176.10 E 5995252.69 N 477466.29 E 0.855 1780.89 3402.04 58.550 39.190 2486.18 2542.68 1400.17 N 1226.81 E 5995315.32 N 477517.20 E 0.480 1861.50 3521.70 58.740 36.890 2548.45 2604.95 1480.64 N 1289.77 E 5995395.59 N 477580.41 E 1.649 1963.45 3616.90 58.020 37.300 2598.37 2654.87 1545.30 N 1338.67 E 5995460.10 N 477629.51 E 0.841 2044.24 3712.39 57.440 40.250 2649.36 2705.86 1608.24 N 1389.22 E 5995522.88 N 477680.26 E 2.682 2124.85 3808.06 56.770 42.020 2701.32 2757.82 1668.74 N 1442.05 E 5995583.21 N 477733.29 E 1.704 2205.17 '~ 3903.43 56.170 41.680 2754.00 2810.50 1727.96 N 1495.10 E 5995642.26 N 477786.52 E 0.696 2284.67 3999.41 55.420 40.540 2807.95 2864.45 1787.76 N 1547.29 E 5995701.90 N 477838.90 E 1.255 2364.04 4094.05 56.860 44.580 2860.70 2917.20 1845.61 N 1600.44 E 5995759.58 N 477892.24 E 3.857 2442.59 4189.79 56.710 43.800 2913.14 2969.64 1903.05 N 1656.27 E 5995816.83 N 477948.25 E 0.699 2522.62 4284.99 58.800 46.680 2963.94 3020.44 1959.71 N 1713.45 E 5995873.32 N 478005.61 E 3.371 2602.98 4380.30 59.460 45.350 3012.84 3069.34 2016.53 N 1772.31 E 5995929.94 N 478064.64 E 1.384 2684.56 4475.88 58.910 45.850 3061.81 3118.31 2073.96 N 1830.95 E 5995987.19 N 478123.47 E 0.730 2766.47 4569.74 58.380 45.650 3110.65 3167.15 2129.89 N 1888.37 E 5996042.94 N 478181.06 E 0.593 2846.43 4665.80 57.880 45.260 3161.37 3217.87 2187.11 N 1946.51 E 5996099.98 N 478239.39 E 0.624 2927.85 4761.56 57.520 45.050 3212.53 3269.03 2244.19 N 2003.90 E 5996156.87 N 478296.96 E 0.419 3008.65 4855.17 57.210 44.190 3263.02 3319.52 2300.30 N 2059.27 E 5996212.81 N 478352.51 E 0.842 3087.39 4950.55 56.780 44.550 3314.97 3371.47 .2357.48 N 2115.20 E 5996269.81 N 478408.62 E 0.551 3167.30 5046.18 56.410 45.200 3367.62 3424.12 2414.05 N 2171.53 E 5996326.20 N 478465.13 E 0.687 3247.01 5140.88 56.560 43.420 3419.91 3476.41 2470.55 N 2226.68 E 5996382.52 N 478520.45 E 1.575 3325.89 5236.07 56.100 43.800 3472.69 3529.19 2527.91 N 2281.32 E 5996439.71 N 478575.28 E 0.586 3405.07 5331.50 57.350 38.660 3525.07 3581.57 2587.89 N 2333.86 E 5996499.53 N 478628.00 E 4.689 3484.81 5426.32 57.310 37.640 3576.26 3632.76 2650.66 N 2383.16 E 5996562.14 N 478677.51 E 0.907 3564.46 5522.11 56.480 38.220 3628.57 3685.07 2713.95 N 2432.48 E 5996625.27 N 478727.03 E 1.004 3644.52 ~ 5617.36 56.270 40.380 3681.32 3737.82 2775.32 N 2482.71 E 5996686.48 N 478777.45 E 1.901 3723.74 5712.40 55.980 39.910 3734.30 3790.80 2835.64 N 2533.58 E 5996746.64 N 478828.52 E 0.512 3802.62 5808.13 55.560 39.160 3788.15 3844.65 2896.68 N 2583.97 E 5996807.52 N 478879.09 E 0.782 3881.70 5902.54 55.070 39.920 3841.87 3898.37 2956.55 N 2633.39 E 5996867.23 N 478928.70 E 0.841 3959.27 5998.19 54.930 38.470 3896.74 3953.24 3017.27 N 2682.90 E 5996927.79 N 478978.41 E 1.250 4037.54 6092.04 55.890 40.390 3950.02 4006.52 3076.94 N 2731.97 E 5996987.30 N 479027.67 E 1.970 4114.72 6188.18 55.340 40.650 4004.31 4060.81 3137.25 N 2783.52 E 5997047.45 N 479079.41 E 0.614 4194.04 6284.17 55.000 40.190 4059.14 4115.64 3197.23 N 2834.61 E 5997107.28 N 479130.69 E 0.529 4272.81 6379.78 54.390 40.750 4114.39 4170.89 3256.59 N 2885.25 E 5997166.47 N 479181.52 E 0.797 4350.82 6475.79 56.700 41.260 4168.71 4225.21 3316.33 N 2937.19 E 5997226.04 N 479233.65 E 2.446 4429.97 6571.29 56.170 41.490 4221.51 4278.01 3376.04 N 2989.79 E 5997285.59 N 479286.44 E 0.590 4509.54 27 December, 2002 - 8:49 Page 3 of5 DrillQuest 3.03.02.004 Sperry-Sun Drilling Services Survey Report for Kuparuk 3S Pad. 3S-09 Your Ref: 501032043200 Job No. AKMW22193, Surveyed: 13 December, 2002 ConocoPhillips Western North Slope Measured Sub-Sea Vertical local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (°/1 OOft) 6665.82 55.460 40.820 4274.62 4331.12 3434.92 N 3041.25 E 5997344.30 N 479338.09 E 0.953 4587.74 6761.33 57.500 43.110 4327.37 4383.87 3494.10 N 3094.50 E 5997403.32 N 479391.52 E 2.925 4667.35 6855.89 57.270 43.230 4378.33 4434.83 3552.19 N 3149.00 E 5997461.23 N 479446.20 E 0.266 4746.98 6949.30 56.430 44.470 4429.41 4485.91 3608.59 N 3203.17 E 5997517.46 N 479500.55 E 1 .430 4825.13 7045.38 55.660 43.640 4483.08 4539.58 3665.86 N 3258.59 E 5997574.56 N 479556.15 E 1.075 4904.76 7142.18 57.380 43.510 4536.48 4592.98 3724.36 N 3314.24 E 5997632.87 N 479611.99 E 1.780 4985.46 ,-",,' 7236.72 57.270 43.530 4587.52 4644.02 3782.06 N 3369.04 E 5997690.40 N 479666.97 E 0.118 5065.01 7332.10 56.550 43.160 4639.59 4696.09 3840.17 N 3423.89 E 5997748.34 N 479722.00 E 0.822 5144.89 7425.99 55.750 43.110 4691.89 4748.39 3897.08 N 3477.20 E 5997805.07 N 479775.50 E 0.853 5222.84 7521.75 55.200 43.140 4746.16 4802.66 3954.66 N 3531.13 E 5997862.49 N 479829.61 E 0.575 5301.72 7617.34 54.520 43.220 4801.18 4857.68 4011.66 N 3584.62 E 5997919.32 N 479883.28 E 0.715 5379.86 7712.45 55.580 43.630 4855.66 4912.16 4068.27 N 3638.21 E 5997975.76 N 479937.05 E 1.169 5457.79 7807.28 55.790 42.920 4909.12 4965.62 4125.30 N 3691.90 E 5998032.62 N 479990.92 E 0.657 5536.09 7903.65 54.850 43.570 4963.96 5020.46 4183.03 N 3746.19 E 5998090.17 N 480045.39 E 1.122 5615.31 7999.22 56.190 44.580 5018.06 5074.56 4239.62 N 3800.99 E 5998146.59 N 480100.38 E 1.651 5694.02 8094.13 56.710 45.530 5070.52 5127.02 4295.50. N 3856.98 E 5998202.29 N 480156.54 E 0.998 5772.99 8188.21 55.960 45.090 5122.67 5179.17 4350.56 N 3912.65 E 5998257.18 N 480212.38 E 0.887 5851.15 8282.21 56.710 44.230 5174.78 5231.28 4406.21 N 3967.64 E 5998312.65 N 480267.54 E 1.103 5929.29 8377.94 58.030 41.800 5226.40 5282.90 4465.16 N 4022.62 E 5998371.42 N 480322.71 E 2.544 6009.88 8473.04 57.680 41 .590 5277.00 5333.50 4525.28 N 4076.18 E 5998431.38 N 480376.46 E 0.413 6090.40 8566.86 56.990 41 .270 5327.63 5384.13 4584.50 N 4128.44 E 5998490.43 N 480428.91 E 0.790 6169.38 8662.48 56.430 41.300 5380.12 5436.62 4644.56 N 4181.18E 5998550.32 N 480481.84 E 0.586 6249.31 8758.33 55.820 41 .440 5433.54 5490.04 4704.28 N 4233.77 E 5998609.88 N 480534.62 E 0.648 6328.88 8853.99 55.210 40.820 5487.70 5544.20 4763.67 N 4285.64 E 5998669.10 N 480586.68 E 0.832 6407.73 .~ 8948.48 54.790 40.760 5541.90 5598.40 4822.27 N 4336.20 E 5998727.54 N 480637.43 E 0.448 6485.12 9043.56 54.360 41.370 5597.01 5653.51 4880.69 N "4387.10 E 5998785.80 N 480688.51 E 0.691 6562.59 9139.08 53.980 41.750 5652.93 5709.43 4938.64 N 4438.48 E 5998843.58 N 480740.07 E 0.512 6640.03 9235.07 53.790 42.280 5709.51 5766.01 4996.25 N 4490.38 E 5998901.03 N 480792.15 E 0.488 6717.57 9328.63 53.190 42.730 5765.17 5821.67 5051.69 N 4541.18 E 5998956.31 N 480843.14 E 0.749 6792.77 9422.63 52.490 41.970 5821.95 5878.45 5107.05 N 4591.65 E 5999011.51 N 480893.78 E 0.985 6867.67 9518.27 51.610 41 .430 5880.77 5937.27 5163.36 N 4641.82 E 5999067.66 N 480944.13 E 1.022 6943.09 9579.93 51.000 41 .160 5919.32 5975.82 5199.51 N 4673.58 E 5999103.71 N 480976.00 E 1.047 6991.21 9650.00 51.000 41.160 5963.41 6019.91 5240.51 N 4709.42 E 5999144.60 N 481011.97 E 0.000 7045.66 Projected Survey 27 December, 2002 - 8:49 Page 40f5 DrillQuest 3.03.02.004 Sperry-Sun Drilling Services . Survey Report for Kuparuk 3S Pad - 3S-09 Your Ref: 501032043200 Job No. AKMW22193, Surveyed: 13 December, 2002 Western North Slope ConocoPhil/ips All data is in Feet (US) unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to RKB = 56.5' MSL. Northings and Eastings are relative to 2491' FNL, 974' FEL. Global Northings and Eastings are relative to NAD27 Alaska State Planes, Zone 4. The Dogleg Severity is in Degrees per 100 feet (US). Vertical Section is from 2491' FNL, 974' FEL and calculated along an Azimuth of 41.820° (True). Magnetic Declination at Surface is 25.2600(03-Dec-02) Based upon Minimum Curvature type calculations, at a Measured Depth of 9650.00ft., The Bottom Hole Displacement is 7045.68ft., in the Direction of 41.945° (True). ,,--,,' Comments Measured Depth (ft) Station Coordinates TVD Northings Eastings (ft) (ft) (ft) Comment 9650.00 6019.91 5240.51 N 4709.42 E Projected Survey Survey tool program for 35-09 Fro m Measured Vertical Depth Depth (ft) (ft) To Measured Vertical Depth Depth (ft) (ft) Survey Tool Description ~ 0.00 0.00 9650.00 6019.91 MWD Magnetic 27 December, 2002 - 8:49 Page 50f5 Dri//Quest 3.03.02.004 SeblulDbepgep Schlumberger Technology Corporation, by and through is Geoquest Division 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 A TTN: Beth Well Job# Log Description Date 1C-119 35-09 2K-13 aOI" 13q ~O:;> .. ~ '3 /~c¡ - 09~ 04/15/02 12/25/02 12/19/02 PRE5SITEMP LOG 5BHP/T (POST PERF) INJECTION PROFILE SIGNED~'(JOOor~ DATE: NO. 2635 12/31/02 Company: Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: BL Sepia 1 1 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. Kuparuk CD Color ~- ~ RECE\VED JAN 1 0 2.003 Ala.! <Xi & Gas Cons. eommiSlian Ancborage [Fwd: 3S-09] ) ') Subject: [Fwd: 3S-09] Date: Fri, 13 Dee 2002 15:20:07 -0900 From: Tom Maunder <tom_maunder@admin.state.akus> To: Winton GAubert <winton_aubert@admin.state.akus> Winton, I believe this is for you. Tom Subject: 3S-09 Date: Fri, 13 Dee 2002 15: 17 :29 -0900 From: " Sharon Allsup-Drake" <Sharon.K.Allsup-Drake@eonoeophillips.eom> To: Tom Maunder <tom_maunder@admin.state.akus> Tom - we are currently drilling this well 3S-09 and we permitted it injector. We would like to pre-produce this well from one to What do we need to do to notify AOGCC of our intentions? It permanent conversion. for an four months. is not a Thanks, Sharon work: (907) 263 -4612 fax: ( 90 7 ) 265 - 6224 office ATO-1530 sallsup@ppco.com ,'--.".-'.'--- -- ----... -- ._'~'---- ._---~- ----- - "-- ... ."- -- --- --. --_._._~_. ~ u.....------. -.. "-" -"- .'n_- --- .... --" -----.- ._---_.~ .-' Tom J\'iaundê!' <tom_mallnderr~~'admin.state.ak.lIs> ¡ Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 11'-, ., ) ~~~~ If b TONY KNOWLES, GOVERNOR ~ ~~ 1A\ 1T Œ (ill 333 W. "]TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 A.ItA.~1iA OIL AlQ) GAS CONSERVATION COMMISSION December 6, 2002 Daniel E. Hensley Palm Surveillance Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage AK 99510-0360 Re: Request for variance from 20 AAC 25.412 (b), packer setting depth requirement in Drill Site 3S (Palm) injection wells. Dear Mr. Hensley: ConocoPhillips Alaska, Inc. ("CPA"), by letter dated November 18, 2002, requested that packers in Drill Site 3S (Palm) injection wells be set up to 350 feet measured depth above the injection formation top (the Kuparuk). CP A also proposes to cement these injection wells' seven inch casing annuli to a height above the packer setting depth. The Kuparuk is overlain by multiple thick shale and claystone confining intervals, includ- ing the Lower Kalubik, Upper Kalubik, and HRZ. The Alaska Oil and Gas Conservation Commission ("Commission") finds that CPA's proposed injection well packer setting depth is within the shale/claystone sequence above the Kuparuk reservoir. The Commis- sion further finds that increasing the height of the seven inch casing cement columns in these wells provides security against annulus leak paths above the packer setting depth. Accordingly, the Commission hereby approves a variance from 20 AAC 25.412 (b), al- lowing the packer in injection well 3S-09 to be set up to 350 feet measured depth above the injection interval. Sincerely, ~?'~ Michael L. Bill Commissioner WA\MLB\jjc ,~~ .'. ) ) ~ y ConocoPhillips November 18, 2002 REC E IV ED NOV22 '2002 Alaska Oil and Gas Conservation Commission Cammy Taylor, Chair 333 W. 7th Ave Suite 100 Anchorage, AK 99501 Alaska Oil & Gas Oons. Commission . Anchor-age Attention: Commissioner Seamount Subject: A request for a variance in packer setting depth for Drill Site 3S (Palm) z--o ~- t.-o { injectors under AAC 25.412 (b) Dear Commissioner Taylor: With this letter, ConocoPhillips Alaska requests a Drill Site 3S (Palm) variance in the 200 feet measured depth limit between the packer and the formation top specified in statewide AOGCC regulations. Specifically, we request that CPA be permitted to set injector packers up to 350 feet measured depth above the formation top in Drill Site 38 (Palm) injection wells. The following discussion is provided to support this request: 20 AAC 25.412 (b) states:". . . The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves ,a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone." In the Drill Site 3S (Palm) development area, the Kuparuk formation is found between 5700 and 5900 feet vertical depth. Overlying the Kuparuk is the Lower Kalubik, Upper Kalubik, and HRZ confining intervals which are thick sequences of shales and claystones with no known reservoir potential. . The Drill Site 3S (Palm) injection wells are planned with a 7" long/production string with 3.5" tubing. To maintain the regulation of 200 feet measured depth maximum spacing between packer depth and formation top, the injector packer setting depth is planned for 100 feet measured depth above the anticipated top of formation. With this configuration, the available logging interval between the tubing tail (approximately 30 feet below the packer setting depth) and formation top would be limited to- 70 feet measured depth; therefore on previous wells, CPA has chosen to petfonn a cement bond log on the drilling rig prior to running the 3.5" tubing completion. In an effort to lower the development program drilling costs, we are requesting that CPA be pennitted to set injector packers up to 350 feet measured depth above the fonnation top. With a longer interval in which tQ illustrate a hydraulic barrier exists behind the 7" casing, it becomes practical to run the cement bond logs after the drilling rig runs the completion and moves off of the well. It 1 is also proposed to plan the cement top in the 7" annulus to be raised by an equal distance ./ i ..,. ..,-. (250 feet) in order to maintain the same interval of cemented 7" annulus above the packer and therefore the same level of security against an annulus leak path behind the 7" (around and above the packer). . The first well on which CPA proposes to apply a 350 feet measured depth rule is injection weIl3S-09. Nabors 7ES is scheduled to spud this injector on December 07, 2002. 3S-09will be used as the example for this concept. The planned completion strategy of 3S-09 is essentially analogous to all planned completions for Drill Site 3S (Palm) injectors. Please refer to the attached well bore diagram. Illustrating the application of a 350 feet measured depth rule inthe 38-09 injection well, the packer would most likel y be placed at a measured depth of 8903 to 9003 feet. The prognosed top for the Kuparuk formation in 3S-09 is 9253 feet measured depth (5734 feet vertical depth). The top of cement will be designed at 8203 feet measured depth, 1050 feet measured depth above the top of the Kuparuk target interval. The formation top for the Lower Kalubik, Upper Kalubik, and HRZ intervals in 3S-09 are forecasted to be 9135, 8942, and 8702 feet measured depth, respectively. In the above completion scenario, the packer is set in the shale/claystone sequence overlying the Kuparuk reservoir and 700 feet below the top. of cement. Also, the distance between the tubing tail and Kuparuk formation top would be +/- 320 feet. In this case, CPA would run a cement bond log below the tubing tail to confirm cement quality after the drilling rig runs the completion and moves off of the well. In summary, two primary risks are introduced by taking this action. One risk is the increased exposure for an annulus leak path in the event of a leak in the 7" casing below. the packer. The other risk is a reduced interval length to be bond logged, which could create difficulties in demonstrating a hydraulic ba1TÎer above the pay zone. To mitigate the risks of increasing the distance between the packer and the top perforation by 250 feet, CPA proposes to increase the length of the cement column above the pay zone by an equal amount. We believe that a 350 feet measured depth exception for Drill Site 3S (Palm) provides protection to resources equivalent to whatis provided under 20 ACC 25.412 (b) and serves to facilitate drilling operations. Adoption of this practice will ultimately decrease development drilling costs on the Drill Site 3S (Palm) project. We respectfully request consideration of this proposal and look forward to your favorable reply. If you have further questions, please call me at 265-1606. Sincerely, V~/(.PJ? Daniel E. Hensley Palm Surveillance Engineer ') ŒillJ ~~~~ TONY KNOWLES, GOVERNOR AI,ASIiA OIL AND GAS CONSERVATION COltDlISSION 333 W. "JTH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Randy Thomas Kuparuk Drilling Team Leader ConocoPhillips Alaska PO Box 100360 Anchorage AK 99510 Re: Kuparuk River Unit 38-09 ConocoPhillips Alaska Pennit No: 202-205 Surface Location: 2497' FNL, 974' FEL, Sec. 18, TI2N, R8E, UM Bottomhole Location: 2585' FNL, 1580' FEL, Sec. 8, TI2N, R8E, UM DearMr. Thomas: Enclosed is the approved application for pennit to drill the above referenced development well. This pennit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative. Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, P?-¡'~/? ~ Michael L. Bill Commissioner BY ORDER OF THE COMMISSION - DATED this ;2t,1.~.day of November, 2002 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. "') Conoc:oPhinips ) Post Office Box 100360 Anchorage, Alaska 99510-0360 Randy Thomas Phone (907) 265-6830 Fax: (907) 265-1535 Email: rlthomas@ppco.com September 26, 2002 Cammy Oechsli Taylor, Chair Alaska Oil and Gas Conservation Commission 333 West ih Avenue Suite 100 Anchorage, Alaska 99501 (907) 279-1433 Re: Application for Permit to Drill, injector 38-09 Dear Commissioner Taylor: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore service well, KRU 3S-09, a development well. Please find attached for the review of the Commission the information required by 20 ACC 25.005 (c). If you have any questions or require any further information, please contact Scott Lowry at 265-6869. Sincerely, ~ '"'"---L \ '-~~~ \ ~.- Randy Thomas GKA Drilling Team Leader RECE1VED OCT 0 "' .2002 A1aSka O~&Gaa Qons. eommission Anchorage ltJG¡.\-- HI i i/ 02- ') J 1a. Type of work: Drill ~ Redrill 0 Re-entry ODeepen 0 2. Name of Operator ConocoPhillips Alaska, 3. Address P.O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface 2497'FNL,974'FEL,Sec.18,T12N,R8E,UM At top of productive interval 2548'FSL,1713'FEL,Sec.8,T12N,R8E,UM At total depth 2585'FNL,1580'FEL,Sec.8,T12N,R8E,UM 12. Distance to nearest property line 13. Distance to nearest well 1580' @ TD1580' @ TD No risk 16. To be completed for deviated wells Kickoff depth: 200 M D 18. Casing program size STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1b. Type of well. Exploratory U Stratigraphic Test U Service 0 Development Gas 0 Single Zone 0 5. Datum elevation (DF or KB) RKB = 28' feet 6. Property Designation ADL 380106 ALK 4623 7. Unit or property Name 11. Type Bond (see 20 MC 25.0251) Kuparuk River Unit Statewide 8. Well num~ Number 3S-09 #59-52-180 9. Approximate spud date / Amount December 1, 2002 $200,000 14. Number of acres in property 15. Proposed depth (MD and TVD) 2448 9486 ' MD / 5921 'TVD 17. Anticipated pressure (see 50 MC 25.035 (e)(2» Maximum surface 2951 psig/ At total depth (TVD) 3588 psig Setting Depth Development Oil U Multiple Zone 0 10. Field and Pool Kuparuk River Field Kuparuk River Oil Pool Maximum hole angle 56° Hole Casing Weight 42" 16" X 30" 62.5# 12.25" 9.625" 40# 8.5" 7" 26# Specifications Grade Coupling H-40 Weld L-80 BTC L-80 BTCM Top Bottom Quantity of Cement Length MD TVD MD TVD (include stage data) 80' 28' 28' 108' 108' 9 cy High Early 3561' 28' 28' 3589' 2612' 580 sx AS Lite & 300 sx LiteCrete 9458' 28' 28' 9486' 5921' 210 sx Class G 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total Depth: measured true vertical feet feet Plugs (measured) Effective Depth: measured true vertical feet feet Junk (measured) Casing Conductor Surface 0 Length Size Cemented Measured depth True Vertical depth RECEIVED OCT 0 1.2002 A1aSIØ101&Gas Gons. Gommtsslan . . Anchomge 20. Attachments Filing fee 0 Property Plat 0 BOP Sketch 0 Diverter Sketch 0 Drilling program 0 Drilling fluid program 0Time vs depth plot Qefraction analysis OSeabed report 020 AAC 25.050 requirements 0 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Questions? Call Scott Lowry 265-6869 Signed ~4~ R. Thomas Perforation depth: measured true vertical Title: Kuparuk Drilling Team Leader e>¡ (, () (0<- Date Prp.nArp.rl hv RhAmn AII.C:/ln-nrAkp. Commission Use Only Permit Number API number APprovalate I see cover letter -< 0 Z - Zð $" 50- /03 - 2-0 7'32- t I db o;;¿ for other requirements Conditions of approval Samples required 0 Yes I8J No Mud log equired U Yes ~ No Hydrogen sulfide measures 0 Yes 81 No Directional survey required ~ Yes 0 No Required working pressure for BOPE 02M; 0 3M; 0 5M; 0 . 10M; .0 O. ~. '. 1 j. ~ 4 . r. . Other: :T€-St- gP~E: ~r 5000 f1 > t. MIT. ~t i UA:íiL- }",,, ~it.(.,i~d. &W'-~~.~ê~ .~us.r p.e ~'\-('\-<e.-<- ",l' "'" ~€4 ~ \={ cct, <U "'-t~r þiO\ f~ IÑ\. M ,~,,'- ~ ~ ~~ {.CØK M d 'lttdiy ~f~~~ 'ff.é'.-I:;v. 0". clev , ...\- J .J ".J by order of \.. Approved by Commissioner the commiss~,~, Date, I I do Co, {Yd ORIGI~Ls::eoBY J N í (.;j ¡ j L Submit in triplicate Form 10-401 Rev. 12/1/85. ) Apr" ,,'¡iOn for Permit to Drill, Well 3S-09 Revision No.O , Saved: 26-Sep-02 Permit It - Kuparuk Well 38-09 Application for Permit to Drill Document MQximizE Well Va. VI; Table of Contents 1. Well Name ....... ..... ..... ........... ....... .... ........ .... ...... ....... ......... ......... ..... .... ... ............ ....... 2 Requirements of 20 AAC 25.005 (f)....... ..... ...... ........................ ................ .................... ............. .............2 2. Location Sum mary ... ... .... ........... ..... ....... .... ...................... .... ........ ......... .......... .... ..... 2 Requirements of 20 AAC 25.005(c)(2) .............. ................ ......... ..... ......... .............. ............ ....................2 Requirements of 20 AAC 25. 050(b )...... .............................................. ...... .................. .... ........................ 2 3. Blowout Prevention Equipment Information .........................................................3 Requirements of 20 AAC 25.005(c)(3) ... ............. ..... ....... ........... ............ ............. ....... ..................... ....... 3 4. Drill i ng Hazards Information .. .... .... ... ...... ........ ......... .... ......... ......... ......... .......... ...... 3 Requirements of 20 AAC 25.005 (c)( 4) ........ ...... ................................ ............... ................. ............. ....... 3 5. Procedure for Conducting Formation Integrity Tests ...........................................3 Requirements of 20 AAC 25.005 (c)(5) .................................................................................................. 3 6. Casing and Cementing Program .............................................................................4 Requirements of 20 AAC 25.005(c)(6) .... ....... ....... ........ ....... ........................ ............. ...... ........... ............ 4 7. Diverter System Information...... ........ ... ............ ..... ...... .......... ........... ..... ........ ...... ... 4 Requirements of 20 AAC 25. 005( c)(7) .... ....... ....... ""'"'''''''' ...................... ..................... ............ ........... 4 8. Drill i ng FI uid Program ... ........ ....... .... ..... ... ...... ........ ......... ..... ... .... ......... ...... .... ......... 4 Requirements of 20 AAC 25. 005( c)(B) .................................... ....................... .......... .................. ............ 4 9. Abnormally Pressured Formation Information ...................................................... 5 Requirements of 20 AAC 25.005 (c)(9) .................................................................................................. 5 10. Seism ic Analysis ........ ....... ............. ... ..... .... ....... ...... ....... .............. .... ........ ......... ....... 6 Requirements of 20 AAC 25.005 (c)(10) ................................................................................................ 6 11. Seabed Condition Analysis .....................................................................................6 Requirements of 20 AAC 25.005 (c)(11) ................................................................................................ 6 12. Evidence of Bonding ....... ............... ............ ........... ........ ................... ............... ........ 6 Requirements of 20 AAC 25.005 (c)(12) ................................................................................................6 13. Proposed Drilling Program .....................................................................................6 3$-09 PERMIT IT. DOC J n .~ ,~ n ~.I Æ L. Page 1 of 7 . ~,'æ'J l;. ~ n..... n.. ' . Prmted: 26-$ep-02 !.td "'~~"t} I I f . ¡~ I I 1iJ I'~¡ ) APr'..").. ion for Permit to Drill, We1l3S-09 Revision No.O Saved: 26-Sep-02 Requirements of 20 AAC 25.005 (c)(13) ... ............ .......... ......... '"'.''' "'" ......... ................ ................. ....... 6 14. Discussion of Mud and Cuttings Disposal and Annular Disposal....................... 7 Requirements of 20 AAC 25.005 (c)(14) ................................................................................................ 7 15. Attachments .. ..... ...... .... ............ ..... ....... ...... ....... .......... ....... ............................. ......... 7 Attachment 1 Directional Plan............... .................................. ......................... ....................... .............. 7 Attachment 2 Drilling Hazards. ................ ............... ...... ....... ........... ..... ...... .... ........ ............ ..6 Attachment 3 Well Schematic....... "'. ..... .... ... ...... ...... ... ......... ........ ............. ..... "'." ............. ..6 1. Well Name Requirements of 20 AAC 25.005 (f) Each well must be Identified by a unique name designated by the operator and a unique API number assigned by the commi¿;,:;ian under 20 AAC 25.040{b). For a we!! with multiple well branche~ eaLl1 branch must similady be Identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number ass~qned to the we!1 by the commi.sion The well for which this application is submitted will be designated as 35-09. 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An application far a Permit to Dliff must be accompanied by each of'the following item~ except for an item already on tHe with the commission and Identified i/7 the application: (2) a plat identifyliìg the property and the property's owners and showing (A)the coordinates of the p!vposed locatian of the well at the surfac~ at the tap of each objective formation and at total depth referenced to governmental section lines. (B) the coordinates of the proposed location of the well at the surfacer referenced to the state plane coordinate system f()r this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the propos-ed depth of tlie well at the top of each objective formation and at total depth; I 2497' FNL, 9741 FEL, Sec 18, T12N, R8E, UM RKB Elevation Pad Elevation Location at Surface NGS Coordinates Northings: 5,993/919 Eastings: 476,286 Location at Top of Productive Interval (Kuparuk "c" Sand) NGS Coordinates Northings: 5,998,950 25481 FSL, 17131 FEL, Sec 8, T12N, R8E, UM Measured Depth, RKB: Total Vertical Depth, RKB: Total Vertical Depth, 55: Location at Total Depth I 2585' FNL, 15801 FEL, Sec 8, T12N, R8E, UM NGS Coordinates Measured Depth, RKB: Northings: 5,999,097 Eastings: 480,957 Total Vertical Depth, RKB: Total Vertical Depth, 55: Eastings: 480,824 and (D) other information required by 20 AAC 25.050(b); 56.11 AMSL 28.0' AMSL 9247' 57871 57311 94861 59211 58651 Requirements of 20 AAC 25.050(b) If a well is to be intentionally deviatedr the application for a Permit ta Dr!!1 (Form 10-401) must (1) include a p/aç dra}'vn to a suitable scaler showing the path of the proposed wellbore/ including all adjacent wellbores within 200 feet of any portion of the proposed welf,' Please see Attachment 1: Directional Plan 0 38-09 PERMIT IT. DOC 7J' Page 2 of 7 Prif1ted: 26-8ep-02 ,~~JiÎj 1.. ') APP':-<~..tion for Permit to Drill, We1l3S-09 } Revision No.O Saved: 26-Sep-02 and (2) for all wells within 200 feet of the proposed we/lbore (A) list the names of the operators of those well~ to the extent that those names are known or discoverable in pub/lc record~ and show that each named operator has been furnished a copy of the application by certifìed ma¡¿- or (8) state that the applicant is the only affected owner. The Applicant is the only affected owner. 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for a Pe¡mit to Drill must be accompanied by each of the foIIO¡¡<{Íng Items, except for an Item already on tile with the commission and identifìed in the application: (3) a diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25-03~ 20 MC25-036, or 20 AAC 25-037, as applicabJe;-, Please reference BOP schematics on file for Nabors 7E5. 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application for a Permit to Drill must be accompanied by each of the following !tem~ except for an item already on tile with the commis..,>ion and Identifìed in the application: (4) information on dnlling hazard~ including (A) the maximum downhole pressure that may be encountered, cntefia used to determine it and maximum potential surface pressure based on a methane gradient' A pressure build-up test performed on Palm lA (35-26) in 4/01 indicated a reservoir pressure in th~. Kuparuk C sand of 3597 psi at 5830' tvd, 0.62 psi/ft or 11.9 ppg EMW (equivalent mud weight). ./ The maximum potential surface pressure (MP5P) while drilling 35-09 is calculated using above maximum reservoir pressure, a gas gradient of 0.11 psi/ft, and the Kuparuk C sand target at 5787' tvd: MP5P =(5787 ft)*(0~2 - 0.11 psi/ft) = 2951 psi / (B) data on potential gas zones; The well bore is not expected to penetrate any gas zones. and (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zoneS;, and zones that have a propensity for differential sticking,: Please see Attachment 2 - Drilling Hazards Summary 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An application for a Permit to Dnll must be accompanied by each of the following item~ except for an item already on fìle with the commission and identitied in the application: (5) a description of the procedure for conducting formation integrity test~ as required under 20 MC 25.030{f); A procedure is on file with the commission for performing LOT's. For 35-09 the procedure will be followed with one exception. The surface casing shoe will be pressured until leak-off occurs and the 16.0 ppg EMW maximum will not be observed. (see step 6 in the procedure) 0), ~ 3$-09 PERMIT IT. DOC Page 3 of 7 Þrrted: 26-$ep-02 L ) APr"!~ion for Permit to Drill, Well 3S-09 J Revision No.O Saved: 26-Sep-02 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each af tile tôllavv'ing ¡tem~ except for an item already on file with the commiS:;;7on and identífìed in the application: (6) a complete proposed casing and cementing program as required by 20 MC 25. 03~ and a desc-¡iption of any slotted liner; pre- perforated liner; or screen to be installeci' Casinq and Cementing Program Hole Top 8tm Csg/Tbg Size Weight Length MD/TVD MD/TVD 00 (in) (in) (Ibltt) Grade Connection (ft) (tt) (tt) Cement Program 30 X 16 42 62.5 H-40 Welded 80 28 / 28 108 / 108 9 cy High Early Insulated ...........-. 9-5/8 12-1/4 40 L-80 BTC/ 3561' 28'/28' 3589'/2612' Lead:~§"x 10.7 ppg ASL~ Tail: . O."sx 12.0 ppg 'LiteKt I ~'. (Yield=2.40 cuft/sk) ~ned TOC=Surface 7 8-1/2 26 L-80 BTC-Mod / 9458' 28'/28' 9486'/5921' f2 sx 15.8 ppg 'G' w/ aCíé:l. Planned TOC= 8447' MD 3-1/2 9.3 L-80 EUE 8rd 9119' 28' / 28' 9147'/5734' SAB- 3 packer set at Mod 9147' MD. An open-hole leak-off test will be performed on the 8 112" open hole interval after reaching the contingent casing point. If the leak-off test indicates insufficient formation integrity, 7" casing will be top-set above the Kuparuk C sand. If 7" casing must be top-set above the Kuparuk C sand, a 3 112" production liner will be used and an exception to 20 AAC 25.412 (b) is requested. The distance between seals at the top of the 3 112" liner and the top perforation will exceed 200' MD. In the top-set case, the distance between the seals and the top perforation will be 1V400' MD. An adequate leak-off test of the 7" casing shoe, combined with a cement bond log of the liner section below the 7" casing shoe will provide proof of zonal isolation between the seals and the perforated interval. 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An application for a Permit to Drill must be accompanied by each of the following ¡tems¡- except for an Item already on file with the commission and identified in the application: (1) a diagram and description of the diverter system as required by 20 AAC 25.03~ unless this requirement is waived by the commission under 20 AAC 25.035(17)(2); / Please reference diverter schematic on file for Nabors 7ES. I 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(B) An application for a Permit to Drill must be accompanied by each of the follol/;lÍng items; except for an item already on file with the commission and Identified in the application: (8) a drilling fluid program/ incJudJÌ1g a diagram and descriptíon of the ddllíng fluid system/ as required by 20 MC 25.033; Drilling will be done using mud systems having the following properties: O.R..'...ii.ff '1 ¡ i .i 38-09 PERMIT IT. DOC J Page 4 of 7 7rinted: 26-8ep-02 ~;fiIt ') Apr'" <;;ion for Permit to Drill, We1l3S-09 , Revision No.O . Saved: 26-Sep-02 Suface Hole mud properties Spud to Base of Permafrost Base of Permafrost to Total Depth Initial Value Final Value Initial Value Final Value / Density (ppg) 9.4 9.4* 9.4* 9.4* Funnel Viscosity 120-130 120-1 00 100-120 100-75 (seconds) Yield Point 35-45 27 -40 25-35 20-30 (cP) Plastic Viscostiy 8-15 11-22 15-30 15-30 (lb11 00 sf) 10 second Gel 10-30 10-25 1 0-25 10-25 Strength (lb1100 sf) 10 minute Gel 25-55 25-55 20-40 15-35 Strength (lb1100 sf) pH 8-9 8-9 8-9 8-9 API Filtrate(cc) 12-15 7-8 7-8 7-8 Solids (%) 6-9 6-12 6-12 6-12 * 9.8 if hydrates are encountered Production Hole mud properties initial C40 Top Morraine Top HRZ Kuparuk Density (ppg) 9.5 10.2 10.6 10.8 12.3 r" Funnel Viscosity 40-55 42-55 42-58 42-58 42-58 (seconds) Yield Point 11-15 20-25 20-25 20-25 20-25 (cP) Plastic Viscostiy 6-12 8-15 8-16 8-18 15-25 (lbl1 00 sf) 10 second Gel 2-5 3-6 3-6 4-7 4-8 Strength (lb1100 sf) 10 minute Gel 4-10 7-10 7-112 7-12 8-16 Strength (lb1100 sf) pH 9-9.5 9-9.5 9-9.5 9-9.5 9-9.5 API Filtrate(cc) <6 <6 <6 <4 <4 Solids (%) 6-11 9-14 1 0-15 1 0-15 15-19 Diagram of Nabors 7ES Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Permit to Dnll must be accompanied by each of the fol/owing item~ except for an item already on file ¡¡<lith the commission and identified in the application: (9) for an exploratof1/ or stratigraphic test we/~ a tabulation ::.--etting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.0J3(f); N/ A - Application is not for an exploratory or stratigraphic test well. O'~.; h 3S-09 PERMIT IT.DOC ." ~;'\. .~.~ 1ge 5 of 7 ¡prirt(3ä..: 6-Sep-02 ~t!r~ ') Apr" .~.. ion for Permit to Drill, We1l3S-09 } Revision No.O . Saved: 26-Sep-02 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) An application for a Permit to Drill must be accompanied by each of tile fo/lovving Item~ except for an Item already on file with the commission and identified in the application: (10) for an exploratory or stratigraphic test wel¿ a seismic refraction or reflection analysis as requIred by 20 MC 25.061(a); N/ A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An application for a Permit to Drill must be accompanied by each of the following Item::,~ except for an item already on file with the commission and identified in the application: (11) for a well drilled from an offs11Ore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel; an analysis of seabed conditions as required by 20 MC 25.061{b); N/ A - Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An application for a Permit to Drill must be accompanied by each of the followIng item~ except for an item already on file ¡~'¡Ith the commIssIon and Identified in the application: (12) evidence showing that the requirements of 20 MC 25.025 {Bonding}have been met; Evidence of bonding for Phillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) An application tor a Permit to Dlill must be accompanied by each of the (ollowing items¡ except for an item already on file wìth the commission and Identifled in the application: The proposed drilling program is listed below. Please refer as well to Attachment 3, Well Schematic. 1. MIRU Nabors 7ES. /' 2. Install diverter system. 3. Drill 12-1/4" hole to 9-5/8" surface casing point according to directional plan. Run LWD logging equipment with GR tool only. /' 4. Run and cement 9-5/8" 40#, L-80 BTC casing string to surface. Employ lightweight permafrost cement lead slurry and LiteCRETE tail slurry. Pump adequate excess to ensure cement reaches the surfa~. If cement does not circulate to surface, perform top job. Install and test BOPE to 5000 psi. Test casing to 2500 psi. 5. Drill out cement and 20' of new hole. Perform LOT. 6. Drill 8-1/2" hole to contingent top-set casing point according to directional plan. Run LWD logging equipment with GR and resistivity. Perform second LOT to evaluate long string option. ../ POOH aqd P/U neutron density tool, drill well to total depth according to directional plan, and run 7" 26# (-80 BTCM casing to surface and cement. Note: If significant hydrocarbon zones are present above the Kuparuk C sand, sufficient cement will be pumped for isolation in accordance with 20 MC 25.030(d)(3)(C). / 7. Run cement bond log to verify zonal isolation prior to running completion. 8. Run 3-1/2" 9.3#,1.-80 8rd EUE 8rd-Mod completion assembly w/ SAB-3 permanent packer and PBR. Set packer, shear out of PBR, P/U tubing hanger, and land tubing. Pressure test tubing to 3500 psi. Pressure test 3 112" x 7" annulus to 3500 psi. Burst shear valve for freeze protect. 9. Set TWC and ND BOPE. Install and pressure test production tree. 10. Freeze protect. Secure well. Rig down and move out. 11. Handover well to Operations Personnel. Note: If the deep LOT indicates insufficient formation integrity to continue drilling, 7" 26# L -80 BTCM . casing will be run and cemented above the Kuparuk C sand. 6 1/8" hole will be drilled to total depth /' o.c...P . !J g ~ ~.~. 5 ,; j 3$-09 PERMIT IT. DOC Page 6 of 7 I Printed: 26-Sep-02 .... ) Apr'. '\tion for Permit to Drill, Well 3S-09 J Revision No.O , Saved: 26-Sep-02 according to the directional plan and a 3 V2" 9.3# L-80 5LHT liner will be ran and cemented across the/ productive interval. In this case, the cement bond log will be done after moving the rig off the well. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An application f'Or a Permit to Drill mu!:>tc be accompanied by each of the following items, except for an item a/ready 0/7 tile with the commission and identified in the application: (14) a general dÔ"CTipUon of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator Intends to request authorization under 20 AAC 25.080 for an annular disposal operation In the well.; Waste fluids generated during the drilling process will be disposed of down a permitted annulus on 35 pad or hauled to a KRU Class II disposal well. All cuttings will be disposed of either down a permitted annulus on 35 pad or hauled to the Prudhoe Bay Field for temporary storage and eventual processing for injection down an approved disposal well. // At the end of drilling operations, an application may be submitted to permit 35-09 for annular pumping of fluids occurring as a result of future drilling operations on 35 pad. 15. Attachments Attachment 1 Directional Plan Attachment 2 Drilling Hazards Summary Attachment 3 Well Schematic. 0 3$-09 PERMIT IT. DOC Page 7 of 7 L Printed: 26-Sep-02 \À ¡ 4 Sperry-Sun Drilling Services ConocoPhillip~18¡i1t, Western North Slope Kup t(fc 3$ Pad '(':1'°3) . .......,. oposal Report 26 September, 2002 Surface Coordinates: 5993919.00 N, 476285.94 E (70023' 40.2619" N, 150011' 34.6045" W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 Kelly Bushing: 56. 10ft above Mean Sea Level C :::J::J ...........- -""',.,-- ~ ,~ 3}.c.~':sI. r--- s.-.-.y-&UI1 Ft>nì')?"'¡T"lniâiS"""'~ã\r;'SJf¡¡SNl';¡1i"'FWiE"iÈ' ~,:,,:.~::,:x,:::;,.::;:~~!q\~-:,:,)1t,:,:,:,:~:,,:~JMt,:';;;:t:;':M;,:,:$~~::::~k,;ft it.H.tiwttlW¡ ~lii1fØf¥ Proposal Ref: pro9975 Sperry-Sun Drilling Services Proposal Report for Kuparuk 35 Pad - 35-09 Plan - 3s-09 (wp03) ConocoPhillips Western North Slope Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section (ft) (ft) (ft) (ft) (ft) (ft) (ft) e 11 OOft) 0.00 0.000 0.000 -56.10 0.00 O.OON 0.00 E 5993919.00 N 476285.94 E I'Î~í¡f,IIT 0.00 SHL (2497' FNL & 974' FEL, SEC. 18- T12N - R8E) 100.00 0.000 0.000 43.90 100.00 O.OON 0.00 E ''i\tll¡t~.ooo 0.00 200.00 0.000 0.000 143.90 200.00 0.00 N 0.00 E '..000 0.00 Begin Dir @ 2.00/100ft (in 12-1/4" Hole): 200.00ft MD, 200.00ft TVD 300.00 2.000 41 .000 243.88 299.98 1.32 N 1.14 E 2.000 1.74 400.00 4.000 41 .000 343.74 399.84 5.27N 4.58 E 2.000 6.98 500.00 6.000 41 .000 443.35 499.45 11 .84 N 10.30 E 5993930.81 N 476296.27 E 2.000 15.69 '-.-r 600.00 8.000 41 .000 542.60 598.70 21.04 N 18.29 E 5993939.98 N 476304.30 E 2.000 27.88 700.00 10.000 41 .000 641 .37 697.47 32.85 N 28.55 E 5993951.76 N 476314.60 E 2.000 43.52 Increase in Dir Rate @ 4.00/100ft : 700.00ft MD, 697.47ft TVD 800.00 14.000 41 .296 739.16 795.26 42.24 E 5993967.36 N 476328.33 E 4.000 64.30 900.00 17.999 41 .462 835.27 891.37 60.46 E 5993987.98 N 476346.62 E 4.000 91.86 1000.00 21.999 41 .569 929.22 83.12 E 5994013.51 N 476369.36 E 4.000 126.05 1100.00 25.999 41 .645 1020.55 7N 110.13 E 5994043.82 N 476396.46 E 4.000 166.72 1200.00 29.999 41.701 1108.83 160.23 N 141.33 E 5994078.78 N 476427.78 E 4.000 213.65 1300.00 33.999 41.746 1193.62. . 199.77 N 176.60 E 5994118.21 N 476463.17 E 4.000 266.63 1400.00 37.999 41.782 1274.51 243.60 N 215.74 E 5994161.92 N 476502.45 E 4.000 325.40 1500.00 41.999 41.812 1351.10 1407.20 291.51 N 258.57 E 5994209.69 N 476545.43 E 4.000 389.66 1600.00 45.999 41 .838 23.02;>' 1479.12 343.27 N 304.88 E 5994261.30 N 476591.91 E 4.000 459.11 1700.00 49.999 41.860 9.92 1546.02 398.61 N 354.45 E 5994316.49 N 476641.65 E 4.000 533.41 1700.12 50.004 41.860 1490.00 1546.10 398.68 N 354.52 E 5994316.56 N 476641.72 E 4.000 533.50 B. Permafrost 1800.00 53.999 41 .880 1551.48 1607.58 457.28 N 407.04 E 5994374.99 N 476694.42 E 4.000 612.19 1846.60 55.863 41 .889 1578.25 1634.35 485.67 N 432.50 E 5994403.30 N 476719.98 E 4.000 650.33 End Dir, Start Sail @ 55.86°: 55.863 1846.60ft MD, 1634.35ft TVD 1900.0 41 .889 1608.22 1664.32 518.58 N 462.01 E 5994436.11 N 476749.59 E 0.000 694.53 '~¡ 2000.0 55.863 41 .889 1664.33 1720.43 580.19 N 517.27 E 5994497.55 N 476805.05 E 0.000 777.30 2100.00 55.863 41 .889 1720.45 1776.55 641.81 N 572.54 E 5994558.99 N 476860.51 E 0.000 860.07 C) 2200.00 55.863 41 .889 1776.57 1832.67 703.43 N 627.80 E 5994620.43 N 476915.97 E 0.000 942.84 ~- 765.04 N 683.07 E 5994681.87 N 476971.43 E 0.000 1025.61 2300.00 55.863 41 .889 1832.69 1888.79 2400.00 55.863 41 .889 1888.81 1944.91 826.66 N 738.33 E 5994743.31 N 477026.89 E 0.000 1108.38 2500.00 55.863 41 .889 1944.92 2001.02 888.28 N 793.59 E 5994804.76 N 477082.35 E 0.000 1191.15 2517.96 55.863 41 .889 1955.00 2011.10 899.34 N 803.52 E 5994815.79 N 477092.31 E 0.000 1206.01 T. West Sak 2600.00 55.863 41 .889 2001 .04 2057.14 949.90 N 848.86 E 5994866.20 N 477137.81 E 0.000 1273.92 26 September, 2002 - 7:29 Page 2 of9 Drillquest 3.03.02.002 Sperry-Sun Drilling Services Proposal Report for Kuparuk 35 Pad - 35-09 Plan - 3s-09 (wp03) ConocoPhillips Western North Slope Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section (ft) (ft) (ft) (ft) (ft) (ft) (ft) (o/100ft) 2700.00 55.863 41 .889 2057.16 2113.26 1011 .51 N 904.12 E 5994927.64 N ò'%œ<w1356.69 2800.00 55.863 41 .889 2113.28 2169.38 1073.13 N 959.39 E 5994989.08 N 00 1439.45 2900.00 55.863 41 .889 2169.39 2225.49 1134.75 N 1014.65 E 5995050.52 N .000 1522.22 3000.00 55.863 41 .889 2225.51 2281.61 1196.36 N 1069.92 E 5995111.96 N .000 1604.99 3100.00 55.863 41 .889 2281.63 2337.73 1257.98 N 1125.18 E 5995173.40 N 0.000 1687.76 ,';''''-»:';'~:«', - 3200.00 55.863 41 .889 2337.75 2393.85 1180.44 E 5995234.85 N 70.56 E 0.000 1770.53 3300.00 55.863 41 .889 2393.87 2449.97 1235.71 E 5995296.29 N 477526.02 E 0.000 1853.30 3310.93 55.863 41 .889 2400.00 2456.10 1241.75E 5995303.00 N 477532.09 E 0.000 1862.35 B. West Sak ,~ 3400.00 55.863 41 .889 2449.98 2506.08 1290.97 E 5995357.73 N 477581.48 E 0.000 1936.07 3500.00 55.863 41 .889 2506.10 2562.20 1346.24 E 5995419.17 N 477636.94 E 0.000 2018.84 3589.00 55.863 41 .889 2556.05 2612.15 1¡¡I¡II:N 1395.42' E 5995473.85 N 477686.30 E 0.000 2092.51 9-5/8" Csg Pt ... Drill out 8-1/2" Hole 3589.00ft MD, 2933.84ft TVD 9 5/8" Casing 3600.00 55.863 41 .889 2562.22 2618.32 1401.50 E 5995480.61 N 477692.40 E 0.000 2101.61 3688.71 55.863 41 .889 2612.00 2668.10 1450.52 E 5995535.12 N 477741.60 E 0.000 2175.03 C-80 (K-10) 3700.00 55.863 41 .889 2618.34 2674.44 1456.76 E 5995542.05 N 477747.86 E 0.000 2184.38 3800.00 55.863 41 .889 2674.45" 2730.55 1512.03E 5995603.50 N 477803.32 E 0.000 2267.15 ..~ttIfj@@ 3900.00 55.863 41 .889 2730.57 27à~:67 1750.92 N 1567.29 E 5995664.94 N 477858.78 E 0.000 2349.92 4000.00 55.863 41 .889 2786.69 2842.79 1812.53 N 1622.56 E 5995726.38 N 477914.24 E 0.000 2432.69 4100.00 55.863 41 .889 42.81%'.". 2898.91 1874.15 N 1677.82 E 5995787.82 N 477969.70 E 0.000 2515.46 4200.00 55.863 41 .889 8.93 2955.03 1935.77 N 1733.08 E 5995849.26 N 478025.16 E 0.000 2598.23 4300.00 55.863 41 .889 955.04 3011.14 1997.39 N 1788.35 E 5995910.70 N 478080.62 E 0.000 2681.00 4400.00 55.863 41 .889 3011.16 3067.26 2059.00 N 1843.61 E 5995972.14 N 478136.08 E 0.000 2763.77 4500. 41 .889 3067.28 3123.38 2120.62 N 1898.88 E 5996033.59 N 478191.54 E 0.000 2846.53 4600. 41 .889 3123.40 3179.50 2182.24 N 1954.14 E 5996095.03 N 478246.99 E 0.000 2929.30 4700.0 41 .889 3179.51 3235.61 2243.85 N 2009.41 E 5996156.47 N 478302.45 E 0.000 3012.07 .~ 4800.0 41 .889 3235.63 3291.73 2305.47 N 2064.67 E 5996217.91 N 478357.91 E 0.000 3094.84 4900.00 55.863 41 .889 3291.75 3347.85 2367.09 N 2119.93 E 5996279.35 N 478413.37 E 0.000 3177.61 5000.00 55.863 41 .889 3347.87 3403.97 2428.70 N 2175.20 E 5996340.79 N 478468.83 E 0.000 3260.38 CJ 5100.00 55.863 41 .889 3403.99 3460.09 2490.32 N 2230.46 E 5996402.23 N 478524.29 E 0.000 3343.15 5200.00 55.863 41 .889 3460.10 3516.20 2551.94 N 2285.73 E 5996463.68 N 478579.75 E 0.000 3425.92 5300.00 55.863 41 .889 3516.22 3572.32 2613.56 N 2340.99 E 5996525.12 N 478635.21 E 0.000 3508.69 """"'0 5400.00 55.863 41 .889 3572.34 3628.44 2675.17 N 2396.25 E 5996586.56 N 478690.67 E 0.000 3591.46 ~. 5500.00 55.863 41 .889 3628.46 3684.56 2736.79 N 2451.52 E 5996648.00 N 478746.13 E 0.000 3674.23 - 5600.00 55.863 41 .889 3684.58 3740.68 2798.41 N 2506.78 E 5996709.44 N 478801.59 E 0.000 3757.00 5700.00 55.863 41 .889 3740.69 3796.79 2860.02 N 2562.05 E 5996770.88 N 478857.05 E 0.000 3839.77 .,,-,-.-,,"_n~<- 5800.00 55.863 41 .889 3796.81 3852.91 2921.64 N 2617.31 E 5996832.32 N 478912.51 E 0.000 3922.54 i\~ " 26 September, 2002 - 7:29 Page 3 of9 Dril/Quest 3.03.02.002 Sperry-Sun Drilling Services Proposal Report for Kuparuk 3S Pad - 3S-09 Plan - 3s-09 (wp03) ConocoPhillips Western North Slope Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate .Section (ft) (ft) (ft) (ft) (ft) (ft) (ft) (O/100ft) ! 5900.00 55.863 41 .889 3852.93 3909.03 2983.26 N 2672.58 E 5996893.77 N O.OOO"'^~ 4005.31 6000.00 55.863 41 .889 3909.05 3965.15 3044.88 N 2727.84 E 5996955.21 N 0.000 4088.08 6100.00 55.863 41 .889 3965.16 4021 .26 3106.49 N 2783.10 E 5997016.65 N 0.000 4170.85 6200.00 55.863 41 .889 4021 .28 4077.38 3168.11 N 2838.37 E 5997078.09 N .000 4253.62 6300.00 55.863 41 .889 4077.40 4133.50 3229.73 N 2893.63 E 5997139.53 N 0.000 4336.38 A'~:':::::::0'X~ 6338.49 55.863 41 .889 4099.00 4155.10 3253.44 N 2914.90 E 5997163.18 N 11.15 E 0.000 4368.24 C-40 (K-3) 6400.00 55.863 41 .889 4133.52 4189.62 3291.34 N 2948.90 E 5997200.97 N 479245.26 E 0.000 4419.15 6500.00 55.863 41 .889 4189.64 4245.74 3352.96 N 3004.16 E 5997262.41 N 479300.72 E 0.000 4501.92 ~ 6600.00 55.863 41 .889 4245.75 4301.85 3414.58 N 3059A2 E 5997323.86 N 479356.18 E 0.000 4584.69 6700.00 55.863 41 .889 4301.87 4357.97 3476.20 N 3114.69 E .5997385.30 N 479411.64 E 0.000 4667.46 6800.00 55.863 41 .889 4357.99 4414.09 3 81 N 3169.95 E 5997446.74 N 479467.10 E 0.000 4750.23 6900.00 55.863 41 .889 4414.11 4470.21 3599.43 N 225.22 E 5997508.18 N 479522.56 E 0.000 4833.00 7000.00 55.863 41 .889 4470.22 4526.32 3661.05 N 3280.48 E 5997569.62 N 479578.02 E 0.000 4915.77 7100.00 55.863 41 .889 4526.34 4582.44 . 3722.66 N 3335.75 E 5997631.06 N 479633.48 E 0.000 4998.54 7200.00 55.863 41 .889 4582.46 4638.56 3784.28 N 3391.01 E 5997692.50 N 479688.94 E 0.000 5081.31 7300.00 55.863 41 .889 4638.58 4694.68 3845.90 N 3446.27 E 5997753.95 N 479744.40 E 0.000 5164.08 7400.00 55.863 41 .889 4694.70 4750.80 3907.51 N 3501.54 E 5997815.39 N 479799.86 E 0.000 5246.85 7500.00 55.863 41 .889 4750.81 4806.91 3969.13 N 3556.80 E 5997876.83 N 479855.32 E 0.000 5329.62 7600.00 55.863 41 .889 4806.93 4863.03 4030.75 N 3612.07 E 5997938.27 N 479910.77 E 0.000 5412.39 7700.00 55.863 41 .889 63.0S"". 4919.15 4092.37 N 3667.33 E 5997999.71 N 479966.23 E 0.000 5495.16 7800.00 55.863 41.889 4919.17 4975.27 4153.98 N 3722.59 E 5998061.15 N 480021.69 E 0.000 5577.93 7900.00 55.863 41 .889 4975.29 5031.39 4215.60 N 3777.86 E 5998122.59 N 480077.15 E 0.000 5660.70 8000.00 55.863 41 .889 5031.40 5087.50 4277.22 N 3833.12 E 5998184.04 N 480132.61 E 0.000 5743.47 8100.00 55.863 41 .889 5087.52 5143.62 4338.83 N 3888.39 E 5998245.48 N 480188.07 E 0.000 5826.23 8200.00 55.~93 41 .889 5143.64 5199.74 4400.45 N 3943.65 E 5998306.92 N 480243.53 E 0.000 5909.00 8216.6arlrF 55.863 41 .889 5153.00 5209.10 4410.73 N 3952.87 E 5998317.17 N 480252.78 E 0.000 5922.81 Top Morraine ~ 8300.00 55.863 41 .889 5199.76 5255.86 4462.07 N 3998.92 E 5998368.36 N 480298.99 E 0.000 5991.77 8400.00 55.863 41 .889 5255.87 5311.97 4523.69 N 4054.18 E 5998429.80 N 480354.45 E 0.000 6074.54 8500.00 55.863 41 .889 5311.99 5368.09 4585.30 N 4109.44 E 5998491 .24 N 480409.91 E 0.000 6157.31 8600.00 55.863 41 .889 5368.11 5424.21 4646.92 N 4164.71 E 5998552.68 N 480465.37 E 0.000 6240.08 a 8700.00 55.863 41 .889 5424.23 5480.33 4708.54 N 4219.97 E 5998614.13 N 480520.83 E 0.000 6322.85 L~,?::,~ -.,,!?~] 8701.38 55.863 41 .889 5425.00 5481.1 0 4709.38 N 4220.73 E 5998614.97 N 480521.59 E 0.000 6323.99 Top HRZ ~-:,<., 8800.00 55.863 41 .889 5480.35 5536.45 4770.15 N 4275.24 E 5998675.57 N 480576.29 E 0.000 6405.62 ;~ 8900.00 55.863 41 .889 5536.46 5592.56 4831.77 N 4330.50 E 5998737.01 N 480631.75 E 0.000 6488.39 8941.94 55.863 41 .889 5560.00 5616.10 4857.61 N 4353.68 E 5998762.78 N 480655.01 E 0.000 6523.10 Base HRZ ~~ >.~ t~ 26 September, 2002 - 7:29 Page 4 of9 DrillQuest 3.03.02.002 <:::) ::l:J ~~í'rno -""'"...... ~~~~;~:;;;{I ,-\-:.....,...~-,~ ~''''''-- Sperry-Sun Drilling Services Proposal Report for Kuparuk 35 Pad - 35-09 Plan - 3s-09 (wp03) Western North Slope Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section (ft) (ft) (ft) (ft) (ft) (ft) (ft) r/100ft) 9000.00 55.863 41 .889 5592.58 5648.68 4893.39 N 4385.76 E 5998798.45 N 0.000"""" 6571.16 9100.00 55.863 41 .889 5648.70 5704.80 4955.00 N 4441.03 E 5998859.89 N 0.000 6653.93 9134.39 55.863 41 .889 5668.00 5724.10 4976.20 N 4460.04 E 5998881.02 N 0.000 6682.40 9200.00 55.863 41 .889 5704.82 5760.92 5016.62 N 4496.29 E 5998921.33 N '.000 6736.70 9246.66 55.863 41 .889 5731.00 5787.10 5045.37 N 4522.08 E 5998950.00 N 0.000 6775.32 9252.00 55.863 9285.86 55.863 9300.00 55.863 9400.00 55.863 9486.00 55.863 5790.10 5809.10 5817.03 5873.15 5921.41 5998953.28 N 5998974.09 N 5998982.77 N 5999044.22 N 5999097.06 N 4525.03 E 4543.74 E 4551.56 E 4606.82 E 4654.35 E 41 .889 41 .889 41 .889 41 .889 41 .889 5734.00 5753.00 5760.93 5817.05 5865.31 All data is in Feet (US) unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to RKB = 56.1' MSl. Northings and Eastings are relative to 2491' FNL, 974' FEl. Global Northings and Eastings are relative to NAD27 Alaska State Planes, Zone 4. The Dogleg Severity is in Degrees per 100 feet (US). Vertical Section is from.2491' FNL.974' FEL and calculated along an Azimuth of 41.818° (True). Magnetic Declination at Surface is 60° (05-Sep-02) Based upon Minimum Curvature type calculations, at a Measured Depth of 9486.00ft., The Bottom Hole Displacement is 6973.42ft., in the Direction of 41.870° (True). 26 September, 2002 - 7:29 Page 50f9 480826.96 E 480845.74 E 480853.58 E 480909.04 E 480956.74 E ConocoPhillips ment K-1 TARGET: 9246.66ft MD, 5787.1 Oft TVD (2548' FSL & 1713' FEL, Sec ; T12N-R8E) Target - 3S-09 (Geo), 150.00 F Current Target .~ 0.000 6779.74 Kuparuk 0.000 6807.76 Miluveach 0.000 6819.47 0.000 6902.24 0.000 6973.42 Total Depth: 9486.00ft MD, 5921.41 ft TVD (2585' FNL & 1580' FEL, Sec 8-T12N-R8E) 7" Casing ~ DrillQuest 3.03.02.002 c ~..,"'... ~:) ~"£-;::-)"~'bt i--- Sperry-Sun Drilling Services Proposal Report for Kuparuk 35 Pad - 35-09 Plan - 3s-09 (wp03) Western North Slope ConocoPhillips Comments Measured Depth (ft) Station Coordinates TVD Northings Eastings (ft) (ft) (ft) Comment 0.00 200.00 700.00 1846.60 3589.00 0.00 0.00 N 0.00 E 200.00 O.OON 0.00 E 697.47 32.85 N 28.55 E 1634.35 485.67 N 432.50 E 2612.15 1559.29 N 1395.42 E 5787.10 5045.37 N 4522.08 E 5921.41 5192.85 N 4654.35 E ~I SHL (2497' FNL & 974' FEL, SEC.,1¡tkT12N ~ Begin Dir @ 2.0"/100ft (in 12-1/4" Hole): 200.oð't~D, 200.00ft TVD Increase in Dir Rate @ 4.0'/100ft: 700.00ft MD, 6~f47ft TVD End Dir. Start SaU @ 55.86' : 1846.60ft MD, 1634.35ft TVD 9-5/8" Csg Pt ... Drill out 8-112" Hole: 3589.00ft MD, 2933.84ft TVD TARGET: 9246.66ft MD. 5787.10ft TVD (2548' FSL & 1713' FEL, See 8-T12N-R8E) ,Total DêmUJIfitF9486.00ft'MD, 5921.41ft TVD (2585' FNL & 1580' FEL, See 8-T12N-R8E) 9246.66 9486.00 Formation Toos Measured Vertical Depth Depth Northings Eastings Dip Up-Dip Formation Name (ft) (ft) (ft) (ft) Angle Dirn. 1700.12 1546.10 "iV}B98.68 N 354.52 E 0.000 359.818 B. Permafrost 2517.96 2011.10 899.34 N 803.52 E 0.000 359.818 T. West Sak 3310.93 2456.10 1387.95 N 1241.75 E 0.000 359.818 B. West Sak 3688.71 2668.10 1620.73 N 1450.52 E 0.000 359.818 C-80 (K-10) 6338.49 4155.10 3253.44 N 2914.90 E 0.000 0.000 C-40 (K-3) 8216.68 5209.10 5153.00 4410.73 N 3952.87 E 0.000 0.000 Top Morraine 8701.3 5481 .1'øiv 5425.00 4709.38 N 4220.73 E 0.000 0.000 Top H RZ 8941.9 5616.10 5560.00 4857.61 N 4353.68 E 0.000 0.000 Base H RZ 9134.39 5724.10 5668.00 4976.20 N 4460.04 E 0.000 0.000 K-1 9252.00 5790.10 5734.00 5048.66 N 4525.03 E 0.000 0.000 Kuparuk 9285.86 5809.10 5753.00 5069.53 N 4543.74 E 0.000 359.818 Miluveaeh .~ 26 September, 2002 - 7:29 Page 60f9 DrillQuest 3.03.02.002 a ~ ~,~."" ç~:::~ ~._,,~~"'-~ ,~~Z:'~~= ~~ Sperry-Sun Drilling Services Proposal Report for Kuparuk 3S Pad - 3S-09 Plan - 3s-09 (wp03) Western North Slope CasinQ details From Measured Vertical Depth Depth (ft) (ft) To Measured Vertical Depth Depth (ft) (ft) <Surface> <Surface> <Surface> <Surface> 9486.00 3589.00 5921.41 2612.15 TarQets associated with this wel/øath Target Name 3S-09 (DO) 26 September, 2002 - 7:29 ConocoPhillips Casing Detail 7" Casing 9 5/8" Casing .-.-; Target Entry Coord inates TVD Northings Eastings Target Target (ft) (ft) (ft) Shape Type 5787.10 5045.37 N 4522.08 E Polygon Drillers ea Level/Global Coordinates: 5731.00 5998950.00 N 480824.00 E Geographical Coordinates: 700 24' 29.8737" N 1500 09' 22.0600" W Target Boundary Point #1 5787.10 5120.15N 4515.46 E #2 5787.10 5118.55 N 4529.14 E #3 5787.10 5114.17 N 4542.14 E #4 5787.10 5107.36 N 4554.02 E #5 5787.10 5098.44 N 4564.48 E #6 5787.10 5087.64 N 4573.19 E #7 5787.10 5075.18 N 4579.70 E #8 5787.10 5061.48 N 4583.57 E #9 5787.10 5047.13 N 4584.17 E #10 5787.10 5032.93 N 4581.52 E #11 5787.10 5019.63 N 4575.80 E #12 5787.10 5007.67 N 4567.54 E #13 5787.10 4997.55 N 4557.00 E #14 5787.10 4989.59 N 4544.61 E #15 5787.10 4984.55 N 4530.67 E #16 5787.10 4982.82 N 4515.90 E #17 5787.10 4984.68 N 4501.15 E #18 5787.10 4989.73 N 4487.27 E #19 5787.10 4997.51 N 4474.85 E #20 5787.10 5007.46 N 4464.21 E #21 5787.10 5019.25 N 4455.76 E #22 5787.10 5032.51 N 4449.96 E #23 5787.10 5046.69 N 4447.20 E Page 70f9 DrillQuest 3.03.02.002 ~ Sperry-Sun Drilling Services Proposal Report for Kuparuk 3S Pad - 3S-09 Plan - 3s-09 (wp03) ConocoPhillips Western North Slope #24 5787.10 4447.73 E #25 5787.10 4451.50 E #26 5787.10 4457.84 E #27 5787.10 4466.43 E #28 5787.10 447f5':82 E #29 5787.10 4488.68 E #30 5787.10 4501.73 E #31 5787.10 4515.46 E Mean Sea Level/Global Coordinates #1 4.80 N 480817.62 E #2 .16 N 480831.29 E #3 5731.00 5999018.74 N 480844.28 E #4 5731.00 5999011 .89 N 480856.14 E .~ 5 5731 .00 5999002.93 N 480866.57 E "'2,,,5731.00 5998992.11 N 480875.25 E 5731 .00 5998979.63 N 480881.72 E #8 5731.00 5998965.91 N 480885.54 E #9 5731.00 5998951.56 N 480886.10 E #10 5731.00 5998937.37 N 480883.40 E #11 5731 .00 5998924.09 N 480877.64 E #12 5731.00 5998912.16 N 480869.34 E #13 5731.00 5998902.07 N 480858.77 E #14 5731.00 5998894.15 N 480846.36 E #15 5731.00 5998889.15 N 480832.40 E #16 5731.00 5998887.47 N 480817.62 E #17 5731.00 5998889.38 N 480802.88 E #18 5731.00 5998894.47 N 480789.02 E #19 5731.00 5998902.29 N 480776.62 E #20 5731.00 5998912.27 N 480766.01 E #21 5731.00 5998924.09 N 480757.60 E #22 5731.00 5998937.37 N 480751.84 E #23 5731.00 5998951.56 N 480749.13 E #24 5731.00 5998965.91 N 480749.70 E #25 5731 .00 5998979.63 N 480753.52 E .-...,,1 #26 5731.00 5998992.15 N 480759.90 E #27 5731.00 5999003.06 N 480768.52 E #28 5731 .00 5999012.09 N 480778.94 E #29 5731.00 5999019.05 N 480790.82 E C #30 5731.00 5999023.41 N 480803.89 E ::0 #31 5731.00 5999024.80 N 480817.62 E -....-- Geographical Coordinates #1 700 24' 30.6093" N 1500 09' 22.2526" W #2 700 24' 30.5935" N 1500 09' 21.8518" W #3 700 24' 30.5503" N 1500 09' 21.4707" W -~-.!:.o>.,.:.¡a #4 700 24' 30.4833" N 150009' 21.1226" W #5 700 24' 30.3954" N 1500 09' 20.8162" W #6 700 24' 30.2892" N 1500 09' 20.5610" W ~..---- #7 700 24' 30.1666" N 1500 09' 20.3704" W 26 September, 2002 - 7:29 Page 8 of9 DrillQuest 3.03.02.002 Q ::0 ~r-7.i:~ ~:- r--- Sperry-Sun Drilling Services Proposal Report for Kuparuk 3S Pad - 3S-09 Plan - 3s-09 (wp03) Western North Slope #24 #25 #26 #27 #28 #29 #30 #31 3S-09 (Geo) 5787.10 5731 .00 Mean Sea Level/Global Coordinates: Geographical Coordinates: Target Radius: 150.00ft 26 September, 2002 - 7:29 Page 90f9 700 24' 30.0317" N 700 24' 29.8906" N 70024' 29.7510" N 700 24' 29.6202" N 70024' 29.5027" N 700 24' 29.4Ö32" N 70° 24' 29.3249" N 700 , 2 " ~b,. 70 ' 29 " N 700 9.2769" N 700 24 66" N 00 24' 29.4032" N 700 24' 29.5011" N 700 24' 29.6172" N 70024' 29.7477" N 700 24' 29.8872" N 700 24' 30.0283" N 700 24' 30.1634" N 700 24' 30.2867" N 700 24' 30.3942" N 700 24' 30.4833" N 700 24' 30.5520" N 700 24' 30.5952" N 700 24' 30.6093" N ConocoPhillips 1500 09' 20.2574" 1500 09' 20.2399" 150009' 20.31801' 1500 09' 20.4858" W 150009' 20.7282" W 15qo 09' 21.0372" W 150009' 21.4004" W 1500,,09' 21.8092" W 1500 09' 22.2423" W 1500 09' 22.6744" W 1500 09' 23.0811" W 1500 09' 23.4451" W 1500 09' 23.7568" W 1500 09' 24.0042" W 150009' 24.1740" W 1500 09' 24.2546" W 1500 09' 24.2389" W 1500 09' 24.1280" W 1500 09' 23.9419" W 1500 09' 23.6901" W 1500 09' 23.3854" W 1500 09' 23.0377" W 1500 09' 22.6549" W 1500 09' 22.2526" W ~ 5045.37 N 4522.08 E 5998950.00 N 480824.00 E 700 24' 29.8737" N 1500 09' 22.0600" W Circle Current Target '~ DrillQuest 3.03.02.002 š §! 5000- 1/ .<: C.: ::::¡:, ~ ~ çJ --....,- ..~ ConocoPhillips 0-." / SHL (2497' FNL & 974' FEL, SEC. 18- T12N - R8E) ~ Begin Dir @ 2.00/100lt (in 12-1/4" Hole): 200.00lt MD, 200.00lt TVD 1000 - L"ó>~<) ~ ------ Increase in Dir Rate @ 4.00/100lt : I 700.0011 MD, 697.47ft TVD I 2000 ::J en ~ ¥~> ~,...............~ ~ <Ó 1.0 II m ~ ~ .I::. ã. Q) Q (i'j u t Q) > 3000 - 4000 - Western North Slope, Alaska Kuparuk River Unit 35 Pad 35-09 (wp03) 0 , ! 3000 I Total Deplh : 9486.00lt MD, 5921.4111 TVD (2585' FNL & 1580' FEL, See 8-T12N-R8E) Eastings 1500 I 4500 - Well: Current Well Properties 3S-09 Plan õ g II 13 ~ Horizontal Coordinates: Ref. Global Coordinates: 5993919.00 N, 476285.94 E Ref. Structure: 75.46 N, 169.30 W Ref. Geographical Coordinates: 70° 23' 40.2619" N, 150° 11' 34.6045" W 2497' FNL & 974' FEL, SEC. 18- T12N - R8E <ó ri (f) 3000 - RKB Elevalion : North Reference: Units: 56.10ft above Mean Sea Level True North Feel (US) 1500 - 9-5/8" Csg PI... Drill out 8-1/2" Hole : 3589.0011 MD, 2933.8411 TVD End Dir, Start Sail @ 55.86°: 1846.6011 MD, 1634.3511 TVD 4500 I - 4500 JS-O.9 (G('o-Poly) Circle, RadÌl~'i: 150.lHift 5fi4S.37 N. 4522.IJ8 E @5787.16 TH/, - 3000 C/) C> c :c 1::: 0 Z ~' - 1500 ! i i Increase in Dir Rate @ 4.0°/10011 : 700.00lt MD, 697.4711 TVD 0 ~ ; -B~in Dir @ 2.;;:/10011 (in 12~14" Hole): 2;0.00lt MD, 2;0.00lt TV~ - - - --- - - 0 I ! SHL (2497' FNL & 974' FEL, SEC. 18- T12N - R8E) I 0 I 1500 I 3000 ~~"""'--~-~--~~._~~~~~~ Reference is True North ,,-,' I 4500 spef1'-''Y-!5ur,1 q .~:lh.Ç).~:g'--~..$..E::Et~9:rç..e: ..$ A.N.3Mj.~ ~W(f ...... ~........ ~ ~ -~ -~ -........- ~ ...~~~ ~......... ~ ~ ~~ ~~ - _.~....... ~.....,.. 6000 - Tolal Deplh: 9486.00lt MD, 5921.4111 TVD (2585' FNL & 1580' FEL, Sec 8- T12N-R8E) 7'Csg 9486.00' MD 5921.41' TVD I 1000 I 2000 I 6000 I 7000 I I I I 0 ~''''''''~ Scale: 1 inch = 1 00011 I 3000 I 4000 I 5000 Drill Quest 3.03.02.002 CJ) COnfOCOPhilliPS Alaska, Inc. 38-09 MD Inc Azim. SSTVD TVD N/S E/W Y X DLS V.S. Comment (ft) (Deg) (Deg) (ft) (ft) (ft) (ft) (ft) (ft) e 11 OOft} (ft) 0.00 0.00 0.00 -56.10 0.00 0.00 N 0.00 E 5993919.00 N 476285.94 E 0.00 0.00 SHL ~ 200.00 0.00 0.00 143.90 200.00 0.00 N 0.00 E 5993919.00 N 476285.94 E 0.00 0.00 Begin Dk in 12-114" Ho!e 700.00 10.00 41.00 641 .37 697.47 32.85 N 28.55 E 5993951 .76 N 476314.60 E 2.00 43.52 Increase in Dir Rate @ 4.0o/100ft 1700.13 50.00 41.86 1490.00 1546.1 0 398.68 N 354.52 E 5994316.56 N 476641.72 E il:ro 533.50 B. Permafrost 1846.60 55.86 41.89 1578.25 1634.35 485.67 N 432.50 E 5994403.30 N 476719.98 E 4.00 650.33 End Dír 2517.96 55.86 41.89 1955.00 2011.10 899.34 N 803.52 E 5994815.79 N 477092.31 E 0.00 1206.01 T. West Sak 3310.93 55.86 41.89 2400.00 2456.10 1387.95 N 1241.75 E 5995303.00 N 477532.09 E 0.00 1862.35 B. West Sak 3589.00 55.86 41.89 2556.05 2612.15 1559.29 N 1395.42 E 5995473.85 N 477686.30 E 0.00 2092.51 9-5/8" Csg pt ... Dri!! 8-1/2" Hole 3688.71 55.86 41.89 2612.00 2668.10 1620.73 N 1450.52 E 5995535.12 N 477741.60 E 0.00 2175.03 C-80 (K-10) 6338.49 55.86 41.89 4099.00 4155.10 3253.44 N 2914.90 E 5997163.18 N 479211.15 E 0.00 4368.24 C-40 (K-3) 8216.68 55.86 41.89 5153.00 5209.10 4410.73 N 3952.87 E 5998317.17 N 480252.78 E 0.00 5922.81 Top Morraíne 8701 .38 55.86 41.89 5425.00 5481.10 4709.38 N 4220.73 E 5998614.97 N 480521 .59 E 0.00 6323.99 Top H RZ 8941 .94 55.86 41.89 5560.00 5616.10 4857.61 N 4353.68 E 5998762.78 N 480655.01 E 0.00 6523.11 Base H RZ 9134.39 55.86 41.89 5668.00 5724.10 4976.20 N 4460.04 E 5998881.02 N 480761.74 E 0.00 6682.40 K-1 9246.66 55,86 41.89 5731.00 578T i 0 5045.37 N 4522.08 E 5998950,00 N 480824,00 E 0,00 6775.32 TARGET 9252.00 55.86 41.89 5734.00 5790.10 5048.67 N 4525.03 E 5998953.29 N 480826.97 E 0.00 6779.74 Kuparuk 9285.86 55.86 41.89 5753.00 5809.10 5069.53 N 4543.74 E 5998974.09 N 480845.74 E 0.00 6807.77 M iluveach 9486.00 55.86 41.89 5865.31 5921.41 5192.85 N 4654.35 E 5999097.06 N 480956.74 E 0.00 6973.42 T ota! Depth ........".,. ) Sperry-SUD Anticollision Report ') CO~P:mŸ: FMd: Reference Site: Reference Well: Iteferëi1ëê~ellpåth: Phillips Alaska lnc, Kuparuk Ri\l~rUrïit KLlparuk3S.pad Plän:3S-09 Plän:38~09 9126/2002 GLOBAL SCAN APPLIED: All well paths within 200'+ 100/1000 of reference Interpolation Method: MD Interval: 50.000 ft Depth Range: 28.100 to 9486.000 1t Maximum Radius: 1145.790 ft Reference: Error Model: Scan Method: Error Surface: Db; Oracle Principal Plan & PLANNED PROGRAM 18CW 8A Ellipse Trav Cylinder North Ellipse + Casing Survey Program for Definitive Wellpath Date: 5/14/2002 Validated: No Planned From To Survey 1t 1t 28.100 500.000 500.000 9486.000 Version: Toolcode Tool Name Planned: 38-09 (wp03) V6 Planned: 38-09 (wp03) V6 CB-GYRO-8S MWD Camera based gyro single shot MW D - 8tandard Casing Points MD TVD 1t ft 3589.000 2612.076 9486.000 5921.087 Diänídër in 9.625 7.000 Hole Size in Name 12.250 8.500 9-518" 7" Summary Rëfërence Offset Ctr~Ctr No~(,TO Allowable MD MD DiStaiicë . Areå Deviåtion Warning ft ft ft ft ft Kuparuk 3S Pad Plan: 38-01 Plan 3S-01 V2 Plan: 31 513.548 500.000 162.557 10.032 152.572 Pass: Major Risk Kuparuk 38 Pad Plan: 38-02 Plan: 38-02 V2 Plan: 3 511.150 500.000 141.004 9.646 131.387 Pass: Major Risk Kuparuk 38 Pad Plan: 3S-02 Plan: 3S-02F V2 Plan: 511.150 500.000 141.004 9.646 131.387 Pass: Major Risk Kuparuk 38 Pad Plan: 38-03 Plan: 38-03 V2 Plan: 3 559.480 550.000 118.723 10.082 108.682 Pass: Major Risk Kuparuk 38 Pad Plan: 38-06 Plan: 38-06 V2 Plan: 3 454.150 450.000 62.190 9.123 53.098 Pass: Major Risk Kuparuk 38 Pad Plan: 38-06 Plan: 38-06F V2 Plan: 454.150 450.000 62.190 9.123 53.098 Pass: Major Risk Kuparuk 38 Pad Plan: 38-07 Plan: 3S-07 V3 Plan: 3 603.298 600.000 35.922 10.803 25.231 Pass: Major Risk Kuparuk 38 Pad Plan: 38-08 Plan: 3S-08 V2 Plan: 3 501.806 500.000 23.040 10.477 12.626 Pass: Major Risk Kuparuk 38 Pad Plan: 38-08 Plan: 38-08F V2 Plan: 501.806 500.000 23.040 10.477 12.626 Pass: Major Risk Kuparuk 38 Pad Plan: 38-10 Plan: 38-10 V1 Plan: 3 448.540 450.000 22.847 9.591 13.272 Pass: Major Risk Kuparuk 38 Pad Plan: 38-10 Plan: 38-10F V3 Plan: 448.540 450.000 22.847 9.591 13.272 Pass: Major Risk Kuparuk 38 Pad Plan: 38-14 Plan: 38-14 V1 Plan: 3 297.233 300.000 101.275 6.290 94.985 Pass: Major Risk Kuparuk 38 Pad Plan: 38-15 Plan: 38-15 V1 Plan: 3 248.356 250.000 120.495 5.343 115.151 Pass: Major Risk Kuparuk 38 Pad Plan: 38-16 Plan: 38-16 V1 Plan: 3 248.093 250.000 140.530 5.175 135.354 Pass: Major Risk Kuparuk 38 Pad Plan: 38-17 Plan: 38-17 VO Plan: 3 247.830 250.000 160.644 5.142 155.503 Pass: Major Risk Kuparuk 38 Pad Plan: 38-17 Plan: 38-17F V1 Plan: 247.830 250.000 160.644 5.079 155.565 Pass: Major Risk Kuparuk 38 Pad Plan: 3S-18 Plan: 38-18 V3 Plan: 3 247.577 250.000 180.338 5.242 175.096 Pass: Major Risk Kuparuk 38 Pad Plan: 38-19 Plan 38-19F V2 Plan: 3 247.317 250.000 200.722 5.095 195.627 Pass: Major Risk Kuparuk 38 Pad Plan: 38-19 Plan: 38-19 V1 Plan: 3 247.317 250.000 200.722 5.095 195.627 Pass: Major Risk Kuparuk 38 Pad Plan: 38-20 Plan: 38-20 V1 Plan: 3 247.062 250.000 220.700 4.947 215.753 Pass: Major Risk L1 L 0 ~~ ~.... ~-:) ~- ~---- WELL DbTAlLS COMPANY DETAILS WEl.LP A TH DETAILS Plan: 35-09 ANTI-COLLISION SETnNGS Name Plan: 3S.09 +FJ-W Longitude Sui Phillip, Alaska Inc. Engineering Kuparuk Caru1ation Method: Minûnum Curvature EITOr System: ISCWSA Scan Method: Tmv Cylinder North wa~:: ~~~~~~ ~~B~;ci&~mg O.lX)() Northing Easting Latitude +NI-S Interpolation Method:MD Interval: 50.000 Depth Range From: 28.100 To: 9486.000 Maximum Range: 1145.790 Reference: Plan: 3S-09 (wp03) 56.JOOfI Rig: Ref. Datum: 476285.94 70'23'40.262N 151r 11'34,605W N/A N7ES 56.1 7(,.008 .169,077 5993919.00 V.Section Angle 4 J.57' Origin +N/-S Origin +FJ-W Starling From TVD 0.000 0.000 SURVEY PROGRAM Colour ToMD 200 400 600 800 1000 1200 1400 1600 1800 2000 2500 3000 3500 4000 5000 6000 7000 8000 9000 From Colour ToMD Tool 0 -~ 200 200- 400 CB-GYRO-SS 400 - 600 600 800 MWD 800 - 1000 1000 --- 1200 1200 - 1400 1400 - 1600 1600 1800 1800 - 2000 2000 2500 2500 - 3000 -36 3000 3500 3500 - 4000 4000 - 5000 5000 - 6000 -30 6000 ~ 7000 7000 - 8000 8000 - 9000 ".'20 ........... -174 Depth Fm Depth To SurveylPlan 28.100 500.000 Planned: 3S-09 (wp03) V6 500.000 9486.000 Planned: 3S-09 (wp03) V6 0 -150 ..'100 -50 -0 -50 -10 \'\~.~.~~.~ . " ". " '."20 (// -----.-',/ .^:// '.......ø ..._.~./ -30 -36 18tt~ SECTION DETAILS See MD Ine Azi TVD +N/.S +E/.W DLeg TFaee VSec Target 1 28.1 00 0.00 0.00 28.100 0.000 0.000 0.00 0.00 0.000 2 200.000 0.00 0.00 200.000 0.000 0.000 0.00 0.00 0.000 3 700.000 10.00 41.00 697.465 32.847 28.553 2.00 41.00 43.520 4 1846.693 55.87 42.07 1634.407 484.638 433.756 4.00 1.24 650.392 5 9247.221 55.87 42.07 5787.100 5031.500 4538.511 0.00 0.00 6775.754 35 (9) 6 9486.000 55.87 42.07 5921.087 5178.205 4670.951 0.00 0.00 6973.389 "'.100 -150 -174 3S..09 (wp03) Approved Plan Travelling Cylinder Azimuth (TFO+AZI) [deg] vs Centre to Centre Separation [100ft/in] Travelling Cylinder Azimuth (TFO+AZI) [deg] vs Centre to Centre Separation [20ft/in] ) Site: Kuparuk 3S Pad Well: Plan: 3S-09 Dri11ing Target Conf.: 75% Based on: Plan: 3S-09 (wp03) Description: Vertical Depth: 5731.00 ft below Mean Sea Level Map Northing: 5998950.00 ft Local +N/-S: 5031.50 ft Map Easting: 480824.00 ft Local +FJ-W: 4538.51 ft Latitude: 70024'29.874N Longitude: 150009'22.060W Shape: Circle Radius: 150 ft ='......I......I.......I......I....J......'..J......\......1.......1......'......1....1......'.......1.......I......!......I......'......I...I......I......I.....I.......!.....I......[....I.......I......I..J......1......I....I......I.....I......'......I....J......I....:......1......1...1.....1.....1....'.......1.....1......I.......!....'......I....I..I......I.....:......I......:..I......'......I..../......I......I.....!....I.......I......!.....I.....'.....I.......I......!....I......1...:......l......!..I.....I...I.......I.....\......:......!.......:.......I......)......:.....I......:......\......I......I......f......!....I......'..............I......I......I......I......I.....!......\......I......'......!.....I.....!......I......\......I....I....:t1......I.....i.....\..........'.......I....I......I.. - .L~OO H~O 4:qO -060 4.~¡;:0 ~400 Ü10 .¡.wo 4-160 -U¡;;O ~~OO 4~'~O ~,":-10 4."60 4:'i'O 4(j()() 46~O 4640 -1660 -1680 -1700 -1710 47.JO '¡760 411'°:t -5~f)1) _.- ---u _._..----_m- .-_u -.. :'_~OO-i: ') Target: 38 (9) ~ =-:"::!8e-------- ~..---~-~--~~._- ---.. -~---'__~_-A ----~~28Ü-: 52,60--+ =-52~- ""I' , , ..;.. -5230..- . ~.. 52~O-+ :J ..S2f~ =-52~. .,.. , .,. , I 5100-j . I. . -:"200 -51~--:- . + -. -.-.-... .-- --._- .--. -... . o. - - ~_._. ..-....__.. ... - c-- - .-s.J8{}--f -:-5060. . ......~......... -.---.- - -" - -- ---. --_.~----51W-; ..,j I . i . I I ,= -i"--~-51~1 --¡-~~ ¡ -1 I . 5 loo---=i --, -i -1 - 508~ ...., =-5160-----, --- : .- - -- - . . =--5+4(}--~--:- -5100 . -50~O ..¡... .t. ...OF" . . i. -.1.- ..1.. -.,... - 506O-j --i :+ =-5040.. . _.~ ... -..-. -. - ,. . 0 .~ ~ -5000----- -; - .5---- en -- .L . , . . - 5040--=1 , ::J -5020 . I I , I I 50~0-=1 I = I ~ --. SOÞ<H I -: -4900- - .- ~- _"0 ---- -. 'r ----.-. .- --- I ....: . 4C):8~ ~ 1--'---1~ ¡ -; -- -- ---:-------:----~-4%H , I t --j , I j . , . . _.'\~ _. -- n " '-.., "~~_. ---------------------- - ------ .---- - --- -- ----- ~ / / / ,/ ~/ - ---. --- --- - ---.. - --- .~CNO- -'¡9~}- --1920 ~9~o- -4900. . .4900-= ~8~--h-~-~-~~--~--~~-,---r,,-,-: West(-)~ï(+) Ift] . . . ~1$.- ----;---_:- ----~---~ -------- - ,- ---~--- --'--------:- ~ ---:--------- -- -.4789--: .16Œ...,........,....¡... . 4300 ' p 4:52 Ii ¡rlFII.rF¡TTTlciTrITrTII"TTrl ) ') 35-09 Drillina Hazards Summary 12-1/4" Hole / 9-5/8" Casing Interval Event Broach of Conductor Gas Hyd rates Gravel/Sand Sloughing to 500' Hole Swabbing/Tight Hole on Trips Possible thaw bulb / water flow around 1200' Lost Circulation I Risk Level I Mitigation Strategy Low Monitor cellar continuously during interval. Low Moderate Moderate Low Low 8-1/2" Hole / 7" Casina Interval Event Shale stability in HRZ, K-1, and Miluveach High ECD and swabbing with higher MW's required Barite Sag Differential Sticking Abnormal Reservoir Pressure Lost Circulation Risk Level Low Moderate Low Moderate Moderate I Moderate If observed - control drill, reduce pump rates, reduce drilling fluid temperatures, Additions of Drilltreat. Increase mud weight / viscosity, High viscosity sweeps. Monitor fill on connections Circulate hole clean prior to trip. Proper hole fill (use of trip sheets), Pumping out of hole as needed. Watch return viscosity for signs of thinning. Increased mud weight/viscosity as needed. Prevent by keeping hole clean. If losses occur - reduce pump rates and mud rheology, use LCM M iti~ation Strateqy Control with higher MW and proper drilling practices. Condition mud prior to trips. Monitor ECD's with PWD tool while drilling across pay interval. Pump and rotate out on trips as a last resort. Good drilling practices as documented in well plan. Periodic wiper trips. Do not leave pipe static for extended period of time. Follow mud weight schedule and do not fall behind. Stripping Drills, Shut-in Drills, PWD Tools, Increased mud weight as needed. Ensure adequate kick tolerance prior to drilling pay interval. Use PWD to monitor hole cleaning. Reduced pump rates, Mud rheology, LCM. Use GKA LC decision tree. 3S-09 Drilling Hazards Summary. doc prepared by Scott Lowry 7/30/02 0 ryPa~e,1¡ 11 ,:;jf\ ,. llzri\~ KRU - 38-09 InjE.lor Proposed Completion Schematic Single Completion 16"x30" insulated I I i conductor @ I ~ ~ +1- 109' MD I I ~ I I I TAM 9-5/8" porttM. d ~ Collar Stnd §I ~ Grade BTC . ~ Threads (+/- tJ ~ 1000'MD/TVD) ~ I I ~ I ~ Surface csg. I ~ 9-5/8"40# L-80 ....ILl I BTC (3589' MD / ~ 2612' TVD) ~ Casing point I 100' above the I ¡ C80 sand ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ I ~ ~ ~ ~ ~ ~ ~ ~ I I I I ~ I I ~ I ~ ~ ~ ~ ~ ~ ~ I ~ ~ ~ ~ ~ ~ j r- - Ii---' ".-.-¡' (--.. ._--~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ J .J-::tm~m:ml ~ :r P3 :a ~ I ~ ~ I ~ ~ Z ~ I I I r i ~ I I L.... UI ~~ Ir I i ~ ~ ~ I ~ I ~ i I i ~~ ~ I ~ ~ ~ I I I I ~ ~ ~ I ~ ~ ~ I I ~ I ~ I I ~ ~ ~ ~ ~ I ~ ~ ~ I ~ I I ~ ~ ~ ~ ~ I I I ~ I I I I I ~ I - C Sand Perfs (to be done after rig moves off) ~ ~ ~ I ~ I ~ ~ I ~--''--' Production csg. 7" 26# L -80 BTCM (+1- 9486' MD) 3-1/2" FMC Gen V tubing hanger, 3-1/2" L-80 EUE8RD pin down. Special Drift 2.91" 3-1/2", L-80, 9.3# EUE8RD Spaceout Pups as Required. Special Drift 2.91" 3-1/2" Camco DS Landing Nipple with 2.875" ID No-Go profile set @+I- 500' MD. Use of port collar at the discretion of the drilling team. / 3-1/2" x 1-1/2" 'MMG' GLM w/ DCR Dump Kill Valve (3000 psi casing to tubing shear). 6' L-80 handling pups installed on top and bottom of mandrel. 1 Joint 3-1/2", L-80, 9.3# EUE 8rd Mod Tubing. 3-1/2" Camco 'DS' nipple w/2.813" No-Go profile 1 Joint 3-1/2", L-80, 9.3# EUE 8rd Mod Tubing. 6' Handling Pup Joint 3-1/2", L-80, 9.3# EUE 8rd Mod Tubing. Baker '80-40' PBR. Baker 7" x 3-1/2" 'SA B-3' Permanent Packer set +1- 100' MD above top planned perf. Minimum ID through the packer 3.00". 6' Pup Joint 3-1/2", L-80, 9.3# EUE 8rd Mod Tubing. 3-1/2" Camco 'D' nipple w/2.75" No-Go profile. 6' Pup Joint 3-1/2", L-80, 9.3# EUE 8rd Mod Tubing. Baker 3-1/2" WL Re-entry Guide wI shear out sub. Tubing tail 50' above top planned perforation. TD @ 9,486' MD I 5921' TVD (200' MD below Miluveach) Scott L Lowry 9/5/02 0.... ...~.. .,;.(::s,~.'......Œ.; ....~,...",..,..,.,f¡ ,.' { ..; ~;:{ { r, ~1 N 3 '1') f ~ &i1J . , iI, ---eu.~~~.~ooo;o:o ::::~þ¡¡,:; oOO::oooDOLLAâSßLOS:;;;: lqØþf~~~~~~:~,~,¥~~~,,,...\I¡d~û~ÎøõOÓO~laf$ f :ø 3S~~'iii~}i4_;~~.~..: .,.: 0 :i . . DO.I.tI.t.:2.SDOE1OI.t2?2S?u'.OOIt.. .. ... ...........,'drii ..!" ~~~~_I~w~¡r,~i~......~. '¡'~¡¡¡¡JRIil 11III1i'o.Wijlj. jíj!ã~ " ".."-'kr""''''¡¡Ü 'f~~l\1i~rl?i~""'ft;' UNIVERSAl. .~ RI€EIVED OCT 0 1.2002 Alast<aM& GasGons. commtsslon . AncftOl8ge ) ') TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERlPARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME /(¿q . 3.Ç oJçt:5 ? PTD# 2/2-- Zçz5.5" CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) PILOT (PH) HOLE SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07110/02 C\jody\templates "CLUE" The permit is. for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function. of the original API number. stated above. In accordance with 20 AAC 25.005(t), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (SO 70/80) from records, data and logs acquired for well (name on permit). . The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. WELL PERMIT CHECKLIST COMPANY ~1/1!5 WELL NAME ~Rb( PROGRAM: Exp ---- Dev A Redrll- Re-Enter - Serv - Wellbore seg- FIELD & POOL- ;7'.90/0 <:::I INIT CLASS .ot::uJ /-f""}//"¡' it" GEOL AREA ?l ~ UNIT# ///6ð ON/OFF SHORE.Q....N ADMINISTRATION 1. Permittee attached. . . . . . . . . . . . . . . . . . . . . . . ~N 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . N /) ¡." J ~ ¡J rri' f 3. Unique well name and number. . . . . . . . . . . .. . . . . Y N *- ¡-'e;. A1 .1'.5' OA..J /4~fI.,.ji....J(Þr~ ,Jy\ c) J 4. Well located in a defined pool.. . . . . . . . '.' . . . . . . . ~N ..;/ b L? .. \ ! -.£>f) 5. Well located proper distance from drilling unit boundary. ... . ...... u, [8. ;c::::. ~L)ð.rG,? /\ I~JP--r ~) I ~ J - /VJ6 6. Well located proper distance from other wells.. . . . . . . . . / r 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . N ~Æ ..ú /. :/ 8. If deviated, is well bore plat included.. . . . . . . . . . . . . .'. N .~ u. --r/ ~.. II / / / -L I ~~ ~ó.2.. 9. Operator only affected party.. . . . . .. . . . . . . . . . . .¥ N;Jf"""'" /',f ¡:;,.t1e.A /'t,~/ A~ r~VJL)qr7'<, 7'0 .)'.-/'(,/) rAG 10. Operator has appropriate bond in force. . . .. . . . . . . . . N / CY .:¡ /ì -I' / / ' J J (1 11. Permit can be issued without conservation order. . ..' .. . . . N r. / Q..L -r- ~ 7r-e.r ,..--'t) 1'7 .. L ("j ~..r ~~.p...., ¿¿.cr,. ¡ 17~ 1ð' 12. Permit can be issued without administrative approval.. . . . . Y N . ..:Â/ h / - / '/ .£//)/ (Service Well Only) 13. Well located wlin area & strata authorized by injection order#~ -yy. NI' A v l<1G /:;/.... l'". & --..At..~/r:~ (¡on- /}r~ . (Service Well Only) 14. All wells wlin 'Xi mile area of review identified. . . . . . . . .. ~ N ENGINEERING 15. Conductor string provided. . . . . . . . . . . . . . . . . . . ~N 16. Surface casing protects all known USDWs. . . . . . . . . . . N 17. CMT vol ádequate to circulate on conductor & surf csg. . . . . . .. N .. -l.. 18. CMT vol adequate to tie-in long string to surf csg. . . . . . . . ~y 6) FI/C.~~.. .. ~ À.Vo 19. CMT will cover all known productive horizons. . . . . . . . . . N 20. Casing designs adequate for C, T, B& permafrost. . .. . . . N. 21. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . - N 'Ú4rb O'Y ~ 16<;' 22. If a re-drill, has a 10-403 for abandonment been approved. . . -¥-N"" 11I/Æ- 23. Adequate wellbore separation proposed.. . . . . . . . . . . . N 24. If diverter required, does it meet regulations. . . . . . . . . . N 25. Drilling fluid program schematic & equip list adequate. . . . . N t41 &../If P11A1 /1.., ~ P ¡? J ' 26. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . N. J tJ. , APPR DATE 27. BOPE press rating appropriate; test to 5000 psig. N I1/l Sf 2 7'5 I pç, ' , 28. Choke manifold complies wlAPI RP-53 (May 84). . . . . . . . N \ti6/t-- it {¡ ~ {D 1.. 29. Work will occur without operation shutdown. . . . . . . . . . . 30. Is presence of H2S gas probable... . . . . . . . . . . . . . . 31. Mechanical condition of wells within AOR verified. . . . . . . . 32. Permit can be issued wlo hydrogen sulfide measures. . . . . 33. Data presented on potential overpressure zones. . . . . . . . 34. Seismic analysis of shallow gas zones. . . . . . . . . . . . . 35. Seabed condition survey (if off-shore). . . . . . . . . . . . . . 36. Contact namelphone for weekly progress reports. . . . . . . . APPR DATE (Service Well Only) GEOLOGY APPR DATE ~~ /ò~~?- (Exploratory Only) Y <¥-tf /'.i/ A- ~ IV.A. GEOLOGY: RPe<?'C PETROLEUM ENGINEERING: TEM RESERVOIR ENGINEERING JDH Comments/lnstructions: SFD WGA /. Rev: 07/12/02 G:\geology\permits\checklist.doc UIC ENGINEER JBR COMMISSIONER: COT ~""/o z.. DTS 1/1 /~;¡O;; ¡ 1- ""'-8.- I'/U./ðz.. MJW ) Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process. but is part of the history file. To improve the readability of the Well History file and to simpltfy finding information. information of this nature is accumulated at the end of the file under APPEN.DIX. No special effort has been made to chronologically organize this category of information. Sperry-Sun Drilling Services LIS Scan Utility $Revision: 3$ LisLib $Revision: 4 $ Tue Mar 25 15:24:02 2003 Reel Header Service name.............LISTPE Date.....................03/03/25 Origin...................STS Reel Name................UNKNOWN Continuation Number......Ol Previous Reel Name.......UNKNOWN Comments. . . . . . . . . . . . . . . . . STS LIS Tape Header Service name.............LISTPE Date.....................03/03/25 Origin...................STS Tape Name. . . . . . . . . . . . . . . . UNKNOWN Continuation Number......Ol Previous Tape Name.......UNKNOWN Comments.................STS LIS Physical EOF Comment Record TAPE HEADER Kuparuk River Unit MVm/MAD LOGS # WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: # JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RUN 1 MW2219300000 P. ROGER D. BURLEY # SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: MSL 0) # WELL CASING RECORD Writing Library. Scientific Technical Services Writing Library. Scientific Technical Services 3S-09 501032043200 Conoco Phillips Sperry Sun 21-MAR-03 Alaska, Inc. MWD RUN 2 MW2219300000 P. SMITH D. BURLEY 18 12N 8E 2497 974 .00 56.50 27.70 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 12.250 16.000 108.0 8.500 9.625 3504.0 # REMARKS: 1. ALL DEPTHS ARE MEASURED DEPTH (MD) UNLESS OTHERWISE NOTED. 2. ALL VERTICAL DEPTHS ARE TRUE VERTICAL DEPTH (TVD). 3. MWD RUN 1 IS DIRECTIONAL WITH DUAL GAMMA RAY (DGR) aOdrdOS I Il.o lÐ 1.0 ) ') UfrILIZING GEIGER-MUELLER TUBE DETECTORS. 4. MWD RUN 2 IS DIRECTIONAL WITH DGR, AND ELECTROMAGNETIC WAVE RESISTIVITY PHASE-4 (EWR4). 5. MWD DATA ARE CONSIDERED PDC PER GKPA GEOSCIENCE GROUP. CNP DATA ARE CALCULATED USING THE SLD 'CALIPER' FOR HOLE SIZE INDICATION. 5. MIriTD RUNS 1,2 REPRESENT WELL 3S-09 API#:50-103-20432-00. THIS WELL REACHED A TOTAL DEPTH ('I'D) OF 9650'MD I 6020'TVD. SROP = SMOO'l'HED RATE OF PENE'l'RATION WHILE DRILLING. SGRC = SMOOTHED GAMMA RAY COMBINED. SEXP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (EXTRA SHALLOW SPACING) . SESP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (SHALLOV~ SPACING) . SEMP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (MEDIUM SPACING) . SEDP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (DEEP SPACING) . SFXE = SMOOTHED FORMATION EXPOSURE TIME (DEEP RESISTIVITY) . SPSF = SMOOTHED NEUTRON POROSITY (SANDSTONE MATRIX, FIXED HOLE SIZE). SNFA = SMOOTHED AVERAGE OF FAR DETECTOR'S COUNT RATE. SNNA = SMOOTHED AVERÄGE OF NEAR DETECTOR'S COUNT RATE. SBD2 = SMOOTHED BULK DENSITY-COMPENSATED (LOIriT-COUNT BIN) . SC02 = SMOOTHED STANDOFF CORRECTION (LOW-COUNT BIN). SNP2 = SMOOTHED NEAR DETECTOR ONLY PHOTOELECTRIC ABSORPTION FACTOR (LOW-COUNT BIN). SLDSLIDE = NON-ROTATED INTERVALS ACCOUNTING FOR BIT-TO-SENSOR DISTANCE. PARAMETERS USED IN POROSITY LOG PROCESSING: HOLE SIZE: SLD CALIPER DATA (BIT MUD ~'JEIGHT: 12.3 PPG HUD SALINITY: 200 PPM CHLORIDES FORMATION WATER SALINITY: 25000 FLUID DENSITY: 1.0 Glce MATRIX DENSITY: 2.65 Glec LITHOLOGY: SANDSTONE SIZE 8.5") PPM CHLORIDES $ File Header Service name.............STSLIB.OOl Service Sub Level Name... Version Number...........1. 0.0 Date of Generation.......03/03/25 Maximum Physical Record..65535 Fi 1 e Type................ LO Previous File Name.......STSLIB.OOO Comment Record FI LE HEADER FILE NUMBER: EDITED MERGED MWD Depth shifted and DEPTH INCREMENT: # FILE SUMMARY PBU TOOL CODE GR ROP 1 clipped curves; all bit runs merged. .5000 START DEPTH 51. 5 108.5 STOP DEPTH 9612.5 9650.0 ) ) NPHI NCNT NCNT FET RPD RPM RPS RPX PEF DRHO RHOB $ 3400.5 3494.0 3494.0 3494.0 3494.0 3494.0 3494.0 3494.0 3494.0 3505.0 3505.0 9560.0 9560.0 9560.0 9604.5 9604.5 9604.5 9604.5 9604.5 9569.0 9569.0 9569.0 # BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH $ # MERGED PBU MWD MWD $ DATA SOURCE TOOL CODE BIT RUN NO MERGE TOP 1 52.0 2 3515.0 MERGE BASE 3515.0 9650.0 # REMARKS: MERGED MAIN PASS. $ # Data Format Specification Record Data Record Type..................O Data Specification Block Type.....O Logging Direction.................Down Optical log depth units...........Feet Data Reference Point..............Undefined Frame Spacing..................... 60 .1IN Max frames per record.............Undefined Absent value..................... .-999.25 Depth Units....................... Datum Specification Block sUb-type...O Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD FT/H 4 1 68 4 2 GR MWD API 4 1 68 8 3 RPX MWD OHMM 4 1 68 12 4 RPS MWD OHMM 4 1 68 16 5 RPM MWD OHJVlM 4 1 68 20 6 RPD MWD OHMM 4 1 68 24 7 FET MWD HOUR 4 1 68 28 8 NPHI MWD PU-S 4 1 68 32 9 FCNT MWD CNTS 4 1 68 36 10 NCNT MWD CNTS 4 1 68 40 11 RHOB MWD GICM 4 1 68 44 12 DRHO MWD GICM 4 1 68 48 13 PEF MWD B/E 4 1 68 52 14 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 51. 5 9650 4850.75 19198 51.5 9650 ROP MWD FT/H 0 537.96 168.907 19084 108.5 9650 GR MWD API 15.18 426.06 101.479 19123 51. 5 9612.5 RPX l'1WD OHl'1M 0.72 1723.45 5.59336 12222 3494 9604.5 RPS MWD OHMM 0.61 2000 5.78772 12222 3494 9604.5 RPM MWD OHMM 0.61 1639.66 5.88932 12222 3494 9604.5 RPD MWD OHMM 0.33 2000 8.80711 12222 3494 9604.5 FET MWD HOUR 0.16 73.3012 0.952539 12222 3494 9604.5 NPHI MWD PU-S 4.17 86.45 48.1529 12320 3400.5 9560 FCNT MWD CNTS 409 1139 588.086 12133 3494 9560 NCNT MWD CNTS 2126 3800 2571. 26 12133 3494 9560 RHOB MWD GICM 2.029 3.104 2.30524 12129 3505 9569 DRHO MWD G/CM -0.254 0.461 0.0578992 12129 3505 9569 PEF MWD B/E 2.05 12.28 3.73741 12151 3494 9569 ) First Reading For Entire File..........51.5 Last Reading For Entire File...........9650 File Trailer Service name.............STSLIB.001 Service Sub Level Name... Version Number...........l.O.O Date of Generation.......03/03/25 Maximum Physical Record..65535 File Type................ LO Next File Name...........STSLIB.002 Physical EOF File Header Service name.............STSLIB.002 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......03/03/25 Maximum Physical Record..65535 File Type................LO Previous File Name.......STSLIB.OO1 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREJVIENT: # FILE SUJVIMARY VENDOR TOOL CODE GR ROP $ 2 ) header data for each bit run in separate files. 1 .5000 START DEPTH 51. 5 108.5 STOP DEPTH 3457.0 3514.5 # LOG HEJ\DER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TO DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOJVI LOG INTERVAL (FT): BIT ROTATING SPEED (RPJVI): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE GM Dual GR $ # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: 06-DEC-02 Insite 4.3 Memory 3515.0 .6 59.0 TOOL NUMBER 077114 12.250 108.0 SPUD 9.00 126.0 9.5 650 7.0 .000 .000 .000 .0 88.0 .0 ) MUD CAKE AT MT: .000 .0 # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type..................O Data Specification Block Type.....O Logging Direction.................Down Optical log depth units...........Feet Data Reference Point..............Undefined Frame Spacing.....................60 .1IN Max frames per record.............Undefined Absent value...................... -999.25 Depth Units.... . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O Narne Service Order Units Size Nsarn Rep Code Offset CrJannel DEPT FT 4 1 68 0 1 ROP MWD010 FT/H 4 1 68 4 2 GR MWD010 API 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 51.5 3514.5 1783 6927 51.5 3514.5 ROP MWDOI0 FT/H 0 537.96 155.006 6813 108..5 3514.5 GR MWD010 API 15.18 137.62 69.5265 6812 51. 5 3457 First Reading For Entire File..........51.5 Last Reading For Entire File...........3514.5 File Trailer Service name.............STSLIB.OO2 Service Sub Level Name... Version Number...........l.0.0 Date of Generation.......03/03/25 Maximum Physical Record..65535 Fi 1 e Type................ LO Next File Name...........STSLIB.OO3 Physical EOF File Header Service name.............STSLIB.OO3 Service Sub Level Name... Version Number...........l.0.0 Date of Generation.......03/03/25 Maximum Physical Record..65535 File T::lpe................ LO Previous File Name..... ..STSLIB.OO2 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SU1'1MARY VENDOR TOOL CODE START DEPTH 3 header data for each bit run in separate files. 2 .5000 STOP DEPTH NPHI GR NCNT FCNT FET RPD RPM RPS RPX PEF DRHO RHOB ROP $ 3400.5 3457.5 3494.0 3494.0 3494.0 3494.0 3494.0 3494.0 3494.0 3494.0 3505.0 3505.0 3515.0 9560.0 9612.5 9560.0 9560.0 9604.5 9604.5 9604.5 9604.5 9604.5 9569.0 9569.0 9569.0 9650.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG HINIHUH ANGLE: MAXIMUH ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DGR EWR4 CNP SLD $ BOTTOM) TOOL TYPE DUAL GAM1'1A RAY ELECTROMAG. RESIS. 4 COMPENSATED NEUTRON STABILIZED LITHO DEN # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: ~ruD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL HATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: $ # Data Format Specification Record Data Record Type.................. 0 Data Specification Block Type.....O Logging Direction.................Down Optical log depth units...... .....Feet Data Reference Point..............Undefined Frame Spacing.....................60 .1IN Max frames per record.............Undefined Absent value..................... .-999.25 Depth Units....................... ) 13-DEC-02 Insite 0.43 Memory 9650.0 51. 0 59.5 TOOL NUMBER 155790 134760 120156 067985 8.500 3504.0 LSND 12.30 53.0 8.5 200 3.3 3.400 2.123 4.500 3.400 86.0 141. 8 86.0 86.0 ) Datum Specification Block sub-type...O Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD020 FT/H 4 1 68 4 2 GR MWD020 API 4 1 68 8 3 RPX MWD020 OHMM 4 1 68 12 4 RPS MWD020 OHMM 4 1 68 16 5 RPM MWD020 OHMM 4 1 68 20 6 RPD MWD020 OHMM 4 1 68 24 7 FET MWD020 HOUR 4 1 68 28 8 NPHI M'i'iJD020 PU-S 4 1 68 32 9 FCNT MWD020 CNTS 4 1 68 36 10 NCNT MWD020 CNTS 4 1 68 40 11 RHOB MWD020 G/CM 4 1 68 44 12 DRHO MWD020 G/CM 4 1 68 48 13 PEF MWD020 B/E 4 1 68 52 14 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3400.5 9650 6525.25 12500 3400.5 9650 ROP MWD020 FT/H 0 412.09 176.626 12271 3515 9650 GR MWD020 API 45.64 426.06 119.16 12311 3457.5 9612.5 RPX MWD020 OHMM 0.72 1723.45 5.59336 12222 3494 9604.5 RPS MWD020 OHMM 0.61 2000 5.78772 12222 3494 9604.5 RPM MWD020 OHMM 0.61 1639.66 5.88932 12222 3494 9604.5 RPD MWD020 OHMM 0.33 2000 8.80711 12222 3494 9604.5 FET M'¡-'VD 02 0 HOUR 0.16 73.3012 0.952539 12222 3494 9604.5 NPHI MWD020 PU-S 4.17 86.45 48.1529 12320 3400.5 9560 FeNT MWD020 CNTS 409 1139 588.086 12133 3494 9560 NCNT MWD020 CNTS 2126 3800 257 L 26 12133 3494 9560 RHOB MWD020 G/CM 2.029 3.104 2.30524 12129 3505 9569 DRHO MWD020 G/CM -0.254 0.461 0.0578992 12129 3505 9569 PEF MWD020 B/E 2.05 12.28 3.73741 12151 3494 9569 First Reading For Entire File..........34üü.5 Last Reading For Entire File...........9650 File Trailer Service name.............STSLIB.003 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......03/03/25 Maximum Physical Record..65535 File Type..............," LO Next File Name...........STSLIB.004 Physical EOF Tape Trailer Service name.... ...... ...LISTPE Da t e. . . . . . . . . . . . . . . . . . . . . 031 03/25 Origin. . . . . . . . . . . . . . . . . . . STS Tape Name................UNKNOWN Continuation Number......01 Next Tape Name...........UNKNOWN Comments. . . . . . . . . . . . . . . . . STS LIS Writing Library. Scientific Technical Services Reel Trailer Service name.............LISTPE Da t e. . . . . . . . . . . . . . . . . . . . . 031 031 2 5 Origin. . . . . . . . . . . . . . . . . . . STS Reel Name................UNKNOWN Continuation Number......Ol Next Reel Name...........UNKNOWN Comments.................STS LIS Writing Library. Scientific Technical Services 8113 81'1 JO pU3 d03 n~;:::q:Si:1..ìd 303 1";:::'1: slï.c.¡a: (