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201-040
TT RR AA NN SS MM II TT TT AA LL FROM::Sandra D. Lemke, ATO-704 TO:: Meredith Guhl ConocoPhillips Alaska, Inc. AOGCC P.O. Box 100360 330 W. 7 th Ave., Suite 100 Anchorage AK 99510-0360 Anchorage, Alaska 99501 RE: Schlumberger Wireline Backlog – Kuparuk River Unit DATE: 12/19/2023 Transmitted: North Slope, Kuparuk River Unit Via hard drive data drop 3S-26 50-103-20361-01 201040_3S-26_CBL_21Sep2023 201040_3S-26_IBC-CBL_25May23 201040_3S-26_Perf_05Jun23 201040_3S-26_Perf_27Jun23 201040_3S-26_RBP_17Jun23 NUNA-1 50-103-20645-00 211155_NUNA-1_JetCut_02Mar2023 WSW-06 50-029-20851-00 182177_WSW-06_HexPlug_15Jul2023 12 of 12 Transmittall instructions: please promptly sign, scan, and e-mail to Sandra.D.Lemke@conocophillips.com Receipt: Date: Alaska/IT-Support Services GGRE |ConocoPhillips Alaska |Office: 907.265.6947; Mobile 907.440.4512 T38415 T38417 T38418 3S-26 50-103-20361-01 201040_3S-26_CBL_21Sep2023 201040_3S-26_IBC-CBL_25May23 201040_3S-26_Perf_05Jun23 201040_3S-26_Perf_27Jun23 201040_3S-26_RBP_17Jun23 Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.04.23 12:46:14 -08'00' 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: __________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" H-40 115' 9-5/8" J-55 2615' 7" J-55 5941' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate 161 bbls 15.8 ppg Class G Cement PWC 70 bbls 15.8 ppg Cement4706-4856' 8869-9237' 21.4 bbls 15.8 ppg Cement below retainer, 2 bbls 15.8 ppg above retainer Top off OA 17 bbls 15.6 Class G Type I/II Portland Cement 201-040/ 323-200 31' 62.58# 36# 115' 31' WT. PER FT.GRADE CEMENTING RECORD 5995857 SETTING DEPTH TVD 5995987 TOP HOLE SIZE AMOUNT PULLED 480825 481126 TOP SETTING DEPTH MD 24" 547' FNL, 1710' FEL, Sec. 17, T12N, R8E, UM Surface/ Surface Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 3-1/2" Flow Tubing Plugged and Abandoned Perforations: 9047-9137' (cemented) Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 95 bbls15.8 ppg Permafrost CementSurface-2616' (OA) 3786-4833' 40 bbls 15.8 ppg Class G Cement Surface-3786' 30' 2616'31' 30' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 26# Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: 9389' SIZE DEPTH SET (MD) ACID, FRACTURE, CEMENT SQUEEZE, ETC. 8881' MD/ 5749' TVD PACKER SET (MD/TVD) 9002' MD Kuparuk River Field/ Kuparuk River Oil Pool 12.25" 225 sx AS I 31'580 sx AS III Lite, 340 sx Class G CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD 282 sx Class G Lead, 398 sx Class G tail8-1/2" suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. BOTTOMCASING N/A 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM 417' FNL, 1409' FEL, Sec, 17, T12N, R8E, UM P.O. Box 100360, Anchorage, AK 99510-0360 475955 5993843 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 10/30/2023 N/A 1758' MD/ 1756' TVD 9400' MD/ 5945' TVD ADL0380107 ALK 4624 50-103-20361-01-00 KRU 3S-26 February 23, 2001 March 7, 2001 9. Ref Elevations: KB: 34.8' Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment RECEIVED 11/16/2023 Abandoned 10/30/2023 JSB RBDMS JSB 112923 GDSR-1/26/24 Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1758' 1756' Top of Productive Interval N/A 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Jill Simek Digital Signature with Date:Contact Email:jill.simek@conocophillips.com Contact Phone:(907) 263-4131 Staff Interventions Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Formation Name at TD: Authorized Title: Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Authorized Name and INSTRUCTIONS Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A -Plugged and Abandoned N/A - Plugged and Abandoned Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Jill Simek Digitally signed by Jill Simek Date: 2023.11.16 14:37:22 -09'00' Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM 8,869.0 3S-26 8/12/2022 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: CEMENT TO SURFACE 3S-26 10/13/2023 condijw Notes: General & Safety Annotation End Date Last Mod By NOTE: DRILLED AS PALM 1A, EXPLORATORY WELL 4/11/2002 WV5.3 Conversio n 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 63.5 115.0 115.0 65.50 WELD SURFACE 9 5/8 8.92 63.5 2,616.0 2,615.4 36.00 J-55 BTCM PRODUCTION 7 6.28 63.4 9,389.0 5,940.6 26.00 J-55 BTCM Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 8,838.0 Set Depth … 9,002.3 Set Depth … 5,794.5 String Max No… 3 1/2 Tubing Description Tubing – Production Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rdMOD 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) 8,859.3 5,741.2 68.07 SEAL ASSY 4.500 BAKER SEAL ASSEMBLY 3.000 8,860.3 5,741.6 68.07 PBR 5.875 BAKER POLISHED BORE RECEPTACLE 3.000 8,880.1 5,749.0 68.10 SEAL NIPPLE 3.500 BAKER TUBING ANCHOR MODEL K-22 w/TUBING SEAL NIPPLE 2.992 8,881.0 5,749.3 68.10 PACKER 5.937 BAKER SAB-3 PACKER 3.250 8,934.2 5,769.1 68.18 PRODUCTION 5.390 CAMCO KBUG-2 2.920 8,961.1 5,779.1 68.13 PRODUCTION 5.390 CAMCO KBUG-2 2.920 8,987.9 5,789.1 68.07 NIPPLE 4.250 HOWCO XN NO GO NIPPLE W/ XXN PLUG 2.750 9,000.1 5,793.7 68.05 PORTED SUB BIT 3.380 HOWCO PORTED BUT (BALANCED ISOLATION TOOL) 1.500 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) 63.2 63.2 0.00 MARKER PLATE 10/29/2023 0.000 4,833.0 4,131.3 66.46 CIBP 5.67" CIBP MID-ELEMENT AT 4833' RKB OAL 2.59' BOT CIBP 10/3/2023 0.000 5,239.0 4,296.9 66.33 CIBP 5.61" CIBP MID-ELEMENT AT 4882', OAL 1.6'. (MOVED DOWNHOLE TO 5239') LEGACY HPBP 000- 5610- 002 6/4/2023 0.000 8,838.0 5,733.3 68.02 CUT 2-3/8" WELLTEC MECHANICAL TBG CUT AT 8838' RKB 4/2/2023 2.992 8,905.0 5,758.3 68.14 CEMENT RETAINER 2.725 ALAPHA FH 1 TRIP SLEEVE VALVE CEMENT RETAINER 7/28/2022 0.000 9,198.0 5,867.9 67.74 FISH HOWCO 4 5/8" Scallop Gun, 5 spf w/27' of stim sleeves; tubing auto release & space 3'x15' (RELEASED & DROPPED 4/1/01 WHEN FIRED) 3/13/2001 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 4,706.0 4,714.0 4,080.2 4,083.4 6/27/2023 21.0 APERF 4.72" POWERFLOW HSD, 21 SPF, 60 DEG PHASE 4,714.0 4,732.0 4,083.4 4,090.7 6/27/2023 21.0 APERF 4.72" POWERFLOW HSD, 21 SPF, 60 DEG PHASE 4,734.0 4,754.0 4,091.6 4,099.6 6/27/2023 21.0 APERF 4.72" POWERFLOW HSD, 21 SPF, 60 DEG PHASE 4,754.0 4,774.0 4,099.6 4,107.7 6/26/2023 21.0 APERF 4.72" POWERFLOW HSD, 21 SPF, 60 DEG PHASE 4,776.0 4,796.0 4,108.5 4,116.5 6/5/2023 21.0 APERF 4.72" POWERFLOW HSD, 21 SPF, 60 DEG PHASE 4,796.0 4,814.0 4,116.5 4,123.7 6/26/2023 21.0 APERF 4.72" POWERFLOW HSD, 21 SPF, 60 DEG PHASE 4,816.0 4,836.0 4,124.5 4,132.5 6/26/2023 21.0 APERF 4.72" POWERFLOW HSD, 21 SPF, 60 DEG PHASE 4,836.0 4,856.0 4,132.5 4,140.5 6/5/2023 21.0 APERF 4.72" POWERFLOW HSD, 21 SPF, 60 DEG PHASE 9,047.0 9,137.0 5,811.3 5,844.9 C-4, 3S-26 4/1/2001 5.0 PERF 4 5/8" Scallop TCP guns Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 63.4 115.0 63.4 115.0 Conductor String Cement 1/1/2022 8,869.0 8,999.7 5,744.9 5,793.6 Cement Plug 2 bbls 15.8ppg above retainer 7/29/2022 63.5 2,616.0 63.5 2,615.4 Cement Plug OA Downsqueeze - 95 bbls 15.8ppg Permafrost Cement 5/18/2023 4,706.0 4,856.0 4,080.2 4,140.5 Cement Plug Hydrawell PWC Plug - 70 bbls 15.8ppg Cement 7/2/2023 3S-26, 11/16/2023 10:31:39 AM Vertical schematic (actual) PRODUCTION; 63.4-9,389.0 FISH; 9,198.0 PERF; 9,047.0-9,137.0 Cement Plug; 8,999.7 ftKB PRODUCTION; 8,961.1 PRODUCTION; 8,934.2 CEMENT RETAINER; 8,905.0 PACKER; 8,881.0 Cement Plug; 8,869.0 ftKB CUT; 8,838.0 CIBP; 5,239.0 APERF; 4,836.0-4,856.0 CIBP; 4,833.0 APERF; 4,816.0-4,836.0 APERF; 4,796.0-4,814.0 APERF; 4,776.0-4,796.0 Cement Plug; 4,706.0 ftKB APERF; 4,754.0-4,774.0 APERF; 4,734.0-4,754.0 APERF; 4,714.0-4,732.0 APERF; 4,706.0-4,714.0 Cement Plug; 3,786.0 ftKB SURFACE; 63.5-2,616.0 CONDUCTOR; 63.4-115.0 Cement Plug; 63.5 ftKB Cement Plug; 63.5 ftKB Conductor String Cement; 63.4 ftKB MARKER PLATE; 63.2 KUP INJ KB-Grd (ft) 37.38 RR Date 2/21/2001 Other Elev… 3S-26 ... TD Act Btm (ftKB) 9,400.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032036101 Wellbore Status INJ Max Angle & MD Incl (°) 68.18 MD (ftKB) 8,935.10 WELLNAME WELLBORE3S-26 Annotation Last WO: End DateH2S (ppm) 0 Date 1/2/2003 Comment SSSV: NIPPLE Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 8,999.7 9,237.0 5,793.6 5,882.7 Cement Plug Reservoir Plug Casing and Tubing - 21.4 bbls 15.8ppg ceme nt below retainer 7/29/2023 3,786.0 4,833.0 3,661.2 4,131.3 Cement Plug 40 bbls 15.8ppg Cement 10/6/2023 63.5 3,786.0 63.5 3,661.2 Cement Plug 161bbls 15.8 ppg cement 10/13/2023 3S-26, 11/16/2023 10:31:39 AM Vertical schematic (actual) PRODUCTION; 63.4-9,389.0 FISH; 9,198.0 PERF; 9,047.0-9,137.0 Cement Plug; 8,999.7 ftKB PRODUCTION; 8,961.1 PRODUCTION; 8,934.2 CEMENT RETAINER; 8,905.0 PACKER; 8,881.0 Cement Plug; 8,869.0 ftKB CUT; 8,838.0 CIBP; 5,239.0 APERF; 4,836.0-4,856.0 CIBP; 4,833.0 APERF; 4,816.0-4,836.0 APERF; 4,796.0-4,814.0 APERF; 4,776.0-4,796.0 Cement Plug; 4,706.0 ftKB APERF; 4,754.0-4,774.0 APERF; 4,734.0-4,754.0 APERF; 4,714.0-4,732.0 APERF; 4,706.0-4,714.0 Cement Plug; 3,786.0 ftKB SURFACE; 63.5-2,616.0 CONDUCTOR; 63.4-115.0 Cement Plug; 63.5 ftKB Cement Plug; 63.5 ftKB Conductor String Cement; 63.4 ftKB MARKER PLATE; 63.2 KUP INJ 3S-26 ... WELLNAME WELLBORE3S-26 SUNDRY NOTICE 10-407 ConocoPhillips Well 3S-26 Plug and Abandonment November 9, 2023 ConocoPhillips Alaska, Inc. performed Plug and Abandonment operations on 3S-26, commencing operations on April 26, 2023 and completing the Plug and Abandonment on October 30, 2023. After successful suspension of the Kuparuk formation and rig operations to remove tubing, a downsqueeze cement job was performed to place cement in the 7” x 9-5/8” annulus. Subsequently, a bond log was run to determine top of cement in the 7” x OH annulus and to establish intervals for Perf/Wash/Cement operations. Based on logs, a CIBP was set at 4,882ft KB, the production casing was perforated from 4,706ft to 4,856ft KB, then wash and cement operations performed across the interval. Cement in the production casing was then milled to the CIBP and a bond log run to validate that adequate cement had been placed in the 7” x OH annulus. Because the original CIBP had moved during milling, a second CIBP was set at 4,833ft, and 1000ft of cement placed on top. Cement was tagged and pressure tested, then the well was cemented to surface inside the 7” production casing. The well was then excavated below original ground level and the tree and wellhead removed. After state inspection, the well was capped with a marker plate, and the excavation backfilled. Pictures below show cement to surface, marker plate installed, and final site condition after backfill. The field Well Service Report Summary is attached. DTTMSTART JOBTYP SUMMARYOPS 4/25/2023 ACQUIRE DATA SLB ELINE MOVE EQUIPMENT FROM 3S-17A TO 3S-26, SPOT EQUIPMENT AND RIGUP FOR JUNK BASKET RUN 4/26/2023 ACQUIRE DATA SLB ELINE RAN IN HOLE JUNK BASKET RUN, TOOL SAT DOWN AT 4085' (63 DEG) RIGGED UP IBC RUN WITHOUT GEMCOS, SAT DOWN AT 4075', POOH JOB SUSPENDED FOR A PLAN FORWARD 5/4/2023 ACQUIRE DATA ATTEMPT TO DRIFT W/ 5.0'' GAUGE RING TO ABOVE TUBING CUT @ 8845'RKB, SD AND WORK 5.0'' GAUGE RING FROM 4076 ' - 4148' RKB, SD AND WORK TOOLS FROM 8592 'SLM - 8646' RKB, UNABLE TO MAKE MORE HOLE, READY FOR COIL *IN PROGRESS* 5/18/2023 ACQUIRE DATA PERFORM DOWN SQUEEZE ON 9 5/8" X 7" ANNULUS, LRS PERFORMS INJECTIVITY TEST (.1,2,3 & 4 BPM), HES PUMPS 95 BBLS OF 15.8# PERMAFROST CEMENT (SURFACE TO CASING SHOE), JOB COMPLETE. 5/19/2023 ACQUIRE DATA MIRU RIH W/ 2 7/8" MOTOR & 5.75" OD MILL.TAG UP @ 8690' POOH W/ NO ISSUE F/P 2500' RDMO T/S3-704 5/24/2023 ACQUIRE DATA MIRU ELINE AND CRANE. ASSEMBLE PCE, MAKE UP TOOLSTRING WITH WELTECH TRACTOR AND SLB USIT-IBC, PRESSURE TEST TO 500/3000 PSI. OPERATIONS CONTINUED INTO NEXT DAY 5/25/2023 ACQUIRE DATA OPERATIONS CONTINUED FROM PREVIOUS DAY. RIH WITH WELLTEC TRACTOR AND USIT W/ IBC SUB TO ~4200 FT AND BEGIN TRACTORING TO ~8575 FT. LOG MAIN PASS AND REPEAT PASS WITH 5 DEG 3" RESOLUTION. LOGGING COMPLETE. SEND DATA TO TOWN FOR PROCESSING, WILL RETURN FOR CIBP AND PERFORATING AFTER DEPTHS ARE SELECTED WITH PROCESSED LOG. 6/4/2023 ACQUIRE DATA SET 7" LEGACY CAST IRON BRIDGE PLUG MID-ELEMENT AT 4882' JOB COMPLETE, READY FOR CASING PERFORATIONS 6/5/2023 ACQUIRE DATA PERFORATE INTERVAL 4836' - 4856' AND 4776' - 4796' WITH 20' X 4.72" HSD POWERFLOW GUN, 21 SPF READY FOR RBP WITH GAUGES 6/6/2023 ACQUIRE DATA SLB ELINE, RIH WITH 5.968" OD BAKER WT-RBP WITH GAUGES, PLUG HANGING UP AT 4776' IN TOP OF PERFS, TAGGING AT SAME DEPTH AFTER MULTIPLE ATTEMPTS, UNABLE TO MAKE REQUIRED SETTING DEPTH, POOH, READY FOR SLICKLINE TO ATTEMPT TO CLEAN UP PERFS 6/12/2023 ACQUIRE DATA DRIFT 5.935" G-RING TO 4881' RKB, BRUSH TOP PERFS, DRIFT 6.125" G-RING TO 4835' SLM, READY FOR E-LINE. 6/17/2023 ACQUIRE DATA RIG UP SLB ELINE AND THIRD PARTY CRANE, SET 5.95" BAKER RBP WITH TANDEM GAUGES IN PC AT 4816'. CCL TO MID ELEMENT = 23.9', CCL STOP DEPTH = 4792.1'. JOB COMPLETE, READY FOR LRS. 6/17/2023 ACQUIRE DATA PRESSURE TEST PC & FORMATION TO 750 PSI, GATHER DIGITAL READING FOR 60 MIN, BLEED TO 0 PSI, PRESSURE UP AGAIN TO 750 PSI, GATHER DIGITAL PRESSURE READING FOR 60 MIN, LEAVE PRESSURE ON WELL, RD. SEE LOG FOR DETAILS JOB COMPLETE 6/25/2023 ACQUIRE DATA PULLED 5.95" BAKER RBP WITH TANDEM GAUGES @ 4792' RKB. COMPLETE. 3S-26 Plug and Abandon Summary of Operations 6/26/2023 ACQUIRE DATA RIG UP SLB ELINE TO PERFORATE W/ 4.72" POWERFLOW HSD GUNS. RUN 1: PERFORATED INTERVAL = 4816' - 4836', CCL TO TOP SHOT = 7.3', CCL STOP DEPTH = 4808.7'. RUN 2: PERFORATED INTERVAL = 4796' - 4814'. CCL TO TOP SHOT = 9.2', CCL STOP DEPTH = 4786.8'. RUN 3: MISFIRE AFTER MULTIPLE ATTEMPTS TO SHOOT AT DEPTH. TOUBLESHOOTING AT SURFACE INDICATES BAD DETONATOR. ARM SAME TOOLSTRING WITH NEW DETONATOR. RUN 4: PERFORATED INTERVAL = 4754' - 4774'. CCL TO TOP SHOT = 7.3', CCL STOP DEPTH = 4746.7'. ***JOB IN PROGRESS*** 6/27/2023 ACQUIRE DATA *** JOB CONTINUED FROM PREVIOUS DAY*** PERFORATE W/ 4.72" POWERFLOW HSD GUNS. RUN 5: PERFORATED INTERVAL = 4734' - 4754', CCL TO TOP SHOT = 7.3', CCL STOP DEPTH = 4726.7'. RUN 6: PERFORATED INTERVAL = 4714' - 4732', CCL TO TOP SHOT = 9.2', CCL STOP DEPTH = 4704.8'. RUN 7: PERFORATED INTERVAL = 4706' - 4714', CCL TO TOP SHOT = 9.2', CCL STOP DEPTH = 4696.8'. RUN 8: DRIFT WITH JUNK BASKET AND 5.90" GAUGE RING, TAGGED FILL AT 4850' (~31' ABOVE CIBP). JOB COMPLETE, READY FOR COIL 7/1/2023 ACQUIRE DATA RIH WITH MOTOR AND MILL. CLEAN OUT FROM TAG AT 4850' TO 4858' RKB. POOH TO C/O MHA. RBIH. CLEAN OUT TO 4881' P/U HYRDAWELL TOOLS AND WASHING DOWN AT 1 FPM 3.5 BPM FIRST DOWN PASS. **** JOB IN PROGRESS **** 7/2/2023 ACQUIRE DATA FINISHED PERF WASH. DROP 5/8" BALL. ACTIVATE CEMENT SUB. PUMP 70 BBLS OF CEMENT. PUMP CEMENT FROM CIBP AT 4881' RKB TO 150 FT ABOVE PERFS AT 4556' RKB. CONTAMINATE AND CIRC OUT EXCESS CEMENT. PUMP FREEZE PROTECT. RDMO. READY FOR SL TAG IN 24 HRS. 7/4/2023 ACQUIRE DATA TAG TOC @ 4513' SLM. UNABLE TO OBTAIN PASSING MIT TO 1500 PSI. RIG DOWN FOR PLAN FORWARD. 7/8/2023 ACQUIRE DATA COMBO TxIA TO 1500 PSI (PRE STATE) CMIT-TxIA TO 1500 PSI FAILED, 2 ATTEMPTS. (SEE LOG FOR DETAILS) BLED TxIA TO 0 PSI. RIG DOWN FOR PLAN FORWARD. 7/17/2023 SUPPORT OTHER OPERATIONS MIRU M/U BHA #1 W MILL RIH TAG UP 4509' CTM START MILLING F/4509' T/ 4650' W/ NO ISSUE ROP 37' HR POOH INSTALL NIGHT CAP L/D/F/T/N 7/18/2023 SUPPORT OTHER OPERATIONS RAN 2 7/8" MOTOR W/ 6" BEAR CLAW MILL MILLING FROM 4659' DOWN TO 4785' CTMD AVERAGING 15' PER HOUR (TARGET DEPTH @ 4882'). 7/19/2023 SUPPORT OTHER OPERATIONS RAN 2 7/8" MOTOR W/ 6' BEAR CLAW MILL, MILLING CEMENT FROM 4785' DOWN TO HARD TAG @ 4870' CTMD / 4881' RKB. RAN IN HOLE W/ 2 7/8" MOTOR, UNDERREAMER (6.28 & 6.19" BLADES), & 3.80" JUNK MILL W/ TOOLS FALLING FREELY DOWN TO 5228' CTMD. PUH TO 4500' & UNDERREAM DOWN TO 4887. UNDERREAM BACK UP OOH TO 4418', HUNG UP BRIEFLY, INADVERTANTLY SHEARED BURST DISK, & CHASED GEL PILL (LAYED IN 80 BBLS OF DIESEL FOR FREEZE PROTECT). READY FOR PLAN FORWARD. 8/31/2023 ACQUIRE DATA RIG UP JUNK BASKET (5.91") FOR DRIFT RUN, TOOL SAT DOWN AT 4070' (63 DEG), POOH AND MAKE UP TRACTORS TO JUNK BASKET **JOB CONTINUE** 9/1/2023 ACQUIRE DATA JUNK BASKET SAT AT 4070' (63 DEG), POOH AND MAKE UP TRACTORS, RAN IN HOLE AND TAGGED FILL AT 4548', POOH AND RIG DOWN 9/5/2023 SUPPORT OTHER OPERATIONS MOVE OVER FROM 3S-17 MOVE HARD LINE UR'S P-SUB MIRU RIH W / 5.90" BEAR CLAW, TAGGED AT 4524' CTMD, FCO/MILL TO FINAL DEPTH OF 4890' CTMD (ESTIMATED 4901' RKB), SAW HARD STALLS. PUMPED SEAWATER & POWERVIS GELS SWEEPS, PERFORMED LONG WIPERS TO BUILD SECTION @ 3000'. DRY DRIFTED F/ 2500' TO 4893' CTMD. POOH, PULLED 5K OVER AT 4540', CONTINUE POOH CLEAN, FREEZE PROTECT 7" W/ 95 BBLS DIESEL TO 2500'. READY FOR ELINE. 9/10/2023 ACQUIRE DATA PERFORMED TRACTOR JUNK BASKET RUN (WITH 5.9'' GAUGE RING) TO IDENTIFY TD IN PREPERATION FOR IBC-CBL RUN. ABLE TO GET DOWN TO 4510', THOUGH NOT ABLE TO GET ANY DEEPER ON MULTIPLE ATTEMPTS, PULLING VERY HEAVY OFF BOTTOM, UNABLE TO CONDUCT IBC/CBL. GRAVEL/FORMATION WAS RECOVERED FROM THE JUNK BASKET AT SURFACE (1/4" - 1/2" IN SIZE). *** JOB IS READY FOR PLAN FORWARD *** 9/15/2023 ACQUIRE DATA SET BAKER 7" RBP MID-ELEMENT AT 4480' MIT CASING TO 2500 PSI (PASS) JOB COMPLETE, READY FOR COIL 9/15/2023 ACQUIRE DATA MIRU MU BAKER RUNNING TOOLT/PULL RBP STAB ON PT T/4500 PSI 9/16/2023 ACQUIRE DATA RIH AND ATTEMPT TO PULL RBP AT 4,480'. UNABLE TO LATCH. RECONFIGURE BHA AND PINHOLE COIL WHILE RBIH. CUT COIL. 9/17/2023 ACQUIRE DATA RIH AND PULL BAKER RBP AT 4480', RIG UP 5.75" BEAR CLAW MILL. DRY TAG AT 4,530'. GET MULTIPLE STALLS AT 4,888' - 4,916'. CLEAN TO 4,916' (60' OF RATHOLE). CHASE RETURNS TO SURFACE. RUN DRY DRIFT WITH 5.75' MILL. FREEZE PROTECT WELL TO 2,500'. READY FOR E-LINE. 9/19/2023 ACQUIRE DATA TRAVEL FROM PRUDHOE BAY TO 3S PAD. SPOT ELINE AND BEGIN RIG UP. ASSEMBLE PCE AND TOOLSTRING AND PERFORM SURFACE CHECKS. STAB ON AND PT. JOB CONTINUED INTO NEXT DAY 9/20/2023 ACQUIRE DATA PERFORM DRIFT RUN WITH 5.91" GAUGE RING AND JUNK BASKET WITH TRACTOR. TAG AT 4738' MULTIPLE TIMES. RECOVER CEMENT CHUNKS AND SINGLE PIECE OF RUBBER FROM CIBP IN JUNK BASKET. NOTIFY ENGINEER AND WAIT FOR PLAN FORWARD. DRIFT RUN WITH 4.05" GAUGE RING AND JUNK BASKET TO 4948' WITHOUT ANY ISSUES. NO DEBRIS RECOVERED IN JUNK BASKET. ASSEMBLE IBC-CBL TOOL WITH TRACTORS AND RIH. TAGGED AT 4846' COULD NOT REACH TARGET DEPTH. AFTER FOUR HOURS OF ATTEMPTING TO GET DEEPER, DECISION MADE TO START LOGGING PASSES FROM 4846'. IBC MOTOR STOPPED SPINNING - MOVE UP HOLE TO CLEAN & TROUBLESHOOT. JOB CONTINUED INTO NEXT DAY 9/21/2023 ACQUIRE DATA AFTER MOVING UPHOLE, IBC MOTOR STARTED WORKING. RIH TO 4846' TO START LOGGING, IBC MOTOR STOPPED SPINNING AGAIN. POOH TO TROUBLESHOOT AND FOUND SOME DEBRIS AND GRIT AROUND THE SHAFT CAUSING IT TO BIND UP. CLEANED OUT AND TESTED ON SURFACE. RIH TO BEGIN LOG PASSES. AFTER SEVERAL TRIES, IBC SUB DID NOT START DUE TO DEBRIS FROM WELL CONTAMINATED IN BETWEEN THE IBC. AT SURFACE, SUB WAS TESTED AND WOULD NOT SPIN. DEBRIS FROM THE WELL WERE SEEN CONTAMINATED AROUND THE IBC. SINGLE CIBP SLIP WAS ALSO FOUND STUCK IN BETWEEN A GEMCO CENTRALIZER. RIH WITH DSLT ONLY TO LOG CBL. WAS ONLY ABLE TO REACH 4850' (6' ABOVE BOTTOM PERF INTERVAL) ON BOTH THE MAIN AND REPEAT PASSES. INTERVAL LOGGED 4850' TO 3800'. JOB COMPLETE, DATA SENT TO TOWN FOR PROCESSING 10/2/2023 SUPPORT OTHER OPERATIONS FINISH CUTTING PIPE FROM PATCH JOB. MIRU CTU 6. **JOB IN PROGRESS** 10/3/2023 SUPPORT OTHER OPERATIONS CONT R/U. RIH w/CIBP. SET @ 4833' RKB. POOH. CTU INJECTOR STOPPED WORKING AT 3300' WHILE POOH. STANDBY FOR REPAIRS. **JOB IN PROGRESS** 10/4/2023 SUPPORT OTHER OPERATIONS CONTINUE STANDING BY FOR INJECTOR REPAIRS. POOH CONTINUE TO HAVE ISSUES ON THE HYDRAULICS DECISION WAS MADE TO TAKE TO SLB SHOP FOR INSPECTION AND REPAIR. 10/5/2023 SUPPORT OTHER OPERATIONS TRAVEL TO LOCATION. RIG UP AND PT. RIH AND TAG CIBP. HOLD PJSM. PT CEMENT LINES. START MIXING CEMENT. 10/6/2023 SUPPORT OTHER OPERATIONS LAY IN 40 BBLS OF 15.8 PPG CLASS G CEMENT ON TOP OF CIBP. TOC=3788'. FREEZE PROTECT WELL. READY FOR SLICKLINE TAG AND TEST IN 48 HOURS. 10/10/2023 ACQUIRE DATA TAG TOC @ 3780' SLM W/ 7'X2.5" BAILER, PERFORM MIT TO 1500 PSI (PASSED) STATE WITNESS TAG TOC @ 3786' SLM, PERFORM MIT TO 1500 PSI (PASSED) 10/12/2023 ACQUIRE DATA (P&A) PRODUCTION CASING DDT (COMPLETE) 10/13/2023 ACQUIRE DATA MIRU CTU 6, RIH W/ 2.75" BD NOZ, TAG TOC AT 3778' CTMD, PUMPED 161 BBLS OF 15.8 PPG, CLASS G CEMENT F/ 3770' CTMD T/ SURFACE. TAKE CEMENT SAMPLE AT TANKS, DENSITY WAS 15.6 PPG. WASH BOP STACK, LUB, TREE VALVES AND SURFACE LINES, W/ 20 BBLS PV GEL, FOLLOWED W/ DIESEL, CYCLE MV AND WASH W/ GEL, CLOSE MV. CLEAN DIESEL RETURNS AT TANKS. READY IN 48 HOURS FOR DHD. 10/16/2023 ACQUIRE DATA (P&A) T X IA DDT (COMPLETE) OA DDT (COMPLETE) 10/17/2023 ACQUIRE DATA (P & A) REMOVED IA CASING VALVE, BAD FLUID/CEMENT AT SURFACE. 10/20/2023 ACQUIRE DATA (P&A) IN PROGRESS- REMOVED WELLHEAD VALVES, TOC IN PRODUCTION CASING =4' BAD CEMENT TOP. SC NEED CEMENT TOP OFF, UNABLE TO GET STRING LINE MEASUREMENT DUE TO INCLEMENT WEATHER CONDITION. RECHECK DEPTH WHEN WINDS ARE LESS. ***NEXT STEP- DETERMINE OA TOC THEN CEMENT TOP-OFF.*** 10/22/2023 ACQUIRE DATA (P&A) IN PROGRESS, UNABLE TO MEASURE OA TOC WITH STRING LINE DUE TO RESTRICTIONS IN THE SC. RETURN IN THE AM TO SHOOT TOC WITH ECHOMETER. 10/23/2023 ACQUIRE DATA (P&A) IN PROGRESS- OBTAINED ECHOMETER SHOT INDICATING TOP OF FLUID/CEMENT @ 306'. 9.09 BBL FUV. 10/24/2023 ACQUIRE DATA (P&A) IN PROGRESS- TOPPED OFF OA WITH 17 BBLS OF 15.6 CLASS G TYPE I/II PORTLAND CEMENT. ***NEXT STEP- CUT/REMOVE WELLHEAD.**** 10/25/2023 ACQUIRE DATA (P&A) IN PROGRESS- NES CUT AND REMOVED WELLHEAD. ***NEXT STEP-CUT/REMOVE STEEL CELLAR BEGIN CAN INSTALL AND EXCAVATION.*** 10/26/2023 ACQUIRE DATA (P&A) IN PROGRESS- CUT & REMOVED STEEL CELLAR. VIBRATED 8'D X 16' H SHORE CAN INTO POSITION. BEGAN EXCAVATING WITH IN SHORE CAN. ***NEXT STEP- CONTINUE TO EXCAVATE TO TARGET DEPTH OF 14' BELOW TOP OF SHORE CAN.*** 10/27/2023 ACQUIRE DATA (P&A) IN PROGRESS- LOCATED ADDITIONAL CORRUGATED CELLAR AND STAND PLATE ~8' INTO EXCAVATION PROCESS. CALLED OUT NES WELDER TO CUT/REMOVE CORRUGATED CELLAR AND STAND PLATE. ***NEXT STEP - RESUME EXCAVATION TO TARGET DEPTH OF 14' BELOW TOP OF SHORE CAN. PREP WELL STUB FOR REMOVAL.*** 10/28/2023 ACQUIRE DATA (P&A) IN PROGRESS- EXCAVATE TO 14' BELOW TOP OF SHORE CAN. CUT/REMOVE 57" OF WELL STUB. TOC = 97" or 8'1"' BELOW OG. *** NEXT STEP- AOGCC INSPECTION AND VERIFICATION OF TOC, MARKER PLATE INFORMATION AND WELD.*** 10/29/2023 ACQUIRE DATA (P&A) IN PROGRESS- AOGCC INSPECTOR BRIAN BIXBY WITNESSED TOC, 16" MARKER PLATE INFORMATION, AND WELD. BACKFILLED AND EXTRACTED SHORE CAN. COMPLETED BACKFILL OPERATIONS. LOUNSBURY SHOT FINAL GRADE OF MARKER PLATE @ 8'- 5.25" BELOW OG. ***NEXT STEP- REQUEST FINAL SITE CLEARANCE POST BACKFILL.*** 10/30/2023 ACQUIRE DATA (P&A) AOGCC INSPECTOR BRIAN BIXBY DECLINED FINAL SITE CLEARANCE - DUE TO RECENT SNOWFALL ON BACKFILL OPERATIONS. PLAN FORWARD REQUESTED FROM TOWN ENGINEER. Jill talked to Regg who confirmed that final site clearance isn't needed to consider the well P&A'd. Final site clearance will be needed at end of field life. *JOB COMPLETE* 2023-1029_Surface_Abandon_KRU_3S-26_bb Page 1 of 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: October 31, 2023 P. I. Supervisor FROM: Brian Bixby SUBJECT: Surface Abandonment Petroleum Inspector KRU 3S-26 ConocoPhillips Alaska Inc. PTD 2010400; Sundry 323-200 10/29/23: I arrived location and met with Roger Mouser (CPAI). I looked over the marker plate to verify that it had all the correct information on it and it did. There is good hard cement to surface on all strings. The cut off is more than 3 feet below tundra level. The marker plate was welded onto the well’s conductor, and I gave the OK to backfill when they are ready. Attachments: Photos (3); Pad Map 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2023.12.03 16:44:54 -09'00' 2023-1029_Surface_Abandon_KRU_3S-26_bb Page 2 of 3 Surface Abandonment – KRU 3S-26 (PTD 2010400) Photos by AOGCC Inspector B. Bixby 10/29/2023 2023-1029_Surface_Abandon_KRU_3S-26_bb Page 3 of 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:18 Township:12N Range:8E Meridian:Umiat Drilling Rig:n/a Rig Elevation:n/a Total Depth:9400 ft MD Lease No.:ADL0380107 Operator Rep:Suspend:P&A:X Conductor:16"O.D. Shoe@ 115 Feet Csg Cut@ Feet Surface:9 5/8"O.D. Shoe@ 2616 Feet Csg Cut@ Feet Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet Production:7"O.D. Shoe@ 9389 Feet Csg Cut@ Feet Liner:O.D. Shoe@ Feet Csg Cut@ Feet Tubing:3 1/2" x 2 7/8"O.D. Tail@ 9002 Feet Tbg Cut@ 8845 Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Perforation Bridge plug 4832 ft MD 3786 ft MD 15.8 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1655 1550 1505 IA 1655 1550 1505 OA 20 10 20 Initial 15 min 30 min 45 min Result Tubing 1720 1640 1615 IA 1720 1640 1615 OA 20 20 20 Remarks: Attachments: Michael Scoles P Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Tubing had been cut and pulled leaving the 7-inch and 9 5/8-inch casings. 1st tag @ 3782 ft MD. Drive down to 3783 ft MD. Sample was loose,contaminated cement. 2nd tag @ 3784 ft MD. Drive down to 3786 ft MD. Sample produced more of the same, but with some firmer cement. The wireline tool string was barely 100 pounds total which was a surprise since I had requested for them to go as heavy as possible before coming out to location. The first MIT was marked inconclusive due to the operator not considering it a pass per CPAI requirements and considering both the large amount of contaminated cement and the total pressure loss being close to 10%. The second MIT was a pass without any issue. With the first MIT they pumped 1.4 bbls in and got back 1.4 bbls. With the second MIT they pumped 1.5 bbls and got back 1.5 bbls. October 10, 2023 Guy Cook Well Bore Plug & Abandonment KRU 3S-26 ConocoPhillips Alaska Inc PTD 2010400; Sundry 323-200 none Test Data: I Casing Removal: rev. 11-28-18 2023-1010_Plug_Verification_KRU_3S-26_gc STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 3S-26 JBR 05/12/2023 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 3-1/2" joint. HCR choke-greased for pass. Test Results TEST DATA Rig Rep:Cozby/YearoutOperator:ConocoPhillips Alaska, Inc.Operator Rep:Adams/Erdman Rig Owner/Rig No.:Nabors 7ES PTD#:2010400 DATE:4/14/2023 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopSAM230415161714 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6 MASP: 1440 Sundry No: 323-088 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 16 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8 P #1 Rams 1 2-7/8x5 P #2 Rams 1 Blinds P #3 Rams 1 3-1/2x5-1/2 NT #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8 P HCR Valves 2 3-1/8 FP Kill Line Valves 2 3-1/8&2 P Check Valve 0 NA BOP Misc 2 2-1/16 P System Pressure P3000 Pressure After Closure P1500 200 PSI Attained P15 Full Pressure Attained P176 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P5@2000 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P25 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9 9999 9 9FP HCR choke- 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: __________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" H-40 115' 9-5/8" J-55 2615' 7" J-55 5941' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate N/A 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM 417' FNL, 1409' FEL, Sec, 17, T12N, R8E, UM P.O. Box 100360, Anchorage, AK 99510-0360 475955 5993843 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 4/16/2023 N/A 1758' MD/ 1756' TVD CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD 282 sx Class G Lead, 398 sx Class G tail8-1/2" suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. BOTTOMCASING 9400' MD/ 5945' TVD ADL0380107 ALK 4624 50-103-20361-01-00 KRU 3S-26 February 23, 2001 March 7, 2001 9. Ref Elevations: KB: 34.8' Kuparuk River Field/ Kuparuk River Oil Pool 12.25" 225 sx AS I 31'580 sx AS III Lite, 340 sx Class G 30' 2616'31' 30' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 26# Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: 9389' SIZE DEPTH SET (MD) ACID, FRACTURE, CEMENT SQUEEZE, ETC. 8881' MD/ 5749' TVD PACKER SET (MD/TVD) 9002' MD3-1/2" Flow Tubing SUSPENDED Perforations: 9047-9137' (cemented) Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 31' 62.58# 36# 115' 31' WT. PER FT.GRADE CEMENTING RECORD 5995857 SETTING DEPTH TVD 5995987 TOP HOLE SIZE AMOUNT PULLED 480825 481126 TOP SETTING DEPTH MD 24" 547' FNL, 1710' FEL, Sec. 17, T12N, R8E, UM 8869' MD/ 5745' TVD Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment 14. Permit to Drill Number / Sundry: 201-040/ 323-088 RECEIVED by James Brooks on 5/10/2023 at 10:26 AM Suspended 4/16/2023 JSB RBDMS JSB 051823 xGDSR-6/1/23 Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1758' 1756' Top of Productive Interval N/A 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Dusty Ward Digital Signature with Date:Contact Email: dusty.ward@conocophillips.com Contact Phone:(907) 265-6531 Senior Workver Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: INSTRUCTIONS Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A -Suspended N/A - Suspended Authorized Title: Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Authorized Name and Formation Name at TD: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM 8,869.0 3S-26 8/12/2022 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Annotate Tbg Cut 3S-26 4/2/2023 bworthi1 Notes: General & Safety Annotation End Date Last Mod By NOTE: DRILLED AS PALM 1A, EXPLORATORY WELL 4/11/2002 WV5.3 Conversio n General Notes: Last 3 entries Com Date Last Mod By DRILLED AS PALM 1A, EXPLORATORY WELL 4/11/2002 Admin 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 30.0 115.0 115.0 65.50 WELD SURFACE 9 5/8 8.92 31.0 2,616.0 2,615.4 36.00 J-55 BTCM PRODUCTION 7 6.28 31.0 9,389.0 5,940.6 26.00 J-55 BTCM Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 8,838.0 Set Depth … 9,002.3 Set Depth … 5,794.5 String Ma… 3 1/2 Tubing Description Tubing – Production Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rdMOD 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) 8,859.3 5,741.2 68.07 SEAL ASSY 4.500 BAKER SEAL ASSEMBLY 3.000 8,860.3 5,741.6 68.07 PBR 5.875 BAKER POLISHED BORE RECEPTACLE 3.000 8,880.1 5,749.0 68.10 SEAL NIPPLE 3.500 BAKER TUBING ANCHOR MODEL K-22 w/TUBING SEAL NIPPLE 2.992 8,881.0 5,749.3 68.10 PACKER 5.937 BAKER SAB-3 PACKER 3.250 8,987.9 5,789.1 68.07 NIPPLE 4.250 HOWCO XN NO GO NIPPLE W/ XXN PLUG 2.750 9,000.1 5,793.7 68.05 PORTED SUB BIT 3.380 HOWCO PORTED BUT (BALANCED ISOLATION TOOL) 1.500 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) 8,838.0 5,733.3 68.02 CUT 2-3/8" WELLTEC MECHANICAL TBG CUT AT 8838' RKB 4/2/2023 2.992 8,869.0 5,744.9 68.08 TUBING PLUG Pumped 24 bbls of 15.8 ppg cement. 19.4 bbls below and 2 bbls on top. 8/12/2022 0.000 8,905.0 5,758.3 68.14 CEMENT RETAINER 2.725 ALAPHA FH 1 TRIP SLEEVE VALVE CEMENT RETAINER 7/28/2022 0.000 9,198.0 5,867.9 67.74 FISH HOWCO 4 5/8" Scallop Gun, 5 spf w/27' of stim sleeves; tubing auto release & space 3'x15' (RELEASED & DROPPED 4/1/01 WHEN FIRED) 3/13/2001 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 9,047.0 9,137.0 5,811.3 5,844.9 C-4, 3S-26 4/1/2001 5.0 PERF 4 5/8" Scallop TCP guns 3S-26, 5/9/2023 1:05:29 PM Vertical schematic (actual) PRODUCTION; 31.0-9,389.0 FISH; 9,198.0 PERF; 9,047.0-9,137.0 TUBING PLUG; 8,869.0 PRODUCTION; 8,961.1 PRODUCTION; 8,934.2 CEMENT RETAINER; 8,905.0 PACKER; 8,881.0 CUT; 8,838.0 SURFACE; 31.0-2,616.0 CONDUCTOR; 30.0-115.0 KUP INJ KB-Grd (ft) 37.38 RR Date 2/21/2001 Other Elev… 3S-26 ... TD Act Btm (ftKB) 9,400.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032036101 Wellbore Status INJ Max Angle & MD Incl (°) 68.18 MD (ftKB) 8,935.10 WELLNAME WELLBORE3S-26 Annotation Last WO: End DateH2S (ppm) 0 Date 1/2/2003 Comment SSSV: NIPPLE Page 1/2 3S-26 Report Printed: 5/9/2023 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 4/13/2023 12:00 4/13/2023 15:30 3.50 MIRU, WELCTL WAIT T Waiting on the pad prepr to get completed to move rig off well 17 and mobilize on well 26. Pad Prep was completed 0.0 0.0 4/13/2023 15:30 4/13/2023 16:30 1.00 MIRU, WELCTL WAIT T Truck called to be on location at 3:00 PM arrived at 4:30 0.0 0.0 4/13/2023 16:30 4/13/2023 20:00 3.50 MIRU, WELCTL MOB P Move over 3S-26 and set pits 0.0 0.0 4/13/2023 20:00 4/13/2023 23:00 3.00 MIRU, WELCTL RURD P Rig up over well // Rig up checklists // Accept rig 23:00 4/13/23 0.0 0.0 4/13/2023 23:00 4/14/2023 00:00 1.00 MIRU, WELCTL RURD P Line up blow down lines to circulate well to 9.6 0.0 0.0 4/14/2023 00:00 4/14/2023 01:30 1.50 MIRU, WELCTL RURD P Rig up lines confirm communication for circulating well over // Load pits with brine 0.0 0.0 4/14/2023 01:30 4/14/2023 04:15 2.75 MIRU, WELCTL CIRC P Circulate well T/ 9.6 brine 0.0 0.0 4/14/2023 04:15 4/14/2023 05:00 0.75 MIRU, WELCTL OWFF P OWFF at well head 0.0 0.0 4/14/2023 05:00 4/14/2023 05:30 0.50 MIRU, WELCTL SVRG P Service rig 0.0 4/14/2023 05:30 4/14/2023 07:15 1.75 MIRU, WHDBOP MPSP P Set 3" HP-BPV and test from below to 1000 PSI for 10 minutes. 0.0 0.0 4/14/2023 07:15 4/14/2023 09:00 1.75 MIRU, WHDBOP NUND P N/D adapter and tree 0.0 0.0 4/14/2023 09:00 4/14/2023 10:30 1.50 MIRU, WHDBOP NUND P NU BOP's 0.0 0.0 4/14/2023 10:30 4/14/2023 11:00 0.50 MIRU, WHDBOP NUND P Run stack washer in advance of BWM. 0.0 0.0 4/14/2023 11:00 4/14/2023 14:30 3.50 MIRU, WHDBOP RURD P Bore scope BOP stack for BWM. 0.0 0.0 4/14/2023 14:30 4/14/2023 16:00 1.50 MIRU, WHDBOP RURD P RU to test BOP's 0.0 0.0 4/14/2023 16:00 4/14/2023 21:00 5.00 COMPZN, WHDBOP BOPE P Initial BOPE test, Tested BOPE at 250/2500 PSI for 5 Min each, Tested annular on 3-1/2" test joint, UVBR's, W/3-1/2" test joint. Test blinds rams. Choke valves #1 to #16, upper IBOP and lower top drive well control valves. Test 3 1/2" HT-38 safety valve, FOSV, and IBOP. Test 2" rig floor Demco kill valves. Test manual and HCR kill valves & manual and HCR choke valves. Test two ea. 2 1/6" gate auxiliary valves below LPR. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Perform accumulator test. Initial pressure=3050 PSI, after closure=1500 PSI, 200 PSI attained =14 sec, full recovery attained = 175 sec. UVBR's= 5 sec, Annular= 25 sec. Simulated blinds= 5 sec. LVBR’s=5 sec. HCR choke & kill= 1 sec each. 5 back up nitrogen bottles average = 2000 PSI. Test gas detectors, PVT and flow show. Test Witnessed by AOGCC rep Austin McLeod 0.0 0.0 4/14/2023 21:00 4/14/2023 22:00 1.00 COMPZN, WHDBOP MPSP P Suck out stack // Pull HP-BPV // Observe well for flow 0.0 0.0 4/14/2023 22:00 4/14/2023 23:15 1.25 COMPZN, WHDBOP THGR P Pick up landing jt, make up to hanger, BOLDS , pull hanger off seat // Pipe moving 120K up wt // pull hanger to floor and lay down 0.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 4/16/2023 Page 2/2 3S-26 Report Printed: 5/9/2023 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 4/14/2023 23:15 4/15/2023 00:00 0.75 COMPZN, WHDBOP PULL P Lay down 3.5" completion 0.0 0.0 4/15/2023 00:00 4/15/2023 01:30 1.50 COMPZN, WHDBOP CIRC P Well u-tubing after pull from cut circulate B/U // after circulating bottoms up well continue to flow gain 3 bbls // Line up for casing test 0 psi to start // 8,777.0 8,777.0 4/15/2023 01:30 4/15/2023 02:30 1.00 PRTS P Pressure test casing confirm holding to 1500 psi // good test // after test open up well no flow observed 8,777.0 8,777.0 4/15/2023 02:30 4/15/2023 03:45 1.25 CIRC P Circulate B/U confirm good fluid in and out 8,777.0 8,777.0 4/15/2023 03:45 4/15/2023 14:00 10.25 PULL P Lay down 3.5" completion F/8777, T/surface ( joint 129 to 281 cement on outside of tubing) CMU in closed position. Bottom GLM @ 8777.1' OV in place. 8,777.0 0.0 4/15/2023 14:00 4/15/2023 14:30 0.50 SVRG P Service rig. 0.0 0.0 4/15/2023 14:30 4/15/2023 15:00 0.50 FRZP P RU and freeze protect 7" casing with 12 BBL's diesel. blow down lines, R/D pumping equipment. 0.0 0.0 4/15/2023 15:00 4/15/2023 16:00 1.00 RURD P R/D floor from laying down tubing clean floor after laying down tubing. 0.0 0.0 4/15/2023 16:00 4/15/2023 20:00 4.00 NUND P Nipple down BOPs nipple up tree test break 800 psi 10 min 0.0 0.0 4/15/2023 20:00 4/16/2023 00:00 4.00 RURD P Rig down from 3S-26 for move to 3A Rig released 00:00 on 4/16/23 0.0 0.0 Rig: NABORS 7ES RIG RELEASE DATE 4/16/2023 DTTMSTART JOBTYP SUMMARYOPS 8/12/2022 ACQUIRE DATA (STATE WITNESS) TAG TOP OF CEMENT W/ 2.25" BAILER @ 8869' RKB. MITT & CMIT TO 1500 PSI (PASS) 3/30/2023 ACQUIRE DATA (P&A) FUNCTION TESTED ALL T & IC LDS/GN'S, T-POT (PASSED) T-PPPOT (PASSED) IC-POT (PASSED) IC-PPPOT (PASSED) 4/1/2023 SUPPORT OTHER OPERATIONS TAG TOC @ 8895' RKB W/ SAMPLE BAILER (CEMENT IN BAILER); MAKE SEVERAL ATTEMPTS TO PULL DV @ 8777' RKB (BREAKING PULLING TOOLS); PULL DV @ 7764' RKB (LEFT POCKET OPEN). READY FOR E-LINE. 4/2/2023 SUPPORT OTHER OPERATIONS CUT TUBING WITH WELLTEC MECHANICAL CUTTER AT 8838' TATTLETAIL AT SURFACE INDICATES 3.51" BLADE EXPANSION (> 3.50" TBG OD) JOB COMPLETE, READY FOR RWO 4/5/2023 ACQUIRE DATA (P&A) CDDT- T X IA X OA (IN PROGRESS) 4/6/2023 ACQUIRE DATA (P&A) : CDDT-TxIAxOA (IN-PROGRESS). 4/7/2023 ACQUIRE DATA (P&A) : CDDT-TxIAxOA (IN-PROGRESS). 4/8/2023 ACQUIRE DATA (P&A) : CDDT-TxIAxOA (PASSED). 4/13/2023 RECOMPLETION Completed rigging down off 3S-17, move to 3S-26, rig up 4/14/2023 RECOMPLETION Completed rig up over 3S-26, rig up to kill well, Pump 337 bbls 9.6 ppg brine down tubing up IA, check for flow, install hp-bpv, nipple down tree, nipple up stack, perform between wells maintenance, test bop's witnessed by AOGCC Austin McLeod, pull bpv, install landing jt , pull hanger off seat pipe moving 120K up wt, start laying down 3.5" completion 4/15/2023 RECOMPLETION Completed laying down 3.5" completion, nipple down stack nipple up dry hole tree, test 800 psi 10 min good test on break, rdmo to 3A 4/25/2023 ACQUIRE DATA SLB ELINE MOVE EQUIPMENT FROM 3S-17A TO 3S-26, SPOT EQUIPMENT AND RIGUP FOR JUNK BASKET RUN 4/26/2023 ACQUIRE DATA SLB ELINE RAN IN HOLE JUNK BASKET RUN, TOOL SAT DOWN AT 4085' (63 DEG) RIGGED UP IBC RUN WITHOUT GEMCOS, SAT DOWN AT 4075', POOH JOB SUSPENDED FOR A PLAN FORWARD 5/4/2023 ACQUIRE DATA ATTEMPT TO DRIFT W/ 5.0'' GAUGE RING TO ABOVE TUBING CUT @ 8845'RKB, SD AND WORK 5.0'' GAUGE RING FROM 4076 ' - 4148' RKB, SD AND WORK TOOLS FROM 8592 'SLM - 8646' RKB, UNABLE TO MAKE MORE HOLE, READY FOR COIL *IN PROGRESS* 3S-26 RWO Summary of Operations SFD 4/7/2023GCW 04/12/23 JLC 4/12/2023 04/12/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.04.12 16:54:32 -08'00' RBDMS JSB 041423 1a. Well Status:Other Abandoned SuspendedSPLUGOil 1b. Well Class: 20AAC 25.105 20AAC 25.110 ExploratoryDevelopment GINJ WINJ WDSPL No. of Completions: __________________Stratigraphic TestService 14. Permit to Drill Number / Sundry:6. Date Comp., Susp., or2. Operator Name: Aband.: 15. API Number:7. Date Spudded:3. Address: 16. Well Name and Number:8. Date TD Reached:4a. Location of Well (Governmental Section): Surface: 17. Field / Pool(s):Top of Productive Interval: GL: BF: 18. Property Designation:10. Plug Back Depth MD/TVD:Total Depth: 19. DNR Approval Number:11. Total Depth MD/TVD:4b. Location of Well (State Base Plane Coordinates, NAD 27): Zone- 4y-x-Surface: 20. Thickness of Permafrost MD/TVD:12. SSSV Depth MD/TVD:Zone- 4y-x-TPI: Zone- 4y-x-Total Depth: 5. Directional or Inclination Survey: Yes (attached) No 21. Re-drill/Lateral Top Window MD/TVD:13. Water Depth, if Offshore: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: 23. BOTTOM 115'H-4016" 2615'J-559-5/8" 5941'J-557" 25.Yes No 26. NoWas hydraulic fracturing used during completion? Yes AMOUNT AND KIND OF MATERIAL USEDDEPTH INTERVAL (MD) 27. Method of Operation (Flowing, gas lift, etc.):Date First Production: Gas-MCF:Production forHours Tested: Test Period Oil Gravity - API (corr):Gas-MCF:CalculatedCasing Press: Press. 24-Hour Rate 201-040/ 322-153 31' 36# 115' 31' WT. PER FT.CEMENTING RECORDGRADE 5995857 SETTING DEPTH TVD 5995987 TOP HOLE SIZE AMOUNT PULLED 480825 481126 TOP SETTING DEPTH MD Sr Res EngSr Pet GeoSr Pet Eng Water-Bbl:Oil-Bbl: 21.4 bbls of 15.8 ppg Cement below retainer, 2 bbls on top of retainer 8869-9137' MD Flow Tubing SUSPENDED Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 26# Water-Bbl: PRODUCTION TEST N/A Oil-Bbl:Date of Test: 9389' DEPTH SET (MD)SIZE 24" 12.25" 225 sx AS I 31'580 sx AS III Lite, 340 sx Class G 30' 2616'31' 30' 547' FNL, 1710' FEL, Sec. 17, T12N, R8E, UM 8869' MD/ 5745' TVD 9400' MD/ 5945' TVD ADL0380107 ALK 4624 50-103-20361-01-00 KRU 3S-26 February 23, 2001 March 7, 2001 9. Ref Elevations: KB: 34.8' Kuparuk River Field/ Kuparuk River Oil Pool ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD 282 sx Class G Lead, 398 sx Class G tail8-1/2" suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. BOTTOM 8881' MD/ 5749' TVD PACKER SET (MD/TVD) 9002' MD3-1/2" CASING STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 8/12/2022 1758' MD/ 1756' TVDN/A N/A 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM 417' FNL, 1409' FEL, Sec, 17, T12N, R8E, UM P.O. Box 100360, Anchorage, AK 99510-0360 5993843475955 Due within 30 days of Completion, Suspension, or AbandonmentForm 10-407 Revised 10/2022 N/A 24. Open to production or injection? Perforations: 9047-9137' MD and 5811-5845' TVD (cemented) 62.5# By James Brooks at 8:07 am, Feb 21, 2023 Suspended 8/12/2022 JSB RBDMS JSB 022823 xGDSR-3/3/23 Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1758' 1756' Top of Productive Interval N/A 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Jill Simek Digital Signature with Date:Contact Email: jill.simek@conocophillips.com Contact Phone:(907) 263-4131 Staff Well Integrity Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Formation Name at TD: Authorized Title: Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Authorized Name and INSTRUCTIONS Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A -Suspended N/A - Suspended Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Signed for Jill Simek Digitally signed by Allen EscheteDN: CN=Allen Eschete, E=Allen.Eschete@ConocoPhillips.comReason: I have reviewed this document Location: Date: 2023.02.20 15:23:29-09'00' Foxit PDF Editor Version: 12.0.1 Allen Eschete Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Tag TOC 3S-26 8/12/2022 rogerba Notes: General & Safety Annotation End Date Last Mod By NOTE: DRILLED AS PALM 1A, EXPLORATORY WELL 4/11/2002 WV5.3 Conversio n General Notes: Last 3 entries Com Date Last Mod By DRILLED AS PALM 1A, EXPLORATORY WELL 4/11/2002 Admin 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 30.0 115.0 115.0 65.50 WELD SURFACE 9 5/8 8.92 31.0 2,616.0 2,615.4 36.00 J-55 BTCM PRODUCTION 7 6.28 31.0 9,389.0 5,940.6 26.00 J-55 BTCM Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 29.6 Set Depth … 9,002.3 Set Depth … 5,794.5 String Ma… 3 1/2 Tubing Description TUBING - 3.5" x 2.875" @ 8999.3 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rdMOD 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) 29.6 29.6 0.00 HANGER 8.000 FMC GEN IV TUBING HANGER 3.500 506.3 506.3 0.89 NIPPLE 4.563 CAMCO DS NO GO NIPPLE 2.875 2,514.7 2,514.2 0.88 GAS LIFT 5.390 CAMCO KBMM-2 2.920 3,995.3 3,784.0 59.22 GAS LIFT 5.390 CAMCO KBMM-2 2.920 6,194.3 4,675.0 66.40 GAS LIFT 5.390 CAMCO KBMM-2 2.920 7,764.7 5,307.6 66.26 GAS LIFT 5.390 CAMCO KBMM-2 2.920 8,777.1 5,710.0 67.13 GAS LIFT 5.390 CAMCO KBMM-2 2.920 8,819.2 5,726.2 67.75 SLEEVE-C 4.375 BAKER CMU SLIDING SLEEVE (CLOSED 11/9/2002) 2.812 8,859.3 5,741.2 68.07 SEAL ASSY 4.500 BAKER SEAL ASSEMBLY 3.000 8,860.3 5,741.6 68.07 PBR 5.875 BAKER POLISHED BORE RECEPTACLE 3.000 8,880.1 5,749.0 68.10 SEAL NIPPLE 3.500 BAKER TUBING ANCHOR MODEL K-22 w/TUBING SEAL NIPPLE 2.992 8,881.0 5,749.3 68.10 PACKER 5.937 BAKER SAB-3 PACKER 3.250 8,987.9 5,789.1 68.07 NIPPLE 4.250 HOWCO XN NO GO NIPPLE W/ XXN PLUG 2.750 9,000.0 5,793.7 68.05 PORTED SUB BIT 3.380 HOWCO PORTED BUT (BALANCED ISOLATION TOOL) 1.500 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) 8,869.0 5,744.9 68.08 TUBING PLUG Pumped 24 bbls of 15.8 ppg cement. 19.4 bbls below and 2 bbls on top. 8/12/2022 0.000 8,905.0 5,758.3 68.14 CEMENT RETAINER 2.725 ALAPHA FH 1 TRIP SLEEVE VALVE CEMENT RETAINER 7/28/2022 0.000 9,198.0 5,867.9 67.74 FISH HOWCO 4 5/8" Scallop Gun, 5 spf w/27' of stim sleeves; tubing auto release & space 3'x15' (RELEASED & DROPPED 4/1/01 WHEN FIRED) 3/13/2001 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) 2,514.7 2,514.2 0.88 1 GAS LIFT DMY BK 1 0.0 5/16/2015 0.000 3,995.3 3,784.0 59.22 2 GAS LIFT DMY BK5 1 0.0 3/13/2001 0.000 6,194.3 4,675.0 66.40 3 GAS LIFT DMY BK5 1 0.0 3/13/2001 0.000 7,764.7 5,307.6 66.26 4 GAS LIFT DMY BK5 1 0.0 3/13/2001 0.000 8,777.1 5,710.0 67.13 5 GAS LIFT DMY BK5 1 0.0 3/13/2001 0.000 8,934.2 5,769.1 68.18 6 PROD DMY BK5 1 0.0 3/13/2001 0.000 8,961.1 5,779.1 68.13 7 PROD OPEN OPEN 1 0.0 6/27/2022 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 9,047.0 9,137.0 5,811.3 5,844.9 C-4, 3S-26 4/1/2001 5.0 PERF 4 5/8" Scallop TCP guns TUBING PLUG; 8,869.0 PRODUCTION; 8,961.1 PRODUCTION; 8,934.2 CEMENT RETAINER; 8,905.0 PACKER; 8,881.0 GAS LIFT; 8,777.1 GAS LIFT; 7,764.7 GAS LIFT; 6,194.3 GAS LIFT; 3,995.3 SURFACE; 31.0-2,616.0 GAS LIFT; 2,514.8 NIPPLE; 506.4 CONDUCTOR; 30.0-115.0 DTTMSTART JOBTYP SUMMARYOPS 5/2/2022 SUPPORT OTHER OPERATIONS DRIFT TBG W/ 2.81" DMY CA2 PLUG TO TOP OF C-LOCK ON ISO SLEEVE @ 8819' RKB PERFORM INJECTIVITY TEST DOWN TBG UP TO 3 BPM @ 1450 PSI. PERFORM INJECTIVITY TEST DOWN OA UP TO 1.7 BPM @ 1000 PSI (SEE ATTACHMENTS) READY FOR CTU PENDING WELL INTERVENTION ENGINEER REVIEW (READY EQUIPMENT FOR PLANNED MAINTENANCE 5-3-22) 6/26/2022 SUPPORT OTHER OPERATIONS ATTEMPT TO PULL ISO SLEEVE & SAT DOWN IN GLM @ 6194' RKB; RUN BARBELL ASSEMBLY W/ PULLING TOOL & PULL 2.81" C-LOCK W/ ISO SLEEVE @ 8819' RKB; ATTEMPT PULL DV @ 8961' RKB & INADVERTENTLY SAT DOWN IN MANDREL @ 6194' RKB (UNABLE TO PASS AND UNABLE TO SHEAR OFF) SHUCK PULLING TOOL TO GET OFF VALVE (NO CHANGE IN IA PRESSURE). IN PROGRESS. 6/27/2022 SUPPORT OTHER OPERATIONS PULLED DV FROM 8961' RKB. JOB COMPLETE. READY FOR CTU 7/28/2022 ACQUIRE DATA (PRE-SW) DEGAS/LOAD IA FOR UPCOMING SW MIT (IN-PROGRESS) 7/29/2022 SUPPORT OTHER OPERATIONS PERFORMED WEEKLY BOP TEST PUMP 21.4 BBLS OF 15.8 PPG CEMENT BELOW RETAINER AND LAID IN 2 BBLS ON TOP OF RETAINER DRESSED OFF CEMENT TOP TO 8675' FREEZE PROTECT FROM 2500' W 23 BBLS OF DIESEL RDMO **** JOB COMPLETE**** 7/30/2022 ACQUIRE DATA (PRE-SW) DEGAS/LOAD IA FOR UPCOMING SW MIT (IN-PROGRESS) 7/31/2022 ACQUIRE DATA (Pre SW) DEGAS?LOAD IA FOR UPCOMING SW MITIA (COMPLETE 8/12/2022 ACQUIRE DATA (STATE WITNESS) TAG TOP OF CEMENT W/ 2.25" BAILER @ 8869' RKB. MITT & CMIT TO 1500 PSI (PASS) 3S-26 Suspension Summary of Operations Operations shutdownRepair WellFracture StimulatePlug PerforationsAbandon1. Type of Request: Other StimulatePerforate Change Approved ProgramPull TubingSuspend Perforate New Pool Re-enter Susp Well Other:Alter CasingPlug for Redrill 5. Permit to Drill Number:4. Current Well Class:2. Operator Name: DevelopmentExploratory 3. Address:ServiceStratigraphic 6. API Number: 8. Well Name and Number:7. If perforating: What Regulation or Conservation Order governs well spacing in this pool? NoWill planned perforations require a spacing exception? Yes 10. Field:9. Property Designation (Lease Number): 11. Junk (MD):Plugs (MD):MPSP (psi):Effective Depth TVD:Effective Depth MD:Total Depth TVD (ft):Total Depth MD (ft): 9198'9400' CollapseCasing Structural Conductor Surface Intermediate Production Liner Packers and SSSV MD (ft) and TVD (ft):Packers and SSSV Type: 13. Well Class after proposed work:12. Attachments: Proposal Summary Wellbore schematic ServiceDevelopmentExploratory StratigraphicDetailed Operations Program BOP Sketch 15. Well Status after proposed work:14. Estimated Date for WDSPLWINJOILCommencing Operations:Suspended WAGGASDate:16. Verbal Approval:SPLUGGSTOR AOGCC Representative: GINJ AbandonedOp Shutdown Contact Name: Contact Email: Contact Phone: Authorized Title: Sundry Number:Conditions of approval: Notify AOGCC so that a representative may witness Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other: Post Initial Injection MIT Req'd? NoYes Spacing Exception Required? Subsequent Form Required:NoYes APPROVED BY Date:COMMISSIONERApproved by:THE AOGCC Sr Res EngSr Pet GeoSr Pet EngComm.Comm. 9047-9137' 9358' 3-1/2" x 2-7/8"5811-5845' 7" 16" 9-5/8" 85' 2585' Perforation Depth MD (ft): MD 115' 2615' 115' 2616' 5941'9389' SizeLength BurstTVD PRESENT WELL CONDITION SUMMARY 8869'1440 psi5745'8869'5945' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0380107 201-040 P.O. Box 100360, Anchorage, AK 99510 50-103-20361-01-00 ConocoPhillips Alaska, Inc. KRU 3S-26 Kuparuk River Field N/A Tubing MD (ft):Tubing Grade: 8881' MD and 5749' TVD 506' MD and 506' TVD Tubing Size:Perforation Depth TVD (ft): 9002'L-80 Packer: Baker SAB-3 Packer SSSV: Camco DS NoGo Nipple 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: AOGCC USE ONLY Dusty Ward dusty.ward@conocophillips.com (907) 265-6531 Senior Workover Engineer Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Current Pools: N/A Proposed Pools: N/A 5/1/2023 By Samantha Carlisle at 11:01 am, Feb 13, 2023 323-088 X VTL 02/15/23 X DSR-2/13/23 BOPtestto2500psig Annular preventer to 2500 psig DLB 02/15/2023 X VTL 02/16/2023 X 10-407 GCW 02/22/23 JLC 2/22/2023 2/22/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.22 15:31:34 -09'00' RBDMS JSB 022323 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 January 25, 2023 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: Dusty K Ward Senior Wells Engineer CPAI Drilling and Wells ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to work over KUP Injector 3S-26 (PTD# 201-040). Well 3S-26 was drilled and completedas a Kuparuk Injector in February 2001. The well has been slated to be P&A'd for development of the Coyote formation. If you have any questions or require any further information, please contact me at +1503-476-2519. After a traditional Kuparuk P&A that has already had sundry approval, the tubing will be cut above tubing cement retainer/top of cement. Then a rig will come and pull the 3.5" tubing and stack two 7-1/16" valves on the wellhead. This will give eline and coiled tubing access to the 7" casing. The OA cement and final P&A deatils of the well will be submitted in a separate sundry. This sundry is just for the rig portion of the work that requires pulling the 3.5" tubing. 3S-26 RWO Procedure Kuparuk Injector Suspend PTD # 201-040 Page 1 of 2 Remaining Pre-Rig Work 1. T-PPPOT and T-POT tests. 2. Cut the tubing above tagged top of cement. 3. Prepare well for rig 48-72 hours before rig arrival. Rig Work MIRU 1. MIRU Nabors 7ES on 3S-26. (No BPV will be install pre-rig due to internal risk assessment for N7ES for MIRU/RDMO without a BPV.) 2. Record shut-in pressures on the T & IA. If there is pressure, bleed off IA and/or tubing pressure and complete 30-minute NFT. Verify well is dead. Circulate KWF as needed. 3. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/2,500 psi. Test annular 250/2,500 psi. Retrieve Tubing Section 4. Pull BPV, MU landing joint and BOLDS. 5. Pull 3-1/2” tubing down to pre-rig cut. a. On POOH with tubing, circulate well over to diesel freeze protect as necessary. 6. Perform 30 minute NFT. ND BOP, NU Tree 7. ND BOPE. NU two 7-1/16” tree valves and any adapter spool. 8. RDMO. Post-Rig Work - Post-rig scope will be submitted as a separate sundry for OA cement job and final P&A. 3S-26 RWO Procedure Kuparuk Injector Suspend PTD # 201-040 Page 2 of 2 General Well info: Wellhead type/pressure rating: FMC Gen 5 Production Engineer: Brian Lewis Reservoir Development Engineer: Lynn Aleshire Estimated Start Date: 3/20/2023 Workover Engineer: Dusty Ward (265-6531/ dusty.ward@conocophillips.com) Current Operations: This well is currently shut in the lower Kuparuk is P&A’d. Well Type: Producer Scope of Work: Pull the existing 3-1/2” completion down to pre-rig cut. Stack two 7-1/16” valves for Eline and coil unit OA cement operations post-rig. BOP configuration: Annular / Pipe Rams / Blind Rams / Pipe Ram Following subject to change/be updated with pre-rig work: MIT results: MIT-T Passed to 1500 psig on 8/13/2022. (Well is P&A’d and tubing will be cut for RWO.) CMIT-TxIA Passed to 1500 psig on 8/12/2022. MIT-OA N/A IC POT & PPPOT PASSED – None Recent. TBG POT & PPPOT PASSED – None Recent. MPSP: 1440 psi using 0.1 psi/ft gradient Static BHP: 1857 psi / 4166’ TVD estimated from 3S-24B BHP. Rig work should be done over P&A’d well and not exposed to formation pressure during Rig portion of work. 3S-26 Proposed Suspended Completion COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread (top) Thread (btm) Conductor 115 115 16 15.06 65.5 H40 Welded Welded Surface 2616 2615 9.625 8.92 36 J55 BTC BTC Production/ Intermediate 9389 5941 7 6.28 26 J55 BTCM BTCM PROPOSED COMPLETION 3.5" Completion REMOVED Install two 7-1/16" Gate Valves (Freeze Protect when pulling 3.5" out of hole.) REMAINING COMPLETION LEFT IN HOLE P&A'd lower Kuparuk (Already done.) 3.5" Tubing Stub Top Approximately ~8845' RKB Surface Casing 7" Production Casing Conductor C and A-sand perfs Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM 8,869.0 3S-26 8/12/2022 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Tag TOC 3S-26 8/12/2022 rogerba Notes: General & Safety Annotation End Date Last Mod By NOTE: DRILLED AS PALM 1A, EXPLORATORY WELL 4/11/2002 WV5.3 Conversio n Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 30.0 Set Depth (ft… 115.0 Set Depth … 115.0 Wt/Len (lb/ft) 65.50 Grade Top Connection WELD Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.92 Top (ftKB) 31.0 Set Depth (ft… 2,616.0 Set Depth … 2,615.4 Wt/Len (lb/ft) 36.00 Grade J-55 Top Connection BTCM Casing Description PRODUCTION OD (in) 7 ID (in) 6.28 Top (ftKB) 31.0 Set Depth (ft… 9,389.0 Set Depth … 5,940.6 Wt/Len (lb/ft) 26.00 Grade J-55 Top Connection BTCM Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 29.6 Set Depth … 5,794.5 String Ma… 3 1/2 Tubing Description TUBING - 3.5" x 2.875" @ 8999.3 Set Depth (ftKB) 9,002.3 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rdMOD 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) 29.6 29.6 0.00 HANGER 8.000 FMC GEN IV TUBING HANGER 3.500 506.3 506.3 0.89 NIPPLE 4.563 CAMCO DS NO GO NIPPLE 2.875 2,514.7 2,514.2 0.88 GAS LIFT 5.390 CAMCO KBMM-2 2.920 3,995.3 3,784.0 59.22 GAS LIFT 5.390 CAMCO KBMM-2 2.920 6,194.3 4,675.0 66.40 GAS LIFT 5.390 CAMCO KBMM-2 2.920 7,764.7 5,307.6 66.26 GAS LIFT 5.390 CAMCO KBMM-2 2.920 8,777.1 5,710.0 67.13 GAS LIFT 5.390 CAMCO KBMM-2 2.920 8,819.2 5,726.2 67.75 SLEEVE-C 4.375 BAKER CMU SLIDING SLEEVE (CLOSED 11/9/2002) 2.812 8,859.3 5,741.2 68.07 SEAL ASSY 4.500 BAKER SEAL ASSEMBLY 3.000 8,860.3 5,741.6 68.07 PBR 5.875 BAKER POLISHED BORE RECEPTACLE 3.000 8,880.1 5,749.0 68.10 SEAL NIPPLE 3.500 BAKER TUBING ANCHOR MODEL K-22 w/TUBING SEAL NIPPLE 2.992 8,881.0 5,749.3 68.10 PACKER 5.937 BAKER SAB-3 PACKER 3.250 8,987.9 5,789.1 68.07 NIPPLE 4.250 HOWCO XN NO GO NIPPLE W/ XXN PLUG 2.750 9,000.0 5,793.7 68.05 PORTED SUB BIT 3.380 HOWCO PORTED BUT (BALANCED ISOLATION TOOL) 1.500 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Make Model SN ID (in) 8,869.0 5,744.9 68.08 TUBING PLUG Pumped 24 bbls of 15.8 ppg cement. 19.4 bbls below and 2 bbls on top. 0.000 8,905.0 5,758.3 68.14 CEMENT RETAINER 2.725 ALAPHA FH 1 TRIP SLEEVE VALVE CEMENT RETAINER 0.000 9,198.0 5,867.9 67.74 FISH HOWCO 4 5/8" Scallop Gun, 5 spf w/27' of stim sleeves; tubing auto release & space 3'x15' (RELEASED & DROPPED 4/1/01 WHEN FIRED) 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) 2,514.7 2,514.2 0.88 1 GAS LIFT DMY BK 1 0.0 5/16/2015 0.000 3,995.3 3,784.0 59.22 2 GAS LIFT DMY BK5 1 0.0 3/13/2001 0.000 6,194.3 4,675.0 66.40 3 GAS LIFT DMY BK5 1 0.0 3/13/2001 0.000 7,764.7 5,307.6 66.26 4 GAS LIFT DMY BK5 1 0.0 3/13/2001 0.000 8,777.1 5,710.0 67.13 5 GAS LIFT DMY BK5 1 0.0 3/13/2001 0.000 8,934.2 5,769.1 68.18 6 PROD DMY BK5 1 0.0 3/13/2001 0.000 8,961.1 5,779.1 68.13 7 PROD OPEN OPEN 1 0.0 6/27/2022 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 9,047.0 9,137.0 5,811.3 5,844.9 C-4, 3S-26 4/1/2001 5.0 PERF 4 5/8" Scallop TCP guns 3S-26, 8/13/2022 8:45:58 AM Vertical schematic (actual) PRODUCTION; 31.0-9,389.0 FISH; 9,198.0 PERF; 9,047.0-9,137.0 TUBING PLUG; 8,869.0 PORTED SUB BIT; 9,000.0 NIPPLE; 8,987.9 PRODUCTION; 8,961.1 PRODUCTION; 8,934.2 CEMENT RETAINER; 8,905.0 PACKER; 8,881.0 SEAL NIPPLE; 8,880.1 PBR; 8,860.3 SEAL ASSY; 8,859.3 SLEEVE-C; 8,819.2 GAS LIFT; 8,777.1 GAS LIFT; 7,764.7 GAS LIFT; 6,194.3 GAS LIFT; 3,995.3 SURFACE; 31.0-2,616.0 GAS LIFT; 2,514.8 NIPPLE; 506.4 CONDUCTOR; 30.0-115.0 HANGER; 29.6 KUP INJ KB-Grd (ft) 37.38 RR Date 2/21/2001 Other Elev… 3S-26 ... TD Act Btm (ftKB) 9,400.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 501032036101 Wellbore Status INJ Max Angle & MD Incl (°) 68.18 MD (ftKB) 8,935.10 WELLNAME WELLBORE3S-26 Annotation Last WO: End DateH2S (ppm) 0 Date 1/2/2003 Comment SSSV: NIPPLE ISSUED AS:PRELIMINARYDATE:ISSUED BY:AS BUILTFOR:APPROVALMARK-UPQUOTEREVIEW07-JUN-21PKMXX17'-314"[5261]3'-912"[1156]4'-734"[1418]2'-0"[610]2'-934"[859]2'-0"[610]2'-0"[610]BY NABORSBY OPERATORPIPE RAMCL WELLCHOKE LINE7BILL OF MATERIALS413121NOQTY DESCRIPTIONBOP, RAM 1358" 5M CAMERON "U" (DOUBLE)1DRILL SPOOL 1358" 5M w/ (2) 318" 5M OUTLETS.BOP, RAM 1358" 5M CAMERON "U" (SINGLE)36GATE VALVE, MANUAL 318" 5MGATE VALVE, HYDRAULIC 318" 5M22BOP, ANNULAR 1358" 5M CAMERON T-9012434455556724" HEIGHT.678KILL LINE5API TARGET BLIND FLANGE 318" 5M48DSA 318"5M x 2116" 5M1FF-TICKET #:THIS DRAWING IS SHOWN TRUE SCALE ONLY WHEN PRINTED ON THIS SIZE PAPERTHIS DOCUMENT AND THE INFORMATION CONTAINED HEREIN IS A CONFIDENTIAL DISCLOSURE. IT IS SHOWN TO YOUR COMPANY WITH THE UNDERSTANDING IT IS NOT TO BEREVEALED TO OTHERS OR USED FOR ANY PURPOSE WITHOUT THE WRITTEN CONSENT OF NABORS INDUSTRIES.REV.XREFDESCRIPTION APP.DATEBYTITLE COPYRIGHTED©DATE:DRN BY:ER:BDWG:APP:RIG:SCALE:NABORSSHT NO. OFNABORS RIG 7ES13 5/8" 5M BOP STACK LAYOUT14002 7ESPKM NTS27-MAY-21 SMB7ES-0008-01B REVISED AND ISSUED FOR INFORMATION 07-JUN-21 PKM3470945 01 01DRILLER SIDEOFF DRILLER SIDE MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 18 Township: 12N Range: 8E Meridian: Umiat Drilling Rig: NA Rig Elevation: NA Total Depth: 9400 ft MD Lease No.: ADL0380107 Operator Rep: Suspend: X P&A: Conductor: 16" O.D. Shoe@ 115 Feet Csg Cut@ Feet Surface: 9 5/8" O.D. Shoe@ 2616 Feet Csg Cut@ Feet Intermediate: O.D. Shoe@ Feet Csg Cut@ Feet Production: 7" O.D. Shoe@ 9389 Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: 3 1/2" X 2 7/8" O.D. Tail@ 9002 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Tubing Retainer 8905 ft 8840 ft 7.1 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1670 1620 1600 IA 150 150 150 OA 325 325 325 Initial 15 min 30 min 45 min Result Tubing 660 930 1050 IA 1650 1540 1510 OA 445 460 465 Remarks: Attachments: Brent Rodgers P Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Suspension plug. Inspector Bob Noble and I arirved on location; talk with S/L unit operator then witnessed run in the hole with a bailer for plug tag. Pick up and set down 3 times after initial tag - call depth 8840 ft MD. Waivered well T X IA; MITT & MIT-IA went well. Location was in good order. August 12, 2022 Kam StJohn Plug Verification KRU 3S-26 ConocoPhillips Alaska Inc. PTD 2010400; Sundry 322-153 Photo of Bailer Sampler Returns Test Data: P Casing Removal: rev. 11-28-18 2022-0812_Plug_Verification_KRU_3S-26_ksj ! 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"+ 6 #.8 % 0A9 (:#L 00'@ ( )*$%C @@4 0'@ '7 < 9 /D2@ + ,-./ ! : %% !' 43";244"3;244<2)" 44 <@ 7 & A ; CK &@ 3 A &@ '<K M ; 0 C +2 3 45 3 6! : /7+ , '89 9 ; /34 '@ N !-"=/ 01/ / 4)7;4 1 )733524 /7./+ '+ 89 9 ) 23'6' ## / + + 4 4;41 )733524 * 23'6'!3& ## / DD'6'/ " / <30 8 #/D2@ ( ! %# !' ! • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Thursday,September 08,2016 Jim Regg P.I.Supervisor CIiklika SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 3S-26 FROM: Johnnie Hill KUPARUK RIV UNIT 3S-26 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry J1 ,2._ NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 3S-26 API Well Number 50-103-20361-01-00 Inspector Name: Johnnie Hill Permit Number: 201-040-0 Inspection Date: 8/18/2016 Insp Num: mitJWH160818183714 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 3S-26 ,- Type Inj W' TVD 5749 - Tubing 2480 . 2480 - 2480, 2480 PTD 1 2010400 Type Test SPT 1Test psi 3000 , IA 705 3300 .. 3230 . 3220 , 1 Interval RSQVAR IP/F P V OA 420 605 . 600 600 Notes: MITIA per AIO 2C.036 4.8bbls of diesel used SCANNED jUN 2 3201/ Thursday,September 08,2016 Page 1 of 1 • S Wallace, Chris D (DOA) From: NSK Problem Well Supv <n1617@conocophillips.com> Sent: Thursday, May 12, 2016 4:49 PM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler Subject: KRU 3S-26 (PTD# 201-040)IA re-pressurization Attachments: KRU 3S-26 TIO Plot_90 days.docx; 3S-26.pdf Chris, KRU injector 3S-26 (PTD#201-040) has shown signs of IA re-pressurization. CPAI intends to WAG the well to water injection and perform initial diagnostics including pack off tests and an MIT-IA. If the MIT passes, the well will be monitored for a 30 day period while on water injection to prove integrity. At the conclusion of the monitor period, a follow-up email with a plan forward will be submitted. Attached are a 90 day T/I/O plot and wellbore schematic. Please let me know if you have any questions or disagree with this plan. Regards, Rachel Kautz 1 g 7,0$ Well Integrity Engineer SCO*33 MA's ConocoPhillips Alaska, Inc. Temp.Slope Phone:907-659-7126 1 • S Well Name 3S-26 Notes: Start Date 2/12/2016 Days 90 End Date 5/12/2016 Annular Communication Surveillance 4GZ,C, - — 14Z, MIHP IAP — � — 1 SZ, LL Co O. — c,p 1`_iC — a�-13 Feb-16 Feb-16 Mar-16 Mar-16 Mar-16 Mar-16 Apr-16 Apr-16 Apr-16 May-1€ Way-16 e»? _JJJ d d JJJJ- Jan-16 Feb-16 Feb-16 Mar-16 Mar-16 Mar-16 Mar-1e Apr-16 Apr-16 Apr-16 May-16 May-'6 Date • Wallace, Chris D (DOA) From: NSK Problem Well Supv <n1617@conocophillips.com> Sent: Saturday, December 19, 2015 8:26 AM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler; NSK Problem Well Supv Subject: RE: 35-26 (PTD#201-040) Update 12/19/15 Attachments: 3S-26 90 day TIO 12-19-15.JPG Chris, KRU injector 3S-26 (PTD 201-040) has completed the 30 day monitor period on gas injection with no signs of TxIA communication. As the well has demonstrated tubing integrity while on gas injection, CPAI intends to leave the well's status as a 'normal' WAG injection well. If at any time in the future the well exhibits signs of annular communication, notification will be made to the AOGCC and proper actions will be taken to ensure the well remains in compliance. I have attached a 30 day TIO trend. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne/ Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7126 Pager(907) 659-7000 pgr. 123 WELLS TEAM DINED SEP 1 92016 ConocoPI ps From: NSK Problem Well Supv Sent: Thursday, November 19, 2015 8:32 AM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler; NSK Problem Well Supv Subject: RE: 3S-26 (PTD#201-040) Update 11/19/15 Chris, KRU injector 3S-26 (PTD 201-040) has completed the 30 day monitor period on water with no signs of TxIA communication. Prior to starting the 30 day monitor period an improved isolation sleeve with more robust packing was installed over the CMU. CPAI intends to WAG the well to gas for a 30 day monitor period to determine if the improved isolation sleeve eliminates the TxIA communication while on gas injection. Upon conclusion of the monitor period or after any changes to the plan notification will be made and any required paperw.rk will be submitted. Attached is a 90 day TIO trend. Please let us know if you disagree or have any questions with this plan. 1 L. . 0..) 5 _ S tt U..i •-> ul ci, Q cc = Lu 17 1--- 4 D C) 0 Lu co a c-1 a. ii. 5 2 UL—I- •-- 'E Cir 73 o a z a L4.1 Lu a. IX 1-- ut —„-, .m La c‘4- t- co at I co J CV ...I , tA..1 (I) On C3 CI . A6ap " 61 c3 c3 C3 Co 0 tO „.. ,- Cu cC. .1 Cu 0`-', .1- t c 03 '5) I ) C '1 L'ILIP 11 '-,L1 - 6 ca to 1 vt-S el 01 —... 03 1 . -.1--- iiim----- cr"---- (i) u. 4 LA Cly • , P / (13 , - :. U 0 a cm 1 ._ __ . , 3 , E WIN E , c III O , O , 03 c 0 3 . O C i E CX i Lin WI .1, v... CO cz C" r`,J est cx ' tn c, at at --soot— 0. I.1ii : .__ ---- I a..a ..-- H ' , gri C o o o o o o o o Grj 1 C Pilifkil " 'Y') CI Li I CI LI 1 C:3 li 1 c3 5, (ki,irhom ....• .. RI C • • • Wallace, Chris D (DOA) From: NSK Problem Well Supv <n1617@conocophillips.com> Sent: Thursday, November 19, 2015 8:32 AM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler; NSK Problem Well Supv Subject: RE: 3S-26 (PTD#201-040) Update 11/19/15 Attachments: 3S-26 90 day TIO 11-19-15.JPG Chris, KRU injector 3S-26 (PTD 201-040) has completed the 30 day monitor period on water with no signs of TxIA communication. Prior to starting the 30 day monitor period an improved isolation sleeve with more robust packing was installed over the CMU. CPAI intends to WAG the well to gas for a 30 day monitor period to determine if the improved isolation sleeve eliminates the TxIA communication while on gas injection. Upon conclusion of the monitor period or after any changes to the plan notification will be made and any required paperwork will be submitted. Attached is a 90 day TIO trend. Please let us know if you disagree or have any questions with this plan. Regards, Jan Byrne/ Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7126 SW'►�`Nf ,,..��YY p MAY 1 12016 Pager(907) 659-7000 pgr. 123 WELLS TEAM ConocoPhillips From: NSK Problem Well Supv Sent: Monday, October 19, 2015 2:52 PM To: Wallace, (DOA) Cc: Senden, R. Tyler; NW-Problem Well Supv Subject: RE: 3S-26 (PTD#201-0 Update 10/19/15 Chris, KRU injector 3S-26 (PTD 201-040) exhibited TxIA commu 3 ation during the 30 day gas injection monitor period. The plan is to WAG to well back to water as soon as possible and begin a 30 day monitor. The IA pressure will be bled down to prove tubing integrity to water. If the well demonstrates TxIA i unication while on water injection the well will be shut in and freeze protected. Upon conclusion of the monitor period Xchange in the plan forward notification will be made and any required paperwork will be submitted. Attached is a 90 da\if and wellbore schematic. Please let us know if you disagree or have any questions with this plan. 1 w • so . z,. u., _, ,,,,, a cc . Lu f- a D U 0 0 o w CO Ce r, Cir a OIA O m CL a G v x y w m Vi 0 UJ O C Ln C. H tel Ln 0 N M co G Ji (D V M GJs, d 6 a p V C - U O CJ J CV 41 u-1 <r (V V O I 1 a - a y 'V C] U i • • i O 0 i Z 1 in di C (013 owns' 1 . V/ o I u,Q -i ' ieil""."3 . if; co Q1 = 15 c CI q L p (1] • r CDC O ;V N0 N M N 1 T co r I gg g g g$ z9 A . o 0 0 CO 0 o v "'I $ $ R H •; '= ❑ c1 o 1, n 1, o uw t' N ❑ r, tv � 9gi ii MIMI , ; isd ❑ w 0 • RECEIVED O C T 2 3 2015 ConocoPhillips C Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 a0I - 6) October 20, 2015 �j Commissioner Cathy Foerster S(041) MA`( 1 '�01b 3 S Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Cathy Foerster: 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. These voids were filled with cement 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 attached spreadsheet presents the well name,top of cement depth prior to filling and volumes used on each conductor. Please call MJ Loveland at 907-659-7043, if you have any questions. Sincerely, MJ Lo eland ConocoPhillips Well Integrity Projects Supervisor 0 • ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations(10-404) Kuparuk Field Date 10/20/2015 3H,3J,3Q&3S Pad Corrosion Initial top of Vol.of cement Final top of Cement top off Corrosion inhibitor/ Well Name API# PTD# cement pumped cement date inhibitor sealant date ft bbls ft gal 3H-26 501032020800 1940290 9" NA 9" NA 4.3 10/9/2015 3J-18 500292270100 1961470 12" NA 12" NA 8 10/3/2015 3J-19 500292270200 1961480 11" NA 11" NA 4.25 10/5/2015 3Q-21 500292263000 1951930 12" NA 12" NA 5.5 10/9/2015 3S-6A 501032045401 2030880 11" NA 11" NA 9.1 10/3/2015 3S-23A 501032045301 2060430 16" NA 16" NA 6.2 10/3/2015 3S-24A 501032045601 2040610 18" NA 18" NA 6.3 10/3/2015 3S 26 501032036101 2010400 9" NA 9" NA 3.8 10/3/2015 1k. :C STATE OF ALASKA ` ALSA OIL AND GAS CONSERVATION CON�SION l� 2015 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon Plu Perforations Pull Tubing r ' Operations shutdown (� 9 � Fracture Stimulate (� I Performed: Suspend rl Perforate rl Other Stimulate r Alter Casing r Change Approved Program Rug for Redrill r Perforate New Pool Repair Well r Re-enter Susp Well r Other:Cond Extension 17 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory r 201-040 3.Address: 6.API Number: P. O. Box 100360,Anchorage,Alaska 99510 Stratigraphic Service 50-103-20361-01 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0380107 KRU 3S-26 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): NA Kuparuk River Field/Kuparuk River Oil Pool 11.Present Well Condition Summary: Total Depth measured 9400 feet Plugs(measured) None true vertical 5945 feet Junk(measured) None Effective Depth measured 9058 feet Packer(measured) 8881 true vertical 5815 feet (true vertical) 5749 Casing Length Size MD TVD Burst Collapse CONDUCTOR 86 16 115 115 1640 630 SURFACE 2585 9-5/8 2616 2615 3520 2020 PRODUCTION 9358 7 9389 5941 4980 4330 Perforation depth: Measured depth: 9047'-9137' True Vertical Depth: 5811'-5845' a (,);(-' SCN Tubing(size,grade,MD,and TVD) 4.5, L-80, 9000 MD, 5794 TVD Packers&SSSV(type,MD,and TVD) PACKER= BAKER SAB-3 PACKER @ 8881 MD and 5749 TVD SSSV=CAMCO DS NO GO NIPPLE @ 506 MD and 506 TVD 12.Stimulation or cement squeeze summary: Intervals treated(measured): NA Treatment descriptions including volumes used and final pressure: 13. 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 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 17 Exploratory fl Development fl Service F7 Stratigraphic r Copies of Logs and Surveys Run r 16.Well Status after work: Oil r Gas r WDSPL r Printed and Bectronic Fracture Stimulation Data r GSTOR r WINJ r WAG 17 GINJ r SUSP r SPLUG n 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: 315-433 Contact Martin Walters/MJ Loveland Email n1878conocophillips.com Printed Name Martin Walters Title Well Integrity Supervisor Signature Phone:659-7043 Date: 10/4/2015 oi)ah... vii-/o%2//S /e9/2.,//c RBDM9' (►L f 12 2015 Form 10-404 Revised 5/2015 Submit Original Only • 3S-26 • DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 09/19/15 Welder welded 9"x 16" .375 62#extension onto conductor. 10/03/15 Injected 3.8 gallons of RG2401 sealant into the conductor. v OF T4 ���w\�� �� THE STATE Alaska Oil and Gas of/� j /� S �T /�, Conservation Commission F .- ===-444'. � 1 1JI1 �.I1 fti i•�z_; _ :_ 333 West Seventh Avenue ' GOVERNOR BILL WALKER Anchoiage, Alaska 99501-3572 Main: 907.279.1433 ALAS Fax 907.276.7542 =; 'j www.aogcc alaska.gov Martin Walters /0 Well Integrity Supervisor a 0 17 `T ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 3S-26 Sundry Number: 315-433 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. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ,a/- 7,720..(_,,,th,_ Cathy P. Foerster �, Chair DATED this(�day of July, 2015 Encl. STATE OF ALASKA RECEIVED • A"SSKA OIL AND GAS CONSERVATION COM.„FISSION JUL 16 2015 APPLICATION FOR SUNDRY APPROVALS A -7/2$-i i S 20 AAC 25.280 AOGCC CC 1.Type of Request: Abandon r Rug Forforations r Fracture Stimulate r Pull Tubing r 7 \ Operations shutdown r Suspend r Perforate r Other Stimulate r Alter Casing J' Change Approved Program r Rug for Redrill r Perforate New Pool r Repair Well p_Re-enter Susp Well r Other:Cond Extension 2.Operator Name: 4.Current Well Class. 5 Permit to Drill Number. ConocoPhillips Alaska, Inc Exploratory r Development r 201-040 • 3 Address: Stratigraphic r Service r 6 API Number: P. O. Box 100360,Anchorage,Alaska 99510 50-103-20361-01 ' 7.If perforating, What 8.Well Name and Number: Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require spacing exceptions Yes r No F KRU 3S-26 • 9.Property Designation(Lease Number): 10 Field/Pool(s) ADL0380107 • Kuparuk River Field/Kuparuk River Oil Pool - 11. PRESENT WELL CONDITION SUMMARY Total depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft) Effective Depth TVD(ft <, Plugs(measured): Junk(measured): 9400 - _ 5945 - 9. i S C, S �S Casing Length Size MD TVD Burst Collapse CONDUCTOR 85 16 115' 115' 1640 630 SURFACE 2585 9-5/8 2616' 2615' 3520 2020 PRODUCTION 9358 7 9389' 5941' 4980 4330 Perforation Depth MD(ft): Perforation Depth TVD(ft) Tubing Size: Tubing Grade: Tubing MD(ft): _ 9047'-9137 ' 5811'-5845' 4 5 L-80 9000 Packers and SSSV Type Packers and SSSV MD(ft)and TVD(ft) PACKER=BAKER SAB-3 PACKER MD=8881 TVD=5749 " NIPPLE=CAMCO DS NO GO NIPPLE MD=506 TVD=506 12.Attachments Description Summary of Proposal [ 13. Well Class after proposed work Detailed Operations Program r BOP Sketch r Exploratory r Stratigraphic r Development r Service J. 14.Estimated Date for Commencing Operations: 15 Well Status after proposed work. 9/15/2015OIL r WINJ r WDSPL r Suspended r 16.Verbal Approval Date: GAS r WAG GSTOR r SPLUG r Commission Representative: GINJ r Op Shutdown r Abandoned r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge Contact: Martin Walters/MJ Loveland Email: n1878@cop.com Printed Name rtin alters Title Well Integrity Supervisor Signature /7/74%/,',‘61: f Phone:659-7043 Date:07/14/15 Commission Use Only Sundry Number: 2 Conditions of approval. Notify Commission so that a representative may witness 3 I rj" -7 U73 Plug Integrity r BOP Test r Mechanical Integrity Test r Location Clearance r Other: Spacing Exception Required? Yes ❑ No 12( Subsequent Form Required /(91—4 0* APPROVED BY _ Approved by: 44-(1-1-0Vp 'ORION IC0I10 lt`1PN71EOnt s from t11EcR OiS YOval. Date:'7.-2. -LS- Form / Q �/Z�i Subsin Form ane Form 10-403 Revis d 5 2015 L K� I) Attachm sin Duplicate VTC 7-/Z g/15 A 7izf(/S- RBDMS ) AUG - 2 2015 ConocoPhillips RECEIVED Alaska P.O. BOX 100360 J U L 16 2 015 ANCHORAGE,ALASKA 99510-0360 AOGCC July 14, 2015 Commissioner Cathy Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Foerster: Enclosed please find the 10-403 Application for Sundry Approvals for ConocoPhillips Alaska, Inc. well 3S-26, PTD 201-040 conductor extension. Please contact Martin Walters or MJ Loveland at 659-7043 if you have any questions. Sincerely, Martin Walters ConocoPhillips Well Integrity Projects Supervisor ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 ConocoPhillips Alaska, Inc. Kuparuk Well 3S-26 (PTD 201-040) SUNDRY NOTICE 10-403 APPROVAL REQUEST July 14, 2015 This application for Sundry approval for Kuparuk well 3 S-26 is to extend the conductor to original height so as to stabilize tree and prevent any corrosion to the surface. At some point during normal operations the conductor subsided about 9". With approval, the conductor extension will require the following general steps: 1. Remove landing ring from conductor if necessary. 2. Examine surface casing for any corrosion damage. 3. Extend the conductor to starter head and fill the void with cement and top off with sealant. 4. File 10-404 with the AOGCC post repair. NSK Well Integrity Projects Supervisor € KUP INJ 3S-26 Conoc Phillips ; Well Attributes Max Angle&MD TD Alaska Inc Wellbore API/UWI Field Name Wellbore Status lIncl(°) MD)ftKB) Act Btm(ftKB) G..:n IIfn 501032036101 KUPARUK RIVER UNIT INJ 68.18 8,935.10 9,400.0 -.- Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date 3S-26.5/22/2015 9:W.08 AM SSSV:NIPPLE 0 1/2/2003 Last WO: 37.38 2/21/2001 Vertical schematic(actua0 Annotation Depth(ftKB) End Date 'Annotation Last Mod By End Date Last Tag'.SLM 9,028.0 10/6/2013 Rev Reason:PULLED PLUG,SET ISO SLEEVE, lehallf 5/22/2015 ... .... .............. ......_.._... __._,... ...,....___. GLV C/O �li ii e Casing Strings Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth)T/D)... Wt/Len(I...Grade Top Thread HANGER.Zee I CONDUCTOR 16 15.062 30.0 115.0 115.0 65.50 WELD I Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len 0...Grade Top Thread • SURFACE _ 9 5/8 8.921 31.0 2,616.0 2,615.4 36.00 J-55 BTCM , . yr Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread „a....,PRODUCTION 7 6.276 31.0 9,389.0 5.940.6 26.00 J-55 BTCM CONDUCTOR:30.0-1150 a Tubing Strings Tubing Description String Me,..ID(in) Top(ftKB) j Set Depth(ft..Set Depth(ND)(...Wt(Ib/ft) Grade Top Connection TUBING-3.5"x 31/2 2.992 296 9.0023 5,794.5 9.30 L-80 EUE8rdMOD NIPPLE;506.4 - 2.875"p 8999.3 Completion Details Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Incl(°) Item Des Com (in) 29.6 29.6 0.00 HANGER FMC GEN IV TUBING HANGER 3.500 GAS LIFT:2,514.8 ? 506.3 506.3 0.89 NIPPLE CAMCO DS NO GO NIPPLE 2.875 8,819.2' 5,726.2. 67.75 SLEEVE-C BAKER CMU SLIDING SLEEVE(CLOSED 11/9/2002) 2.812 8,859.3 5,741.2 68.07 SEAL ASSY BAKER SEAL ASSEMBLY 3.000 SURFACE;31.0.2,616.0 - 8,860.3 5,741.6 68.07 PBR BAKER POLISHED BORE RECEPTACLE 3.000 8,880.1 5,749.0 68.10 SEAL NIPPLE BAKER TUBING ANCHOR MODEL K-22 w/TUBING 2992 SEAL NIPPLE 8,881.0 5,749.3 68.10 PACKER BAKER SAB-3 PACKER 3.250 GAS LIFT;3,995.3 8,987.9 5,789.1 68.07 NIPPLE HOWCO XN NO GO NIPPLE W/XXN PLUG 2.750 9,000.0 5,793.7 68.05 PORTED SUB HOWCO PORTED BUT(BALANCED ISOLATION TOOL) .I 1.500 BIT Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) Top(ND) Top Incl Top(ftKB) (MB) I") Des Com Run Date ID(in) GAS LIFT;6,194.311 8,819.0 5,726.1 67.74 SLEEVE AVA ISO SLEEVE(OAL 59.5") 5/18/2015 2.290 9,198.0' 5,867.9' 67.74 FISH HOWCO 4 5/8"Scallop Gun,5 spf w/27'of slim 3/13/2001 - 0.000 sleeves;tubing auto release&space 3'x15'(RELEASED&DROPPED 4/1/01 WHEN FIRED) Perforations&Slots GAS LIFT;7,764.7 - - r Shot Dens Top(TVD) Bier(TVD) (shots/f -- Top(NCB) Btrn(RKB) (N(B) (NCB) Zone Date - 9 Type Com 9,047.0 9,137.0 5,811.3' 5,844.9 C-4,35-26 4/1/2001 5.0 PERF 4 5/8"Scallop TCP guns Mandrel Inserts GAS LIFT;8,777.1LE St ati on Top(ND) Valve Latch Port Size TRO Run -_ N Top(ftKB) (ftKB) Make Model OD(in) Sew Type Type (in) (psi) Run Date Com 1' 2,514.7 2,514.2 CAMCO KBMM- 1 GAS LIFT DMY BK 0.000 0.0 5/16/2015 2 _ gp 2 3,995.3 3,784.0 CAMCO KBMM- 1 GAS LIFT DMY BK5 0.000 0.0 3/13/2001 SLEEVE-C;8,819 2 ' 2 SLEEVE;8,819.0, J 3 6,194.3 4,675.0 CAMCO KBMM- 1 GAS LIFT DMY BK5 0000 0.0 3/13/2001 ' 2 4 7,764.7 5,307.6 CAMCO KBMM- 1 GAS LIFT DMY BK5 0.000 0.0 3/13/2001 2 ` _ 5 8,777.1 5,710.0 CAMCO KBMM- 1-.GAS LIFT DMY BK5 0.000 0.0 3/13/2001 2 SEAL ASSY,8.859.3 6 8,9342 5,769.1 CAMCO KBUG-2 1 PROD DMY BK5 0.000 0.0 3/13/2001 PBR;8.860.3 I 7 8,961.1 5,779.1 CAMCO KBUG-2 1 PROD DMY BK5 0.000 0.0'3/132001 4/112002 Date NOTE:DRILLEDLLAS PALM 1A,EXPLORATORY Notes:General&Safe SEAL NIPPLE;8,880.1Annotation WELL PACKER;8,881.0 _ 11/2/2010 NOTE:VIEW SCHEMATIC w/Alaska Schematic9.0 4/1/2013 NOTE:SET 2.813"XXN PLUG IN XN NIPPLE @ 8988'RKB PRODUCTION;8,934.2 PRODUCTION,8961.1 NIPPLE;8,987.9 PORTED SUB BIT;8,000.0 PERF;9.047.09.137.0- FISH;9,198.0 PRODUCTION;31.0.9,389.0 Bettis, Patricia K (DOA) From: NSK Well Integrity Proj <N1878@conocophillips.com> Sent: Thursday,July 23, 2015 5:56 PM To: Bettis, Patricia K (DOA) Subject: RE: KRU 3S-26: Sundry Application TD = 9400 RKB, 5945 TVD Effect Depth = 9156 RKB, 5852 TVD MJ Loveland / Martin Walters Well Integrity Project Supervisor ConocoPhillips Alaska, Inc. Office (907) 659-7043 MJ's Cell (907) 943-1687 From: Bettis, Patricia K(DOA) [mailto:patricia.bettis@alaska.gov] Sent:Thursday,July 16, 2015 9:47 AM To: NSK Well Integrity Proj Subject: [EXTERNAL]KRU 3S-26: Sundry Application Good morning Martin, Please advise what the current plug back depth is for the KRU 3S-26 well. It was missing from the sundry application. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Thursday, July 16, 2015 9:47 AM To: NSK Well Integrity Proj (N1878@conocophillips.com) Subject: KRU 3S-26: Sundry Application Good morning Martin, Please advise what the current plug back depth is for the KRU 3S-26 well. It was missing from the sundry application. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you, contact Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission ; TO: Jim Regg �f 6 I J/ DATE: Monday,June 01,2015 P.I.Supervisor t 'Z I ✓ SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 3S-26 FROM: Lou Grimaldi KUPARUK RIV UNIT 3S-26 Petroleum Inspector Src: Inspector Reviewed B P.I.Supry 3 4R-- NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 3S-26 API Well Number 50-103-20361-01-00 Inspector Name: Lou Grimaldi Permit Number: 201-040-0 Inspection Date: 5/28/2015 Insp Num: mitLG150528213027 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well I 3S-26 Type InjW'TVD 5749 - -'Tubing' 1340 1 1340 I 1340 1340 - ' --- PTDt 2010400 - Type Test SPT Test psi 1500 ' IA 640 2200. 2160 - 2140 - Interval 4YRTST P/F P ✓ OA 515 635 - 635 . 635 ' Notes: 2,6 bbl's diesel pumped&returned.Good solid test All required paperwork supplied prior to test. ,/ Nle) ULI3 ? �� Monday,June 01,2015 Page 1 of 1 STATE OF ALASKA ALA:_ _ .OIL AND GAS CONSERVATION COMM. ,ON REPORT OF SUNDRY WELL OPERATIONS 1 Operations Abandon r Plug Perforations r Fracture Stimulate r Pull Tubing r Operations shutdown r Performed Suspend r Perforate r Other Stimulate rAlter Casing r Change Approved Program r Rug for Redrill r Perforate New Pool r Repair Well r Re-enter Susp Well r Other:Isolation Sleeve 17 2.Operator Name: 4 Well Class Before Work: 5.Permit to Drill Number ConocoPhillips Alaska, Inc. Development r Exploratory r 201-040 3.Address 6.API Number: P. O. Box 100360, Anchorage,Alaska 99510 Stratigraphic r Service I 50-103-20361-01 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0380107 KRU 3S-26 _ 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kuparuk River Field/Kuparuk River Oil Pool 11.Present Well Condition Summary: Total Depth measured 9400 feet Plugs(measured) None true vertical 5945 feet Junk(measured) None Effective Depth measured 0 feet Packer(measured) 8819, 8881 true vertical 0 feet (true vertical) 5726, 5749 Casing Length Size .- MD TVD Burst Collapse CONDUCTOR 85 16 115 115 0 0 SURFACE 2585 9 625 2616 2615 0 0 PRODUCTION 9358 7 9389 5941 0 0 Perforation depth: Measured depth: 9047 RECEIVED True Vertical Depth 5811 AW 11, l 09nib MAY 262015 Tubing(size,grade,MD,and TVD) 3.5, 0, 9000 MD, 5794 TVD AOGCC Packers&SSSV(type,MD,and TVD) SLEEVE-C-BAKER CMU SLIDING SLEEVE(CLOSED 11/9/2002) @ 8819 MD and 57261TVD PACKER-BAKER SAB-3 PACKER @ 8881 MD and 5749 TVD 1 12 Stimulation or cement squeeze summary: N/A 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 Casing Pressure Tubing Pressure Prior to well operation N/A N/A N/A N/A N/A Subsequent to operation N/A N/A N/A N/A N/A Daily Report of Well Operations r 14.Attachments(required per 20 AAC 25.070,25 071,&25 283) 15.Well Class after work. Copies of Logs and Surveys Run r Exploratory r Development r Service P Stratigraphic r 16.Well Status after work: Oil r Gas r WDSPL r Printed and Bectronic Fracture Stimulation Data r GSTOR r VVINJ r WAG F GINJ r SUSP r SPLUG r 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 N/A Contact Dusty Freeborn/Jan Byrne Email N1617(a)conocophillips.com I Printed Name Dust Freeborn Title Problem Wells Supervisor Signature Phone:659-7126 Date:5/19/15 6.T1- 6//9//5I RBDMS. * MO 2 9 2015 Form 10-404 Revised 5/2015 Submit Original Only ConocoPhillips RECEIVED VED Alaska MAY 2 6 2015 P.O. BOX 100360 AOGCC ANCHORAGE,ALASKA 99510-0360 th 19day of May 2015 Mrs. Cathy Foerster Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster, Enclosed please find the 10-404 Report of Sundry Operations for ConocoPhillips Alaska, Inc. KRU well 3S-26 (PTD 201-040-0) for an isolation sleeve set within the CMU to restore tubing by inner annulus integrity. Please call Jan Byrne or myself at 659-7126 if you have any questions. Sincerely, /11,11# Dusty Freeborn Problem Wells Supervisor 3S-26 DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 08/01/1. Diagnostic MIT-IA failed 03/26/15 Diagnostic CMIT-TxIA passed 03/29/15 Tubing PO tests passed 05/17/15 Isolation sleeve set acrossed CMU. MIT-IA and IA DDT passed. 5/17-18/2015 Unable to cycle CMU to closed position, Isolation sleeve reset in CMU 3S-26 DESCRIPTION OF WORK COMPLETED SUMMARY • KUP INJ 3S-26 ConocoPhillips ; Well Attributes Max Angle&MD TD Alaska Inc. Wellbore API/UWI Field Name Wellbore Status ncl(°) MD(ftKB) Act Btm(ftKB) cr.ronYtieio, 501032036101 KUPARUK RIVER UNIT INJ s 68.18 8,935.10 9400.0 ... Comment H2S(ppm) Date Annotation End Date KBGrd(ft) Rig Release Date 3S-26,5/22/20159.00:08 AM SSSV:NIPPLE 0 1/2/2003 Last WO: 37.38 2/21/2001 Verb al schematic(actual) Annotation Depth(ftKB) End Date Annotation last Mod By End Date Last Tag:SLM 9,028.0 10/6/2013 Rev Reason:PULLED PLUG,SET ISO SLEEVE, lehallf 5/22/2015 GLV C/0 �il F Casing Strings Casing Description OD(in) ID(in) Top((KB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread HANGER.29.6 CONDUCTOR 16 15.062 30.0 115.0 115.0 65.50 WELD 4.I Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread SURFACE 9 5/8 8.921 31.0 2,616.0 2,615.4 36.00 J-55 BTCM ,,,,..,,sausai.,".."m..,a.,samm ntarul In ,a,Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread a...,PRODUCTION 7 6.276 31.0 9,389.0 5,940.6 26.00 J-55 BTCM CONDUCTOR;30.0-115.0-A . Tubing Strings Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..f Set Depth(ND)(...I Wt(Iblft) Grade Top Connection TUBING-3.5"x 31/2 2992 296 9.0023 5,7945 930 L-80 EUE8rdMOD NIPPLE;508.4 3 p 2.875"@ 8999.3 Completion Details I Nominal ID • Top(ftKB) Top(TVD)(ftKB) Top Incl(") Item Des Com (in) 29.6 29.6 0.00 HANGER FMC GEN IV TUBING HANGER 3.500 GAS LIFT;2514.8 506.3 506.3' 0.89'NIPPLE CAMCO DS NO GO NIPPLE 2.875 8,819.2 5,726.2 67.75 SLEEVE-C BAKER CMU SLIDING SLEEVE(CLOSED 11/9/2002) 2.812 8,859.3 5,741.2 68.07 SEAL ASSY BAKER SEAL ASSEMBLY 3.000 SURFACE;31.0-2.616.0 • • 8,860.3 5,741.6 68.07 PBR BAKER POLISHED BORE RECEPTACLE 3.000 2.992 8,880.1 5,749.0 68.10 SEAL NIPPLE BAKER TUBING ANCHOR MODEL K-22 w/TUBING SEAL NIPPLE 8,881.0 5,749.3 68.10 PACKER BAKER SAB-3 PACKER 3.250' GAS LIFT;3,995.3 g 007.0 5,789.1 68.07 NIPPLE HOWCO XN NO GO NIPPLE W/XXN PLUG 2.750 9,000.0 5,793.7 68.05 PORTED SUB HOWCO PORTED BUT(BALANCED ISOLATION TOOL) 1.500 BIT Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) Top(ND) Top Incl Top(ftKB) (ftKB) (') Des Com Run Date ID(in) GAS LIFT;6.194.3 8,819.0 5,726.1 67.74 SLEEVE AVA ISO SLEEVE(OAL 59.5") 5/18/2015 2.290 9,198.0 5,867.9- 67.74 FISH HOWCO 45/8"Scallop Gun,5 sof w/27'of slim 3/13/2001 0.000 sleeves;tubing auto release&space 3'x15'(RELEASED 8 DROPPED 4/1/01 WHEN FIRED) Perforations&Slots GAS LIFT;7,784.7II Shot I Dens Top(7VD) Blm(ND) (shots/f Top(81KB) Btm(ftKB) (KIM (/tl(B) _ Zone Date t) Type Com 9,047.0 9,137.0 5,811.3 5,544.9 C-0,3S-26 A 1/2001 5.0 PERF 4 5/8"Scallop TCP guns , Mandrel Inserts GAS LIFT;8,777.1lii S1 ati r Top(ND) Valve Latch Pon Size TRO Run N Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com 2,514.7 2,514.2 CAMCO KBMM- 1 GAS LIFT DMY BK 0.000 0.0 5/16/2015 2 Ten 2 3,995.3 3,784.0 CAMCO KBMM- 1 GAS LIFT DMY BK5 0.000 0.0 3/13/2001 SLEEVE-C,8,819.2 1l_ 2 SLEEVE;8,818.0 3 6,194.3 4,675.0 CAMCO KBMM- 1 GAS LIFT DMY BK5 0.000 0.0 3/13/2001 2 4 7,764.7 5,307.6 CAMCO KBMM- 1 GAS LIFT DMY BK5 0.000 0.0 3/13/2001 2 li 5 8,777.1 5,710.0 CAMCO KBMM- 1 GAS LIFT DMY BK5 0.000 0.0 3/13/2001 2 SEAL ASSY;8.859,3 - 6 8,934.2 5,769.1 CAMCO KBUG-2 1 PROD DMY BK5 0.000 0.0 3/13/2001 PBR;8.880.3 ) 7 8,961.1 5,779.1 CAMCO KBUG-2 1 PROD DMY BK5 0.000 0.0 3/13/2001 Notes:General&Safety SEAL NIPPLE;8,880.1 End Date Annotation 4/11/2002 NOTE:DRILLED AS PALM 1A,EXPLORATORY WELL PACKER:6,ee101. 11/2/2010 NOTE:VIEW SCHEMATIC w/Alaska Schematic9.0 4/1/2013 NOTE:SET 2.813"XXN PLUG IN XN NIPPLE @ 8988'RKB PRODUCTION;8,934.2 PRODUCTION;8.961.1 NIPPLE;8,987.9 PORTED SUB BIT;9,000.0 ` PERF;9,047.0.9,137.0- -,,,e2 fp!' FISH;9,198.0 . -._- PRODUCTION;310-9,389.0 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 j d _0 Attachments: Kuparuk Gas Injector Flow back Volumes.xls Tom, Attached you will find the Kuparuk Gas Injector Flowback information per your request. Ff.T286311 Bob Christensen / Darrell Humphrey NSK Production Engineering Specialist ConocoPhillips Alaska, Inc. Kuparuk Office: 907.659.7535 Kuparuk Pager: 659.7000; #924 CPAI Internal Mail: NSK -69 This email may contain confidential information. If you receive this e-mail in error, please notify the sender and delete this email immediately. L7 From: Maunder, Thomas E (DOA) [mailto:tom.maunder ©alaska.gov] 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 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. 1/27/2011 • • Page 2 of 3 Tom Maunder, PE AOGCC L ] From: NSK Prod Engr & Optimization Supv fmailto :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 I1 From: Maunder, Thomas E (DOA) jmailto: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 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 jmailto: n2046 conocophillips.coml 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. 'lowback Adjacent Estimated Prod ias Injector PTD# SI Producer PTD# (Mscfd) 9P -420 201 -182 2P -422A 202 -067 4,500 D1P-447 4g 203 -154 2P -448A 202 -005 2,000 2, U -03 185 -006 2U -02 185 -005 3,500 S -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 1/27/2011 • • Page 1 of 2 Maunder, Thomas E (DOA) From: Roby, David S (DOA) 0`--\, 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 *ANNEX JAN 1 8 20.1 From: Maunder, Thomas E (DOA) : Monday, January 10, 2011 4:38 PM To: Prod Engr & Optimization Supv Cc: Foers ; Catherine P (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA); Roby, David S DOA) Subject: RE: •equest for Approval Gary, I acknowledge your requ- t. Do you have any best estimate of when this could b- eeded? Will there be any modificatio .f the pilot settings on the "new producers "? Sundries will not be necessary. -ving to ability to test is appropriate for all• ation purposes. I have copied this to my colleagues • they may make necessary assess ents. I do not have the authority for this appr. -I, but based on responses t• others, the AOGCC will work with you to make the appropriate decisions. Tom Maunder, PE AOGCC From: NSK Prod Engr & Optimization Supv [mailto• , 046 @c• • •cophillips.com] Sent: Monday, January 10, 2011 4:29 PM To: Maunder, Thomas E (DOA) Cc: NSK Prod Engr Specialist; CPF2 Prod . grs; CPF3 Prod Engrs; NSK i 'wide Operations Supt; CPF1&2 Ops Supt; CPF3 Ops & DOT Pipelines Supt .radley, Stephen D Subject: Request for Approval Importance: High Tom, GKA is requesting AO C approval to initiate WAG injector flowbacks at Kuparuk if needed to *.- intain an adequate fuel gas •- our turbo - machinery due to the current TAPS proration. Doing so should help -nsure that we maintain life - pport and safety systems at each facility. At this tim -, it is unclear if this will become necessary as the repair status at Pump Station #1 is still evolving. As part of •'r 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 1/11/2011 • • Page 1 of 3 II 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 PTD# Adjacent PTD# Estimated Prod ;as Injector SI Producer (Mscfd) DP-420 201 -182 2P -422A 202 -067 4,500 aP -447 203 -154 2P -448A 202 -005 2,000 a,U -03 185 -006 2U -02 185 -005 3,500 3S -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 ~e~l ~I' ~i ~ ~ P.I. Supervisor l 1 I FROM: Bob Noble Petroleum Inspector i State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, August 10, 2010 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 3S-26 KIJPARUK RIV [INIT 35-26 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv ~~~' Comm Well Name: KUPARUK RIV UNIT 3S-26 API Well Number: 50-103-20361-01-00 Insp Num: mitRCN100809162648 Permit Number: 201-040-0 Rel Insp Num: Inspector Name: Bob Noble Inspection Date: g/~/2010 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well T 3s-z6 - Type Inj. G' TVD 5749 ' IA 1820 2520 ' 2380 2370 ' P.T.D~ zoloaoo - TypeTest SPT Test psi zszo -- pA z9o Sao Sao Sao Interval4YRTST per, P ~ Tubing 3100 3100 3100 3100 Notes: ~A j ~,~ ` re ~ +~ ~~,~ 1SCc~~; ~;, °. _ _ Tuesday, August 10, 2010 Page 1 of 1 35-26 (PTD 201-040) Report of p~ ~ng MITIA ,~. Yage 1 of "L Regg, James B (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com] Sent: Wednesday, September 03, 2008 12:36 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: NSK Problem Well S~pv; NSK Well Integrity Proj; Fleckenstein, Robert J (DOA) Subject: 3S-26 (PTD 201-040) Report of passing MITIA Attachments: MIT KRU 3S-26 08-20-08.x1s; 3S-26.pdf; 3S-26 90 day TIO.gif ~- Jim, The wellwork has been completed on this well. After exercising the CMU, slickline was able to get a passing MITIA. Attached is the data from the passing M~ ITIA that was performed by DHD following the slickline work. It is ConocoPhillips intention to return the well to water injection once the CPF3 turnaround is complete and injection is restored. Once the well is online and stablized, the AOGCC inspectors will be notified and a L. witnessed MITIA will be performed in no more than 30 days of injection commencing. Please let us know if this plan is unacceptable or if you have any questions. «MIT KRU 3S-26 08-20-08.x1s» /J Brent Rogers/Martin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7224 Pager (907) 659-7000 pgr. 909 ,~ D ~ ~, 2. ~ 2D09 Prom: NSK Well Integrity Proj Sent: Tuesday, August 19, 2008 6:26 PM ~ ~ ~ ' ' "°'"` To: 'Regg, James B (DOA)' Cc: NSK Problem Well Supv; 'Maunder, Thomas E (DOA)' Subject: RE: 35-26 (PTD 201-040) Notice of TxIA Communication Jim, Kuparuk WAG injector 3S-26 (PTD 201-040) has indications of T X IA communication. This well failed an MITIA on 9116/06, and was reported to the AOGCC 9/17/06. Previous diagnostics determined that there was a very small leak between the IA and the tubing string, however, the exact leak point was not identified. On 10/17/06 documentation of diagnostics, 30 day TIO, and the MIT's performed were submitted to AOGCC and CPAI requested to remove the well from the failed MITA report. Testing indicated that the IA is liquid tight at 1700 psi but has a slow leak at 3000 psi. Recent studies indicate possible benefits of MI injection in 3S-26. As a result, an attempt was made to identify the leak source in order to evaluate possible repair options utilizing an ultrasonic leak detection tool. Interpretation of the log shows the leak point to be the Baker CMU at 8819' MD. The sensor picked up a leak signature with 3000 psi on the IA but was undetectable with 1500 psi on the IA. 12/10/2009 35-26 (PTD 201-040) Report of p~ ~ng MITIA Yage 2 oft `~~ The well is currently shut in as are all CPF3 water injection wells during the planned plant maintenance. Our proposed plan forward is to exercise the CMU then perform diagnostic MITIA's. If exercising the CMU fails to cure the problem we plan on setting an isolation sleeve across the CMU and then retesting the IA. CPAI would like permission to bring the well online in water only injection service once the plant is brought back on line. Target date for restart is 9-5-08. I propose a test period not to exceed 30 days of injection. Our plan is to obtain a passing MITIA prior to the test period on injection and again once the well is online and thermally stable. Please respond with guidance and any questions. A well schematic and 90 day TIO plot are attached. Sincerely Perry Klein Well Integrity Project Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7043 Cell Phone (907) 943-1244 «3S-26.pdf» «3S-26 90 day TIO.gif» 12/10/2009 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg@alaska.gov; tom.maunder@alaska.gov;bob.fleckenstein@alaska.gov;doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. Kuparuk /KRU / 3S-26 08/20/08 ~ Colee !Bates /Ives - AES Packer Depth Pretest Initial 15 Min. 30 Min. Well 3S-26 ' Type Inj. N TVD 5,749' Tubing 1,010 1,010 1,010 1,010 Interval O P.T.D. 2010400 Type test P Test psi X1500 Casing 1,490 =x,000 2,940 X2,930 P/F P Notes: Non witnessed diagnostic MITIA OA 200 290 290 290 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPEINJ Codes D =Drilling Waste G=Gas I =Industrial Wastewater N =Not Injecting W =Water 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 T =Test during Workover O =Other (describe in notes) MIT Report Form BFL 11127!07 MIT KRU 3S-26 08-20-08.x1s • 11: TRh,_AP,F,L - ';SURE TRENDS soo. 3000. SC WELL NAMI! WLKRU3S -26 3000 - 200. 3000. 3000. 2700 3000. 2400 3000. 210n lean - -- - � - - I _ - -- - -- -- -- ------ -- i 1500 - 1200 _____ m ks -� _ i - - -- - i 5 0. 600 H- HRMAUM 3011 n - - -- - - - --- - -- - - -- - ---- -_- _ -- -_ -- - - - --- - - -- ---------------------------------------------------------------------- -- ------- --- ------ ------ -- -- -- - ----------------------------- 0 ' PLOT START TIME MINOR TIME PLOT DURATION PLOT END TIME 21- MAY -08 18:28 MA' WEEK +02160:00.00 - HR" 19 AUG -08 18: PICK TIME 13- AUG -08 07:29:16 F F 7 F F F F 7 SC TAG NAME DESCRIPTION P -VALUE LA1E:,i ROV- 3S- 26C -REQ FLOW TUBING CHOKE ? ?? ?? ?? DRILLSITE WELL PREV WELL SCRATCH 9 FLOW TUBING PRESSURE ? ? ? ?7 ?? 3S 26 SCRATCH FLOW TUBING TEMP ? ? ? ? ? ?? NEXT WELL WL- 3S- 26 -IAP GL CASING PRESSURE ?72?7 ?7 27777 ?7 ENT RY TYPE OPERATOR ? ? ? ? ? ?? OPERATOR VERIFIED 11w SCRATCH_9 INNER "LULUS PRES ? ?77 ? ?? SYSTEM AUTO ENTRY pw SCRATCH OUTER ANNULUS PRES ? ?7 ?277 BOTH ConocoPhlillips Alaska, Inc. KRU 3S -26 35 -26 API: 501032036101 Well Type: INJ Angle a TS: 68 de 9044 TUBING SSSV Type: NIPPLE Oriq Completion: 3/14/2001 Angle a TD: 68 de 9400 (0 -8999, Annular Fluid: Last W /O: Rev Reason: TAG FILL OD.3 500, Reference Log: Ref Log Date: Last Update: 12/15/2006 ID:2.992) Last Ta : 9082' RKB TD: 9400 ftK13 Last Tag Date: 12/14/2006 1 Max Hole Angle: 68 deg Q 8935 Casing String - ALL STRINGS Descri tion Size To Bottom TVD Wt Grade Thread CONDUCTOR 16.000 0 115 115 65.50 WELD SURFACE 9.625 0 2616 2615 36.00 J -55 BTCM PRODUCTION 1 7.000 0 9389 5941 26.00 J -55 I BTCM Tubing String - TUBING Size i Top t I Grade Thread 3.500 0 8999 5793 9.30 L -80 8rdMOD 2.875 1 8999 900 1 5796 1 0.00 1 1 EUE8rd Perforations Summa Interval TVD Zone Status Ft SPF Date Type Comment 9047-9137 5811 -5845 C -4 90 1 4 5/8" Scallop TCP guns Gas Lift MandrelsNalves St MD TVD Man Mfr Man Type V Mfr V Type VOID Latch Port TRO Date Run Vlv Cmnt 1 2514 2513 CAMCO KBMM -2 DMY 1.0 BK 0.000 0 3/31/2001 I 2 3995 3784 CAMCO KBMM -2 DMY 1.0 BK5 0.000 0 3/13/2001 3 6194 4675 CAMCO KBMM -2 DMY 1.0 BK5 0.000 0 3/13/2001 4 7764 5307 CAMCO KBMM -2 DMY 1.0 BK5 0.000 0 3/13/2001 5 8777 5710 CAMCO KBMM-2 DMY 1.0 BK5 0.000 0 3/13/2001 Production MandrelsNalves St MD TVD Man Mfr Man Type V Mfr V Type VOID Latch Port TRO Date Run Vlv Cmnt 6 8934 5769 CAMCO KBUG I DMY 1.0 BK5 0.000 1 0 3/13/2001 7 8961 57791 CAMCO I KBUG I DMY 1.0 BK5 0.000 0 1 3/13/2001 Other (plugs, equip., etc. - JEWELRY Depth TVD Type Description ID 506 506 NIP CAMCO'DS' NIPPLE 2.875 NO GO 2.875 8819 5726 SLEEVE -C BAKER CMU SLIDING SLEEVE W/2.813 'DS' PROFILE closed 11/9/2002 2.812 8859 5741 SEAL BAKER SEAL ASSEMBLY 2.992 8860 5741 PBR BAKER POLISHED BORE RECEPTACLE W/12' SEAL TRAVEL 3.000 8881 5749 PKR BAKER SAB -3 PACKER PINNED FOR 1500 PSI SHEAR 3.250 8987 5789 NIP HOWCO'XN' NIPPLE W/2.75" NO GO 2.813" BORE 2.750 8999 5793 XO XO 3.5" TO 2 7/8" 2.440 9000 5794 PERF SUB HOWCO PORTED SUB BALANCED ISO TOOL 2.440 PBR Other (plugs, equip., etc. - FISH (8860 -8861, Depth I TVD Type Descri tion ID OD:5.875) 9198 5868 FISH HOWCO 4 5/8" Scallop Gun, 5 spf w/27' of stim sleeves; tubing auto release & space 0.000 3'x15' RELEASED & DROPPED 4/1/01 WHEN FIRED General Notes Date I Note 4111/2002 1 DRILLED AS PALM 1A EXPLORATORY WELL i c I I PERF SUB (9000 -9001, OD:4.500) I Pert (9047 -9137) PRODUCTION (0 -9389, OD:7.000, Wt26.00) MEMORANDUM TO: Jim Regg `~ P.I. Supervisor ~ ~ ~ (~ ~ FROM: Chuck Scheve Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, November O5, 2008 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 35-26 KUPARLTK RIV iJNIT 3S-26 Src: Inspector NON-CONFIDENTIAL Reviewed By: r- P.I. Supr 2,. Comm Well Name• xuPARUx Rrv UNIT 3s-26 API Well Number: s0-1 03-203 6 1-0 1-00 • Inspector Name: ct,UCk scheve mitCS08 1 102 141 929 Permit Number: 201-040-0 "'l Insp Num: Inspection Date: 11/1/2008 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well i 3s-z6 Type Inj. ~ `~' TVD ~ s~a9 ~ IA 1160 ~ - zlo~ 19so 19ao -- - --- p T zoloaoo TypeTest ~ sPT Test psi I lsoo ,~( pA s~o 6zo 6zo 6zo -- - Interval WRKOVR P/F~ P ~ Tubing 14s0 14s0 ]4s0 14s0 Notes: !'.~~' Wednesday, November O5, 2008 Page I of 1 ~ftl \ I,.' 'Ì /.. ! // c----' 03/05/07 Schlullberger NO. 4173 Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 A TTN: Beth iGANNEV MAR 3 G Z007 Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite '100 Anchorage, AK 99501 t1f\1'( ;Þ t. 70tH UIC- çÇúl-C/16 Field: Kuparuk Well Job# Log Description Date Color CD BL 2G-03 11638824 INJECTION PROFILE 02/15/07 1 1 R-08 11628971 INJECTION PROFILE 02/15/07 1 1 F-17 11638827 SBHP SURVEY 02/17/07 1 1F-14 11638826 SBHP SURVEY 02/17/07 1 1 F-19 11638828 SBHP SURVEY 02/19/07 1 1C-13 11628977 SBHP SURVEY 02/19/07 1 1 C-02 11628978 SBHP SURVEY 02/19/07 1 2M-02 11628979 INJECTION PROFILE 02/20/07 1 35-26 11638813 INJECTION PROFILE 01/21/07 1 1 C-121 11665391 INJECTION PROFILE 02/05/07 1 1J-180 11665390 USIT 02/06/07 1 3J-14 11638825 PROD PROFILE 02/16/07 1 1J-118 11665392 U51T 02/22/07 1 1 D-11 11665393 INJECTION PROFILE 02/24/07 1 2M·05 11665400 INJECTION PROFILE 03/01/07 1 2M-04 11665399 INJECTION PROFILE 03/01/07 1 1F-13 11665401 INJECTION PROFILE 03/02/07 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. , ^15) . . Schlumberger 12/19/06 ft. ,/'<_.~. .... NO. 4077 Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth 2 1 ZOOG Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 c~ ~ UICl ()Of -O¿/ó Field: Kuparuk Well Job# Color CD Log Description Date BL 1 R-03A (REDO) 11483497 INJECTION PROFILE 11/30/06 1 1 B-09 11483500 INJECTION PROFILE 12/03/06 1 3S-26 11538769 INJECTION PROFILE 12/10/06 1 1F-04 11538770 INJECTION PROFILE 12/11/06 1 3S-08B 11538771 PRODUCTION PROFILE 12/12/06 1 3H-10B 11534187 PRODUCTION PROFILE 12108/06 1 1 J-136 11534188 US IT 12/10/06 1 2M-12 11534189 PRODUCTION PROFILE 12/11/06 1 1F-10 11534192 INJECTION PROFILE 12/12/06 1 1Y-27 N/A PRODUCTION PROFILE 12/14/06 1 2Z-20 N/A SBHP SURVEY 12/15/06 1 1 H-21 11551832 SBHP SURVEY 12/16/06 1 1 F-05 N/A INJECTION PROFILE 12/13/06 1 1 F-09 11548550 PRODUCTION PROFILE 12/14/06 1 3S-03 11551831 PRODUCTION PROFILE 12/15/06 1 3J-18 11548550 PRODUCTION PROFILE 12/16/06 1 1 H-14 11551835 SBHP SURVEY 12/18/06 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. . . RE: 3S-26 (PTD 2010400) Report of mar ginl ailed MITIA . Jim Thank you for permission to keep 3S-26 online. I plan to have diagnostics finished in the next week to week and a half. Pending the results of the diagnostics we will have a plan forward and timing at that time. I'll be sure to keep you informed. Perry Klein Problem Wells Supervisor ConocoPhillips Alaska Inc. Office 907-659-7224 Cell 907-943-1244 t;,;.'iP'lAMlt.U:::f\ ~ ¡:;- 1) ~.,>." f,.~\ ?n Of, iJ\t'f,n'~4ìioô-fr v U . '" ~ -----Original Message----- From: James Regg [mailto:jim regg@admin.state.ak.us] Sent: Monday, September 18, 2006 1:39 PM To: NSK Problem Well Supv Cc: Thomas Maunder; bob fleckenstein@admin.state.ak.us Subj ect: Re: 3S-26 (PTD2-6i64(Ù5-Y-R:eportofmargInaflyfailed MITIA You have permission to keep the well on line for additional troubleshooting. Please provide your timeline to complete diagnostics and repairs, or if no repairs are planned, when you will request adminstrative approval under AIO 2B to continue injecting. Diagnostic results should be provided once completed. Jim Regg AOGCC NSK Problem Well Supv wrote: Tom, Jim, & Bob, Attached are results of a diagnostic MITIA for 3S-26 completed on 9/16/06. The test barely fails with very slow leak off. Additional diagnostics will be completed to try to identify the location of the leak starting with the packoffs. The well has been added to the Failed MITIA report. permission to leave the well on line for additional troubleshooting is requested. Attached is a 90 day TIO plot and a schematic. Please let us know if there are any questions. I am leaving today for a conference, our office will be vacant until Wed 9/20 when Perry Klein returns. Marie McConnell Problem Well Supervisor 659-7224 «MIT KRU 3S-26 09-16-06.xls» «3S-26 90 day TIO plot 9-16-06.gif» «3S-26.pdf» 1.pf1 f8 Z- lA{1(t~ 9/25/2006 II :09 AM Re: 3S-26 (PTD 2010400) Report of mar ginaii led MITIA . You have permission to keep the well on line for additional troubleshooting. Please provide your timeline to complete diagnostics and repairs, or if no repairs are planned, when you will request adminstrative approval under AIO 2B to continue injecting. Diagnostic results should be provided once completed. Jim Regg AOGCC !~CANNED Sf P ~~ .. NSK Problem Well Supv wrote: Tom, Jim, & Bob, Attached are results of a diagnostic MITIA for 3S-26 completed on 9/16/06. The test barely fails with very slow leak off. Additional diagnostics will be completed to try to identify the location of the leak starting with the packoffs. The well has been added to the Failed MITIA report. Permission to leave the well on line for additional troubleshooting is requested. Attached is a 90 day TIO plot and a schematic. Please let us know if there are any questions. I am leaving today for a conference, our office will be vacant until Wed 9/20 when Perry Klein returns. Marie McConnell Problem Well Supervisor 659-7224 «MIT KRU 3S-26 09-16-06.xls» «3S-26 90 day TIO plot 9-16-06.gif» «3S-26.pdf» 1 of 1 9/18/2006 1 :46 PM MEMORANDUM . State of Alaska _ Alaska Oil and Gas Conservation CommisW TO: ~~S~pe;~isorR'e"c: C¡)3D/Ole . '71 ' DATE: Wednesday, August 30, 2006 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 3S-26 KUPARUK RIV UNIT 3S-26 Q.Þ\-oq-O FROM: Jeff Jones Petroleum Inspector Src: Inspector Reviewed By: P.I. Suprv ."yp;¡?- Comm NON-CONFIDENTIAL Well Name: KUPARUK RIV UNIT 3S-26 API Well Number 50-103-20361-01-00 Inspector Name: Jeff Jones Insp Num: mitlJ060829120809 Permit Number: 201-040-0 Inspection Date: 8/22/2006 Rei Insp Num Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 3S-26 Type Inj. w TVD 5749 IA 2750 1500 1510 1520 1520 P.T. 2010400 TypeTest ßAM1 Test psi 1500 OA 590 490 490 490 490 Interval 4YRTST PIF P Tubing 2350 2350 2350 2350 2350 Notes IA pressure bled from 2750 to 1500 psi and monitored for 45 minutes. IA pressure stabilized at 1520 psi passing the MIT. .t- r' -h/ t~ -k- ~+ ( lJutj.j o ('oc¿Z}i 2-[45-0 ) XItl- SCANNED SEP 0 8 200B Wednesday, August 30,2006 Page 1 of 1 MEMORANDUM . State of Alaska _ Alaska Oil and Gas Conservation CommissP TO: Jim Regg P.I. Supervisor -¡:2eo1 t£./3¿/ ÍJ.¡;; ( , DATE: Wednesday, August 30, 2006 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 3S-26 KUPARUK RIV UNIT 3S-26 ~b \ .r()~D FROM: Jeff Jones Petroleum Inspector Src: Inspector Reviewed By: --2;:;> P.I. Suprv _. j-,.fi- Comm Well Name: KUPARUK RIV UNIT 3S-26 API Well Number 50-103-20361-01-00 Inspector Name: Jeff Jones Insp Num: mitlJ060829121450 Permit Number: 201-040-0 Inspection Date: 8/22/2006 Rei Insp Num Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 3S-26 Type Inj. W TVD 5749 IA 1325 3000 2800 2750 2700 P.T. 2010400 TypeTest SPT Test psi 1500 OA 520 610 600 600 590 Interval 4YRTST PIF F ./ Tubing 2370 2350 2350 2350 2350 Notes Suspect fluid temperature differential responsible for failure ofIA pressure to stablize in 45 minutes; this well passed a subsequent 45 minute annulus monitoring MIT. 2.4 BBLS diesel pumped. 1 well house inspected; no exceptions noted. /" .L(,~ìvl;.. -L(;~ .-\e.s;'; - (LU~::U chaß ZCjiUfOC¡') Del sse£.( . ' ¡ . / NON-CONFIDENTIAL SCANNED SEP {) S 200H Wednesday, August 30, 2006 Page 1 of 1 . '~ ConocOPhillips Alaska . P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 7, 2006 '~ ._~ Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK. 99501 J.ol- O'/-o 3~-~ ~Jd Dear Mr. Maunder: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRD). 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 of2.5 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 ~f~ 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 PTO # 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 Ñ '.{' 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 8/5/2006 e e 'C~, <'.,~ MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F: \LascrFiche\CvrPgs _ Inserts\Microfi 1m _ Marker. doc Permit to Drill 2010400 DATA SUBMITTAL COMPLIANCE REPORT 4/18/2003 Well Name/No. KUPARUK RIV UNIT 3S-26 Operator CONOCOPHILLIPS ALASKA INC MD 9400 <- .... -I-VD 5945 ~ Completion Dat 4/23/2001 Completion Statu 1-OIL Current Status WAGIN UIC Y APl No. 50-103-20361-01-00 REQUIRED INFORMATION Mud Log N._g.o Sample No Directional Survey DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Data Digital Type Media Digital Fmt L Pro Production Name (data taken from Logs Portion of Master Well Data Maint) Log Log Run Scale Media No Interval Start Stop OH / Dataset CH Received Number Comments ¢~::~Po~rm ation Log 2 FINAL Well Report FINAL ~-"D~R/NEU/DEN 2/5 FINAL ROP/DGPJRES 2/5 FINAL -MI~GPJBAT 2/5 FINAL ~:~-~U/DE N 2/5 FINAL /.,,M~ ROP/GR/RES' 2/5 FINAL ~relation log 5 FINAL ~3008 FINAL ~ FINAL CMR Total Porosity 2 FINAL ~,lSl'~- 5 FINAL ~roduction Profile 5 ~'~/~ ~ I FINAL ~ 5 FINAL ~D CMR 5 FINAL · ---3~ PJBAT 2/5 FINAL 1 Blu final 2800 2700 2700 2700 2700 2700 8630 2700 7392 2700 7392 7780 3300 9025 740O 74OO 2700 8970 9318 9318 9318 9318 9318 9318 8975 9318 9180 9318 9180 9180 9314 9180 9180 9180 9318 9186 ch 5/25/2001 ch 5/25/2001 oh 4/11/2001 oh 4/11/2001 oh 4/11/2001 oh 4/11/2001 oh 4/11/2001 oh 4/11/2001 oh 4/11/2001 oh 4/1112001 Open 4/11/2001 Open 4/11/2001 oh 4/11/2001 oh 4/11/2001 oh 4/11/2001 oh 4/11/2001 oh 4111/2001 oh 4/11/2001 Case 2/1412003 /...-1.0008 2800-9318 Sepia Final Well Report 2700-9318 BL. Sepia 2700-9318 2700-9318 2700-9318 2700-9318 8630-8975 2700-9318 7392-9180 2700-9318 7392-9180 7780-9180 3300-9314 9025-9180 7400-9180 7400-9180 2700-9318 BL, Sepia BL, Sepia BL, Sepia BL, Sepia BL, Sepia Digital Data Digital Data Color Print Color Print BL, Sepia BL, Sepia BL, Sepia BL, Sepia Well Cores/Samples Information: Name Interval Start Stop Sent Received Dataset Number Comments Permit to Drill 2010400 DATA SUBMITTAL COMPLIANCE REPORT 4/1812003 Well Name/No. KUPARUK RIV UNIT 3S-26 Operator CONOCOPHILLIPS ALASKA INC APl No. 50-103-20361-01-00 MD 9400 'I-VD 5945 Completion Dat 4/23/2001 Completion Statu 1-OIL Current Status WAGIN UIC Y I ~._..C-~ g s 2760 9400 ADDITIONAL INFORMATION Well Cored? Y/(~) Chips Received? ~ Analysis ~ Received';) Daily History Received? ~ N Formation Tops (~ N Comments: Compliance Reviewed By: Date: i ConocoPhillips Alaska, Inc. KRU 3S-26 TUBING 35-26 (0-8999. APl: 501032036101 Well Type: PROD Angle @ TS: 68 deg @ 9044 0D:3.500, il II SSSV Type: NIPPLE Completion: Odg Angle @ TD: 68 deg @ 9400 ID:2.992) Annular Fluid: Last W/O: Rev Reason: Ta9 fill Reference Log: Ref Log Date: Last Update: 2/912003 Last Tag:l 9156 TD: 9400 ftKB ]~i I CasingLast Tag Date:! 2/8/2003String - ALL STRINGS Max Hole Angle: 68 dog (~ 8935 Description Size Top Bottom TVD Wt Grade Thread CONDUCTOR 16.000 0 115 115 65.50 WELD , , SURFACE 9.625 0 2616 2615 36.00 J-55 BTCM J PRODUCTION 7.000 0 9389 5941 26.00 J-55 BTCM Tubing Strin~ - TUBING Size I Top Bottom I TVD Wt I GradeI Thread / ' 2.875 8999 9005 5796 0.00 EUESrd PerfOratiOns Summary { 9047 - 9137 5811 - 5845 C-4 90 4/1/2001 PERF 5/8" Scallop TCP guns ] I Gas Lift Mandrels/Valves St MD TVD Man Man VMfr VType VOD Latch Port TRO Date Vlv Mfr Type Run Cmnt I 2514 2513 CAMCO KaUU-2 DMY 1.0 BE 0.000 0 3/31/2001 ]~! 2 3995 3784 CAMCO KBMM-2 DMY 1.0 BK5 0.000 0 3/13/2001 I 3 6194 4675 CAMCO! KBMM-2 DMY 1.0 BK5 0.000 0 3/13/2001 4 7764 5307 CAMCO: KBMM-2 DMY 1.0 BK5 0.000 0 3/13/2001 5 8777 5710 CAMCO KBMM-2 DMY 1.0 BK5 0.000 0 3/13/2001 ProdUction Mandrels/Valves· " ~~ St MD TVD Man Man VMfr VType VOD Latch Port TRO Date Vlv Mfr Type Run Cmnt 6 8934 5769 CAMCO KBUG DMY 1.0 BK5 0.000 0 3/13:2001 7 8961 5779 CAMCO; KBUG DMY 1.0 BK5 0.000 0 3/13;2001 Other )lugs, equip., etc. - JEWELRY Depth TVD Type Description ID 506 506 NIP CAMCO 'DS' NIPPLE 2.875 NO GO 2.875 8819 5726 SLEEVE-C BAKER CMU SLIDING SLEEVE W/2.813'DS' PROFILE, closed 11/9/2002 2.812 8859 5741 SEAL BAKER SEAL ASSEMBLY 2.992 8860 5741 PBR BAKER POLISHED BORE RECEPTACLE W/12' SEAL TRAVEL 3.000 8881 5749 PKR BAKER SAB-3 PACKER PINNED FOR 1500 PSI SHEAR 3.250 8987 5789 NIP HOWCO'XN' NIPPLE W/2.75" NO GO, 2.813" BORE 2.750 8999 5793 XO XO 3.5" TO 2 7/8" 2.440 9000 5794 PERF SUB HOWCO PORTED SUB (BALANCED ISOTOOL) 2.440 Other ( 3lugs, equip., etc2 - FISH ] :i" 'i I Depth TVDI Type Description ID 9198 5868 FISH HOWCO 4 5/8" Scallop Gun, 5 spf w127' of stim sleeves; tubing auto 0.000 release & space 3'x15' (RELEASED & DROPPED 4/1/01 WHEN FIRED) General· Notes...'.' ' .' ... '. : : .. ...... Date Note ]~!7- I 4,1112002 DR LLED AS PALM lA, EXPLORATORY WELL II I PERF SUB L -= J RECE V.ED Perf -- -- MAR 1 4. 2005 (9047-9137) .. Casing Detail 7" 26# Production Casing WELL: Palm ARCO Alaska, Inc. DATE: 03107101 Subsidiary of ^flantic Richfield Company 1 OF I PAGES # ITEMs coMPLETE DESCRIPTION OF EQUIPMENT' RUN LENG;I"H' DEPTH Nabors 19E RKB to LDS = 29.60 TOPS .... Nabors 1SE Rotary Table to LDS = 31.00 =7" Landing Joint (above table 5.80) ..... ~.~) -5.80 7', L~'~aing (bel°w table 31.00) ' . .', ........... 3;1'.00 ..... .. . 7, FMC GEN V, fluted mandrel hang.er witl~ ~", 26~, .L-SO i~'.u,p, 2.54.. 31..00 · its 16'230 7", 26#, J-55, BTC-MOD (2t5 its) 8743.77 33.54 Marker A ' 7'", :~6~, L-80, BTC-MOD Ma'rker, top jt. ~ 19.63 Bottom jr. = 19.52 39.15 " 8777.31 jts, 3-15 7", 26#, J-55,"BTC-MOD (1'3 its) ' " 526.37 ' 8816.46 .............. Davis Lynch Double Valve Float Collar 2.02 9342.83 its.1 7", 26#, J-~,..'.BTc-I~'~)D (1 jt.) '.". ......... 4.;i....85.... 9344.85 Davis LYnch Double Valve Float Shoe 2.38 9386.70 .......... BTM' OF SHOE @ ' S38~.0S . _. TD at 9400' 204' of cased rat hole ~RA Marker ~ 8736, Marker Joint Collam ~8777.3J and 8796.94 ........... Joint #2 and Joints' 231.242 will' not be run on t~is well -' ........ ,, , Total Solid Centralizers=16-----Total Bow Spring Cents.=63 7x8 ~8x8 "Gemeco Solid Spiral Centralizers Floating on Joints' ' 'Joints #4 through #14 (11 total) ,, , ..... Gemeco Bow Spring Centralize~'s Run over'stop"F~ings .... .......... JOint #1 10' above shoe and 10' below coli'~ar (2 total) ....... .......... Joint #3' in center Of joint (1 total) ....... ,, , ,, ....... , · , ,,, , ,,, ....... Gemeco Bow'Sprin~ Centralizel;~ Run over Casing c01i~rs On Ev~"ry'3rd joint .... Joints #15'718,21,24,27,30133,36 (8 total) ......... ..... 'On'~Very'.~0int.~, JOints #~7,38,39,4o,41,42,43,44,..4.5,46,47,48,49,. . . . .. .....: ...... .', ~ _. 50 and 51 (15 total) , ' ' Or~' Every 3rd Joint--- Joints #541' ~, 6'~',"63, 66, 6'9, 72, 75', 78, 81, 84 ' ' ' ....................... 87,90,93,96,99,102 (17 total) "On EverY3rd Joint~-- Joints #~05,108,11~,1~4,117,120,123,126,'129,13: ......... " 135',~38, i41,144 and 147 (15 total) ........ .... On Every 3rd'j0ini'---joint~150,153,156,159 and 1'62 (5total) 7x8 3/8x12 Gemeco Solid Straigt Blade centering Guides' F!oating on joints 0'n every 2nd'Joint .... Joints #165,167,169,171 and 173 (5 total) :Rema'rks: S't#ng Weights With Blocks: 1'70k Up, 85~'b~, 25k Blocks. Ran 230joints"ofCasing. Drifted ...... ,casing with 6.151 "plastic rabbit. Used Arctic Grade APl Modified No Lead thread compound on all connections. Casing is non-coated. I~l~bors '19E .... D'~iiing $'u"perVi'sor: R. Morri'son ....... C...JING / TUBING / LINER DETAIL 7" 26# Production Casin_~ ARCO Alaska, Inc. Subsidiary of Atlantic Richfield Company WELL: Palm #1A DATE: 03/07/01 2 OF 2 PAGES "# iTEMS coMPLE'I:'E DESCRIPTION ~F EQUIPMENT'R'uN "' LENGTH DEPTH. TOPS , , ,, , ,, , .... , ...... · __ .. ...... , , , , . . ............... , ,, .............. ,. ,,, ,,,,, · ,, ,,, ,,, , ,,,, , ,, , , _ __ RemO'rk/~:, str'ing'"W, eights with. Bl'o,cks: ~OOk,Up.., 1.5.0k D;; '70,,k, 'BI,o,;i',k;i'"'R,an 262 jOints or,casing, 'i,'-- Driffod casin0..w, ith 6.1S 1,,',', pl,astic rabbit.:, Used Arct.,ic,Gro,,,q?AH Mocllfi0d No Lead , , ,, throod q,0mPound 0n,,olj, conn0cfloas, c0si,,ng is non-cootocl,, ................. Phillips Alaska Drilling Cementing Details " Well ,ame:~'~l~l~ll41~" ~[~,.~/Vt ~ [:~ . Report Date: 03/00/2001 Report Numba~, I RI~ Name: Nabom 19E AFC No.: AX2145 Field: Wildcat Casing Size Hole Diameter, Angle thru KRU: Shoe Depth: LC Depth: % washout: 7" 8,S" 68 9369 9342 !'.',O~..mmsDts=, ,.. '. : · '-', ':"';:~' .... ~ .' ' · " Soecaslngdetsllfordetallsoncentrallzers. Ran 63 bow sprlngs, ll $olldsplralTx83/SxS, SsolldstrelghtTxS..~r8 ...,.~:...::::-:;:.?.:~. '.,i :' '[ ':' ~: ..:- ,42 ~ ,,. ,;~,., ! ... ,,~, ,.~, .'. , .,1'.'.. ,, ~' -'"-' J"'~'", '-" , - ,k · I ~',;B',~'d~-t..~ .- ::: -.. .:.... .... ~l"-'OLttl-t11. el~l~I'' ''''~_,~.-,?~,;.¥:.[::,,.,.,: ,,.,.,] :..[: .. ;:.,..?.,.,..,..; - We,ght: PV(pr,or cond): PV(alter cond)'J YP(prior condO: YP(afle, cond) i~'~t]~;;-' ,.':..,..' : ..; ',." ', '-;;' "., 12.7142.2 22 ';'.' ';.';~,~:,~J~.~';¥','..'?" '. ".'.~: Gels before: Gels alter: Total Volume Circulaled: ~E'::'~:~,;; T: '.;" '.' ;':": ', , 6/9 942 ¥,.'.,,, h. ~ :. ,.. ?,', ~',.;... . . .. · ;~, ~.-.,; ..... , -'..,-' , ,...; , ,. -... ~. ,',,,~:' ~.,,:,..., ,.'.; ..,...,,, , , .~., .... ,,~ , =;:..',%. .,. ,, ,. '; ~-,i~;~%. :,~,.=,.... , ,. T~o: Vo,,,me: Wei0h,. ~,': ~m~e,~;.:=, ;;~ ...... .: .... ' cw 400 40 bble 8.3 ppg ~.;',;.;,; ..~'.;:,~.1.;,~.'.[,..', ,:,.. / ":": . · .!;"~{~!i: =-:,%~'.'-~" '.... '.": ~,,.~.,~;,;..j'.,':.., r., .' . , ,., Type: Volume: Weight: '.~!~!pnts:~.. ~.. .. , MUDPUSHXL 40bbls 12.5 :""~' '~:;:',~i'.:'": ~''''''' "'" ' · ' ."~:~;~,-.>U . .;v~.t~'~ ~¢';., .... '. :' "... :!~.~:~'~i~j ", T~: u~,,~,emp: No. of S~,~k~: wo;.~: "'l.~.'~?,i?'~:. :' ,' .":; 0 80 202 13.0 ppg 1.99 '";;'"".'~' ~ i,' "~':' ," ' Additives: ",i: ;'.,',,,.ii" ' .' , , , · 8.0%D020, 0.6~,~D800, 0.60%DI67,0.20%D046, 0.30%D065 I 1 ...:~i,~i,~;':. '.' .' : ~o a,~ ~.~ :... ,. ,:..~: .., · G 1.2 · i'.':i ' Addilh'o~: .i.,., ... ,., .,.,:' ~ ... 2.. 3.0%~033, 0.60%D0~$, 0.t20%DII00, ~.0 gal/ok D600, 0.t~0 §al/sk Dt~{;, 0.~0 §al/sk D047 · '~J~.~'~l;ii.' 'b.' '.' ' R,'.~e,,t:.ck~,., t;~il at .'.~hco,: [late(tail arm, nj ::hc.¢.,i. S:r. WI. Up: ',,,:=~;~.~'~'?:;i;:,'i' :,,'.,' . :' , .. 4.~ BPM 4.~ ~PM 170 · ' ':J , ': '"'.."" "~: ': ' ,'"" Reciprocaliol~ lenglh: Itecip~ocaliorl speed: Str. WI. [')own: ,.~. i. =:.. '...,~ ,.:,.... . ,. . :"~" ":~':' .",'[ "~, !' "' ;." ' ~. ~'" ',. pipe $1uck 0 · ; ,.:,; :.[:~:./:~....: , · ..:.... 85 "" ..... ' ""[~ ' ' ' '; ' "; ' 'l'hoototJcal Disl;Jacornont: Aol,J;lJ Dis[~lac~.'lllJ~r,h Sit. Wt. in mu(l: , 357.16 357.4 ..~ Calculated top of cement: , CP: Bumped plug: Floats held: 4100' Date:03/09/01 no no Time:Il:31 am .... Remarks:Ran casing to bottom at 9389' and landed on hanger. Made up Dowell cementing head. Attempted to pull off hanger, pipe was stuck. Broke circulation and circulated 942 barrels of mud. Mud weights 12.5 to 12.7 and viscosities 80 to 102 were measured coming out of the hole. The mud wes conditioned to 12.2 wi, and 52 vis~ In and out of the hole. Dowell botch mixed the tall cement. Dowell pressure tested lines to psi. Dowell mixed and pumped 100 barrels of lead at 13.0 ppg followed by' 85 barrels of tall at 15.8 ppg. Flushed lines prior to dlplaclng with 357.4 barrels of 12,2 ppg mud. The cement was preceeded with 40 barrels of CWI00 flush at 8.3 ppg and 40 barrels of mud push XL spacer at 12.$ ppg. · The bottom plug was dropped between the flush and spacer. The top plug was dropped after pumping the tall cement. We had full returns to surface throughout the lob. The plugs did not bump and the floats did not hold (slight flaw back). The casing was shut In with 0 I~1 for 4 hours. · J i _ i, i , i ,,, ,,, , ,, . i , Cement Company: J Rig Contractor: J Approved By: Dmvell J NABORS. J R, L, Morrlson/R. Bowie Phillips Alaska Drilling Daily Completion/Workover Report Wal: ~lm mA ~ ~D) ~ PB~ ~D) ~.~' Top ~ ~n~ ~RS' ~lly ~t $~ ~ ~mpl~o~o~r ~ T~I W~l~ ~ $ 2~ ~ ~{4 Rig N~me: Na~m ~gE In~la~ C~; ~.~"~ Pr~u~qp Llnec 7.~' ~ T~I E~m~ ~ $, O~m~on At~ D~ e~ ~ e~, ~ ~ ~. U~ln~ O~ns: Drill ~ fl~t ~llar at g~t ~,ng~.~y~r ~ ~ ~r~ ~ ~slnl~, ~ la, rig down,' ...... MUD ~E DAILY L~ ~bls) Bff NO. Bff NO. A~DE~ (non-spil~ ~ ~P~IVERT ~ ~P~RILL LSND 3 N TST 0~f W~G~ TOTAL L~ (bbls) S~E ~E EMPLO~R ~ H2S DR~L[' ~ F'IRE DRILL ~2,2pm e.l~ MA~ VI~$~ MA~ ~ILL ~ ~NFINED ~ SPILL DRILL ~ HTC N S~ACE ~ ' ,.PERFO~T~, .. ~E ~PE ~E .... . · "' ' "'"'¥UEL & WA~ER : ' ~1~7 INTERVALS, .' AT~ ~ , .' ..' :'." '... ' G~S .... SERIAL NO SERI~ NO VOLUME ~allons) ~EL useD ....... ~ F~F APl WL ' D~ O~ DE~ O~' ' ~ ~ M~G . DRILL W~R ~ED - ~ ~ ~.4 ~ ~LS ~P~L D~IN DE, IN ;' ...' "'. : ' ..' '' ' ~T~WA~ ~' J0,4m~min ~ ' , I~EC~ON'. ' , USED- BBLS ~U~ ~TAGE ~TAGE INJ~ W~L : . ~THER & ' ~ ~ ~RJ8 ' ' .PER~NNELDATA ' ' ' H~E'V~UME --- PUMP PRES ADT/A~ ADT/A~ ~URCE WELL ~MP~RE ~F .... ~=~ III / / ~.5 ppb III ph LINER ~' RPM 1 RPM ~ PRE~URE ~ WIND DIRE~ON 60 ~o.s ,111 LGS , SPM t ~A ~A INJEC~N FLUI~ 'CHILL FACTOR ~F ~.4~ III '~ w~r~. ~ VOL ' GPM 2 J~S J~S .... ;AR~ pER~N~'~ ' 0 DA~L~ ~uo sPS ~ ~ ~ .~ CO~ ~~o~ S~ III ~ P~SONNeL 0 0 TOTA~MUD ' SPP 1 " DULL DU~ .... TOTAL VOL ~b0 MI~ PER~NNEL 8 ~MP~ MUD ~ G~E G~E ..... TOT FOR WELL ~bl) ' ' SERVICE 8 ~o~o III III III ~ P~R~.NEL T~AL 47 . ii i ii i . . ,,, maE: :, I ;' 'E.D ';, {:', . HOURS '10~S COD~', "1'; ~0'~ SE~' "IPHASE ORS" ,'. I "' "' '"" :"' :'OPERA~ONS FROM ~'-'~ ,. ' ', ' '::' '~'.,'",, t2~0 ~:30 AM 4.60 CASG PROD Casing and Cemple~d ~nning 7" csg ~ 9389'. AM Cementing 04:30 0~0 AM 0.60 CASG PROD Casln~ and Make up hsnger ~ esg & rlh ~ Idg ~ Instil ~ head. AM Cementing 0;~0 09~0 AM 4.00 CEMENT PROD Casing and Cir I tend mud ~om ~2.7 ppg 167 vis out ~ t2.2 In I o~ 164 vis, AM Geme~ng reduced to 13. , 09~0 11~OAM 2.;0 ~EMENT PROD Casing and PJSM. CementT"as ~rprogram, s~ osglemt~forde~lls. Plug AB Cementing did n~ Idg on oaloula~d dlsp of 367 bbl - no press Increase as plug approached Idg collar. Clp ~3th~ t t :30 t2:00 PM 0.60 CEMENT PROD ~aslng and Floa~ I plug did n~ hold - SI ~r emt to gel. Wash up ~ueks & AM Counting suvaco lines. t2:00 08:MO PM 3.~0 CEMENT PROD Oasing and WOC PM Oemenflng O3:aO 04:30 PM 1.00 GEMENT PROD Casing and O~n up 7", no flew, obse~e for 30 min. PM Counting Io4:3o og:oo PM 1,60 CEMENT PROD Casing and Recover Idg ~ Run pack off assby & ~st to 6kpsl 130 mln. ;PM Cementing 06:00 07~0 PM 1.60 GEMENT PROD Casing and PJSM. X~ut pips rams ~ 4" & ~st to 6k psi, PM ¢emen~ng 07:30 Oe~O PM 0.60 GEMBNT PROD Casing and Set wear bushing. PM Cementing 08:00 12~0 AM 4.00 CEMENT PROD Casing and Make up bha & tih filling dp each MO00'. Depth ~ midnight PM Cementing 24.00 .... Supervisor: . MORRISON I R. BOWIE Daily Completion/Workover Report: Palm #lA 03/09/2001 Page 1 CASING TEST and FORMATION INTEGRITY TEST Well Name: Palm Date: 311010t Supervisor: R. Morrison Jr. ~ea$on{'$) for test: r'i Initial Casing Shoe Test [] Formation Adequacy for Annular Injection r'l Deep Test: Open Hole Adequacy for Higher Mud Weight Casing Size and Description: 9,625", 36~, J-ES, BTC Casing Setting Depth: 2,616' 'i'MD 2,616' TVD Hole Depth: 2,616'TMD 2,616' TVD' Mud Weight: 12.2 ppg Length of Open Hole Section: 0' Leak-off Press. + Mud Weight 0.052 x TVD -- 680 psi + 12.2 ppg 0.052 x 2,616' EMW for open hole section = 17.2 ppg Pump output = 0.0840 bps Fluid Pumped = 5.5 bbl 3,200 psi I I I I I I I I I I I I I I I I1 I 2,800 r~ ~,700 r~ roME LINE 2,400 ~ ~ ~ r~ ~K~FF ~ ~ ~ =~C~ING ~ST z~ , + LOT SH~ IN ~ME ~.~ ~ CA~NG TE~SH~ IN ~ME ~,~ .. I ~ME LINE ~,ooo ~ e~ ... ~ _ iii [;; ;;;~g; ;;; ;;; ...... , ........ '", .................. S~O~S ~iOTE: STROKES TURN TO MINUTES DURING "SHUT IN TIME":see time line above LEAK-OFF DATA MINUTE~ FOR LOT STROKE8 ...... ~, 0stks ...... ! 2 stks : 4stks i .i 16stks i ~o stk8 J [ 26_s_t s ; 30 stl(s I 36 stks J 42 stks PRESSURE 0 psi 2oo psi 44)0 psi 400 .psi 475 psi SOO ps! 525 psi ,. 575 psi 601) psi 610 psi 6~.Rsi 66O psi 680 j 48 stks . SO0 psi ...... soo ] 60 stks j 475 psi i I 66stks! $00ps, ; ...... 8~ I~ ~E~ SHUT IN 0.0 min~ ....... I 5~0 psi., 1.0 min I l : 2.0 min ~ l 3.0 mini i i 4.0 min l t 7,0 minj [ 8.0 rain l --j J ' 9.0 min ! J i jO.~!_nj _L j CASING TEST DATA MINUTEG FOR STROKES PRESSURE ~ · I · I I _ ! . i ; i i 1 SHUT IN TIME 0.0 min 1.0 rain SHUT IN PRESSURE 2.0 min j J J ~=:3'0 minj l, j 4.0 minj j -5.0min j =: j ..... i 6.0 min 7.0 minj j .I 8.0 rain 9.0 minj ............ · 10.0 minj ......... ! j 15.0 min 20.0 mini ! 25.0 rain J j I 30.0 min. J i ' NOTE: TO CLEAR DATA, HIGHLIGHT AND PRESS THE DELETE KEY i STATE OF ALASKA ( ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown __ Plugging __ Perforate _ Pull tubing _ Repair well __ Other _XX WELL TYPE 2. Name of Operator: ConocoPhillips Alaska, Inc. 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface: 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM At top of productive interval: 547' FNL, 1710' FEL, Sec. 17, T12N, R8E, UM At effective depth: Stimulate__ Alter casing __ 5. Type of Well: Development _. Exploratory ~ Stratagrapic ~ Service .XX (asp: 475955, 5993843) (asp: 480825, 5995857) At total depth: 417' FNL, 1409' FEL, Sec. 17, T12N, R8E, UM 12. Present well condition summary (asp: 481126, 5995987) Total Depth: measured 9400' Plugs (measured) true vertical 5945' Effective Depth: measured 9156' Junk (measured) true vertical Casing Length Size Cemented Conductor 80' 16" 225 sx AS I Surface 2581' 9.625" 580 SX AS III Lite & 340 sx Class G Production 9354' 7" 282 sx Class G, 398 sx Class G Liner 6. Datum of elavation (DF or KB feet): 34.8' RKB 7. Unit or Property: Kuparuk River Unit 8. Well number: 3S-26 9. Permit number/approval number: 201-040 / 302-337 10. APl number: 50-103-20361-01 11. Field/Pool: Kuparuk River Unit / Kuparuk River Field Measured depth True ve~icaldepth 115' 115' 2616' 2616' 9389' 5941' Perforation Depth measured true vertical 9047'-9137' 5811'-5845' Tubing (size, grade, and measured depth) 3.5", 9.3#, 8rd EUE @ 8999', 2.875" EUE8rd @ 9005' Packers and SSSV (type and measured depth) Baker SAB-3 @ 8881', No SSSV 13. Stimulation or cement squeeze summary Intervals treated (measured) N/A Intervals treated (measured) 14. Prior to well operation Subsequent to operation Representative Daily Average Production or In~ection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Pre-Produced Injector N/A N/A 5500 N/A Tubing Pressure N/A 15, Attachments Copies of Logs and Surveys run _ Daily Report of Well Operations _ 16. Status of well classification as: Oil _ Gas _ Suspended __ Service __XX MWAG 17. I hereby certif~ th~ the for. egoing is true and correct to the best of my knowledge. Signed Mike Moo~eg~y~ Title: Wells Group Team Leader Questions? Call Mike Mooney 263-4574 Date ~/~z/~.~ Form 10-404 Rev 06/15/88 ? ':": "IS BFL Prepared by Sharon AIIsup-Drake SUBMIT IN DUPLICATE MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Randy Ruedrich Commissioner THRU: Tom Maunder P.I. Supervisor FROM: DATE: February 23, 2003 SUBJECT: Mechanical Integrity Tests -'°'7''~ 3S Conoco Phillips Pad KRU Chuck Scheve Petroleum Inspector NON- CONFIDENTIAL Packer Depth Pretest Initial 15 Min. 30 Min. P.T.D.I 202-205ITypetestl P ITestpsil 1398 I Casingl 0 I 18751 18001 18001 P/F Notes: WellI 3S-14 I Type Inj. I S I T.V.D.I ITubing It I . I,ntervall I P.T.D.I 202-221 ITypetestl P ITestpsil 1389 I Casingl 775 I 19001 185O1 18501 P/F I -P Notes: I WellI 3S-26 I Type Inj.I S I T.V.D. I 5749 I Tubing I 2400 12400 I 2400 I 2400 I lntervall I P.T.D.I 201-040 ITypetestl P ITestpsil 1437 I Casingl 25 '1 16251 16001 158O1 P/F I -P Notes: WellI P.T.D.I, Notes: P.T.D.I Notes: IType Inj. Type test Type Inj. Type test Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS I NJ. S = SALT WATER INJ. N = NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Internal Radioactive Tracer Survey A= Temperature Anomaly Survey D.= Differential Temperature Test Interval I= Initial Test 4= Four Year Cycle V= Requi'red by Variance W= Test during Workover O= Other (describe in notes) Test'S Details I traveled to Conoco Phillips 3S Pad in the Kuparuk River Field and witnessed the initial MIT on wells 3S-09, 3S-14 and 3S~26. The pretest tubing 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: 3 Number of Failures: O Attachments: 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 02/12/03 Schlumberger Schlumberger Technology Corporation, by and through is Geoquest Division · 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Beth NO. 2655 Company: Alaska Oil & Gas Cons Corem Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Kuparuk Well Job # Log Description Date BL Sepia CD Color 1B-11 1~1-.1~ ;LDL 01/26/03 2B-10 ] ~.-O~Oj !STATIC BHP SURVEY 01/30/03 2G-17 c~O~.c~q :Z PERF RECORD & SBHP 02/04/03 3N-18 J~o- i~C~ 'STATIC BHP SURVEY 01/28/03 3S-07 -~- ! ~'7 PRODUCTION PROFILE 02/02103 3S-14 ~_C~_ -c~) O CROSSFLOW DETERMINATION LOG 02101103 3S-26 ~0)'0~0 'PRODUCTION PROFILE 01124/03 3S-14 ~ ~,~OG~_~'/ SCMT 01/31/03 ~ 0~-,~iD DATE: RECEIVED FEB 1 4 2005 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. A~ ~ & ~ Cons. Anch~e · ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon _ Suspend _ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program _ Pull tubing _ Vadance _ Perforate _ Other _X Change of Well Type 2. Name of Operator Conoco Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 5. Type of Well: Development __X Exploratory __ Stratigraphic __ Service __ 4. Location of well at surface 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM At top of productive interval 547' FNL, 1710' FEL, Sec. 17, T12N, R8E, UM At effective depth (asp's: 475955, 5993843) (asp's: 480825, 5995857) At total depth 417' FNL, 1409' FEL, Sec. 17, T12N, R8E, UM (asp's: 481126, 5995987) 6. Datum elevation (DF or KB feet) 34.8' RKB feet 7. Unit or Property name Kuparuk River, Unit 8. Well number 3S-26 9. Permit number / approval ndmber 201-040 10. APl number 50-103-20361-01 11. Field / Pool Kuparuk River Field/Kuparuk River Pool 12. Present well condition summary Total depth: measured 9400' true vertical 5945' Effective depth: measured 9337' true vertical 5921' Casing Length Size Conductor 80' 16" Surface 2581' 9.625" Production 9354' 7" Liner feet Plugs (measured) feet feet Junk (measured) feet Cemented 225 sx AS I 580 sx AS III Lite & 340 sx Class G 282 sx Class G, 398 sx Class G Measured Depth True vertical Depth 115' 115' 2616' 2616' 9389' 5941' Perforation depth: measured 9047' - 9137' true vertical 5811' - 5845' Tubing (size, grade, and measured depth Packers & SSSV (type & measured depth) .. 3.5", 9.3#, 8rd EUE @ 8999' Baker SAB-3 packer @ 8874', No SSSV REEEIVED OCT 2 4 2OO2 13. Attachments Description summary of proposal __ Detailed operations program __ BOP sketch _ IRefer to attached mornjr~g drilling report for LOT test, surface cement details and casing detail sheets, schematic 14. Estimated date for commencing operati6n /' 15. Status of well c assification'"as~ Oc~t~ber 2p.;""2002 / ........ ~~ 16. If proposal was verbally approve /'r ' ~ ,.~ Name of approver Date approved Se~ice ~' 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~, ~7'~-~,~ Title: Kuparuk Drilling Team Leader Rand}/Thomas FOR COMMISSION USE ONLY Questions? Call Randy Thomas 265-6830 Date Prepared by Sharon Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test _ Location clearance __ Mechanical Integrity Test__ Subsequent form required 10-_ Approval no. Approved by order of the Commission Form 10-403 Rev 06/15/88 · ORIGINAL SIGNED ML. Bi Commissioner SD IS BFL NOV SUBMIT IN TRIPLICATE. "~ PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 R. Thomas Phone (907) 265-6830 Fax: (907) 265-6224 October_5t, 2002 Ms. Cammy Oechsli Taylor Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501 Subject: 3S-26 Application for Sundry Approval (201-040) Dear Commissioner: Phillips Alaska, Inc. hereby files this Application for Sundry Approval for a change of well type of the Kupamk well 3S-26. If you have any questions regarding this matter, please contact me at 265-6830. Sincerely, Kupamk Drilling Team Leader RT/skad PL~ILLIPS AK INC PHi .LIPS Alaska, inc. Subsidiary ol~ PHILLIPS PETROLEUM COMPANY POSt Office Box 1003~ Anchorage, Aleska 99510-0360 P. Mazzolinl Phorte (907) 263-4603 Fax: (9o7) 26S-S'Z24 90? 265 6224 P.01/01 September- 4, 2002 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Palm lA Rename to 3S-26 Dear Commissioner: Phillips Alaska, Inc. is notifying AOGCC of our intentions to rename the Palm 1A well to 3S-26, If there arc any questions, please contact mc at 263-4603. Sincerely, P. Mazzolini Drilling Team Leader Phillips Drilling I ov 02 PM/skad TOTAL P. 01 ~ p,lu PS Alaska, Inc. . (e:..:A) A Subsidiary of PHILLIPS PETROLEUM COMPANY tJ~ ~J:Q Post OffIce Box 100360 Anchorage, Aluka 98510.0360 P. Mlzzollnl Phone (807) 263-4603 FIX: (907) 266-6224 September 4, 2002 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Palm IA Rename to 3S-26 Dear Commissioner: Phillips Alaska, Inc. is notifying AOGCC of our intentions to rename the Palm IA well to 3S-26. If there are any questions, please contact me at 263-4603. Sincerely, ?~Y11~ P. Mazzolini Drilling Team Leader Phillips Drilling PMlskad SCANNED MAY 1 4 2004 RECEI\/ED (,';9 n r~ 200-2 ......~_. \..; -,) ~laSK¡:¡ Oil &. lJå:" UJï¡,? vUliliihBSIU¡ 4nn!1offlf)f PHILLIPS Alaska, Inc.- A Subsidiary of PHILLIPS PETROLEUM COMPANY TRANSMITTAL CONFIDENTIAL DA TA FROM: Sandra D. Lemke, ATO1486 TO: Phillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Palm lA Lisa Weepie State of Alaska - AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 permit 201-040 DATE: 11/02/2001 Transmitted herewith is the following: Palm lA (501032036101) CD ROM Digital data and Final Report hardcopy v'/Fluid Analysis on Separator Samples- Phillips Alaska, Palm lA Final Report by Oilphase Houston, 08/01/2001; report and CD NAM679 P/ease check off each/tem as rece/ved, s/gn and return one of the transm/tta/ cop/es to address below All data to be held confidential until State of Alaska designated release date (AOGCC) Approx 4/2003 CC: Rick Levinson, PAT Geologist John IVlelvin, PAT Development Engineering Appr°ved f°r~. bL~Y:.. Receipt: · t[~ ~2_e._,E~ ~ ) __ .___J Date: I Return receipt to: Phillips Alaska, Inc. A'rFN: $. Lemke, ATO-1486 700 G. Street Anchorage, AK 99501 RECEIVED NOV 0 2 200~ Alaska Oil & Gas Cons. Commission Anchorage Prepared by: Sandra D. Lemke Phillips Alaska IT Technical Databases PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 P. Mazzolini Phone (907) 263-4603 Fax: (907) 265-6224 July 10, 2001 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 9950 ! Subject: Palm #lA (201-040 / 301-053 / 301-098) Completion Report Dear Ms. Commissioner: Phillips Alaska, Inc., as operator of the Palm #lA exploration well, submits the attached "Well Completion Report" (AOGCC form 10-407). Other attachments to the completion report include the directional survey, report of daily well operations, memo of abnormal pressure, test summary, geological tops and as-built. We will send under separate cover the logs, the mud logs, core description and other well data and reports. The Commission is requested to keep confidential the enclosed information due to the exploratory nature of this well. If you have any questions regarding this matter, please contact me at 263-4603 or Tom Brassfield at 265-6377. Sincerely, P. Mazzolini Exploration Drilling Team Leader PAI Drilling PM/TJB/skad RECEIVED JUL 1 Alaska Oil & Gas Cons. 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~ Gas D Suspended r~] Abandoned [~] Service D 2. Name of Operator;_. _ _~ ._ 7. Permit Number Phillips Alaska, Inc. ~t,OC,.,A'lr-tOf~' 201-040 / 301-053 / 301-098 3. Address ~'1~, . 8. APl Number P. O. Box 100360, Anchorage, AK 99510-0360~ 50-103-20361-01 4. Location of well at surface ' ;.,':i": ',' ': ~...~ ~ ~j'j'j'j'j'j'j'j'~~ 9. Unit or Lease Name 2574' FNL, 1305' FEL, Sec. 18, T12N, RSE, UM (ASP:475955, 5993843) . Kuparuk River Unit / .~-~i ~, 10. Well Number At Top Producing Interval 547' FNL, 1710' FEL, Sec. 17, T12N, R8E, UM (ASP: 480825,5995857) :.~:j[?,,~? .! Palm lA At Total Depth ....... _.,~ 11. Field and Pool 417' FNL, 1409' FEL, Sec. 17, T12N, RSE, UM (ASP 481126, 5995987) '" .... Exploration 5. Elevation in feet (Indicate KB, DF, etc.) 16. Lease Designation and Serial No. Kuparuk River Field / Pool 34.8' RKB, Pad 24.2'I ADL 380107 ALK 4624 12. Date Spudded 13. Date T.D. Reached 14. Date Com~., Susp. Or Aband. 115. Water Depth, if offshore 16. No. of Completions February 23, 2001 March 7, 2001 3,~/./.~2ee1' - Suspended'~Z:~I N/A feet USE 1 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 120. Depth where SSSV set 21. Thickness o! Permafrost MD / 5945' TVD 9337' MD / 5921' TVD YES r~ No E]I N/A feet MD 94OO' 1758' 22. Type Electric or Other Logs Run GR/EWR/CNP/SLD/BAT, DSI/CMR/MDT 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP Bo'FrOM HOLE SIZE CEMENTING RECORDI AMOUNT PULLED 16" 62.58# H-40 Surface 115' 24" 225 sx AS I 9.625" 36# J-55 Surface 2616' 12.25" 58o sx AS III Lite & 34O sx Class G 7" 26# J-55 Surface 9389' 8.5" 282 sx Class G Lead & 398 sx Class G Tail 24. Perforations open to Production (MD + TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 3.5" 9005' 8881' hole, n ' 26. 9047'-9137' MD 5811'-5845' TVD 5 spt, pert guns in ,.~,,~,_,T~/~_ /) ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED fl/'. I-./~ N/A N/A 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) April 1,2001 Flowing (refer to attached Test Summary) Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE I GAS-OIL RATIO 4/1 to 4/8 149.2 hrs (flow time) Test Period > 14,419 5349 0 variableI 371 Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY - APl (corr) 348 psig <1100 psi 24-Hour Rate > 2319 860 0 27 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. None RECEIVED JUL 1 g 7001 Alaska Oil & Gas Cons. Commission Anchorage Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE ORIGINAL Submit in duplicate GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity. MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. On April 1, 2001 perforated 90' MD Kuparuk interval at 5 spf with approximately 1200 psi underbalance using 4-5/8" tubing conveyE perforating guns and StimSleeve. Testing operations included foL flow periods and shut-in periods with final shut-in on April 8 and C80 (K-10) 2675' 2675' bottomhole pressure data acquisition until April 19, 2001. KICK-OFF POINT 2800' 2799' Stabilized production tested at 2350 STBOPD, 873 MSCFPD, 37; C50 4010' 3790' SCF/STBO, 0 BWPD at a 348 psig flowing tubing pressure. Test C40 (K-3) 4806' 4120' production totaled 14,419 STBO for the cumulative 149 hrs of flor from the Palm #lA Kuparuk interval. All fluids from the test were Top Moraine 7490' 5200' transferred to the CPF3 KRU processing facility. Produced gas Base Moraine 7845' 5340' was flared with incidental de minimis venting. Test separator Top HRZ (K-2) 8189' 5480' samples were collected on April 4 and April 5 for recombination C20 (mid HRZ) 8516' 5608' PV-I' studies. Base HRZ 8608' 5644' RECEIVED K- 1 8889' 5752' Top Kuparuk C 9046' 5810' LCU/TopMiluveach 9140' 5846' JUL :~ :~ ~00! TD 9400' 5946' Alaska Oil & Gas Cons. Commission Anchorage 31. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey, As-Built, Geological Tops, Test Summary, Memo of Abnormal Pressure 32. I hereby certify that the following is true and correct to the best of my knowledge. Questions? Call Tom Brassfield 265-6377 ! Signed Title Dfllling Team Leader Date - ~ I Paul Mazzc~lini i) O INSTRUCTIONS Prepared by Sharon A//sup-Drake 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 (DF, 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 ORIGINAL Operations Summary Palm lA Rpt Date 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/20/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM 02/21/01 12:00 AM Begin 00:00 00:30 02:00 03:00 06:30 07:00 08:00 09:00 09:30 10:30 11:30 13:00 18:00 18:30 22:00 23:30 00:00 00:30 04:30 09:30 10:00 10:30 11:30 12:00 13:30 14:00 14:30 15:15 16:00 16:30 17:30 20:30 Time End Time 00:30 02:00 03:00 06:30 07:00 08:00 09:00 09:30 10:30 11:30 13:00 18:00 18:30 22:00 23:30 00:00 00:30 04:30 09:30 10:00 10:30 11:30 12:00 13:30 14:00 14:30 15:15 16:00 16:30 17:30 20:30 21:00 Comments TIH TO 4556'. CIRC AND CONDITON MUD. RIH TO BOTTOM AT 6620'. ClRC AND COND MUD TO SPOT CEMENT ABANDONMENT PLUG. NO MUD LOSS TO HOLE. SPOT CEMENT PLUG IN OPEN HOLE FROM 6620' - 5900'- 275 SX CLASS "G" @ 15.8 PPG. POOH TO 5880'. CIRC BOTTOMS UP - TRACE CMT TO SURFACE. RIG REPAIR - CEMENT STANDPIPE WASHED OUT. RU TO CIRC WITH NEW HOSE. CIRC. PJSM. SPOTTED CEMENT ABANDONMENT PLUG FROM 5880' - 5200' - 275 SX CL "G" @ 15.8 PPG. CEMENT IN PLACE AT 10:30 HRS. POOH 11 STDS TO 4826' CBU - PUMP DRY JOB POOH LAYDOWN 45 JTS DRILLPIPE & 2 7/8 TUBING CHANGE ELEVATORS & RD POWER TONGS PU BIT - I STD FLEX COLLARS - JARS - 29 HWDP - 4" DP & TIH TO 5028' WASH 5028' - 5247'. TAG CEMENT 5247' SET DOWN 20K. WITNESSED BY CHUCK SCHEVE AOGCC. CBU - CONDITION MUD PJSM. SLUG DRILL PIPE. POOH WITH BIT. PJSM. RIH TO SPOT CEMENT ABANDONMENT PLUG #2 AND KICK-OFF PLUG. PU MULE SHOE SUB, 32 JTS 2 7/8" TUBING AND RIH TO 4922'. CIRC - SPOT HIGH VIS PILL FROM 4922' - 4700'. PULLED UP TO 4700' LAYING DOWN 7 JTS D.P. CIRC AND COND MUD. PJSM. DOWELL SPOTTED CEMENT ABANDONMENT PLUG #2 IN O.H. FROM 4,700' - 4,100' - 250 SX CL"G" @ 15.8 PPG. POOH TO 3,350' LAYING DOWN D.P. SPOTTED 30 BBLS HIGH VIS PILL FROM 3350'-3100'. PULLED UP TO 3100' LAYING DOWN D.P. CIRC AND COND MUD TO SPOT KICK-OFF PLUG. DOWELL SPOTTED CEMENT KICK-OFF PLUG FROM 3100'- 2660' - 300 SX (50 BBLS) CL "G" @ 17.2 PPG. POOH TO 2146' CIRCULATE HOLE CLEAN. PUMP DRY JOB POOH LAYDOWN 36 JTS DRILLPIPE - 32 JTS 2 7/8 TUBING. TESTED MANIFOLD AS POOH. MONITOR WELL STATIC - RIG DOWN 2 7/8 EQUIPMENT - CLEAN FLOOR Operations Summary Palm lA 02/21/01 12:00 AM 21:00 02/22/01 12:00 AM 00:00 02/22/01 12:00 AM 00:30 02/22/01 12:00 AM 02:30 02/22/01 12:00 AM 03:30 02/22/01 12:00 AM 05:30 02/22/01 12:00 AM 07:30 02/22/01 12:00 AM 09:00 02/22/01 12:00 AM 10:30 02/22/01 12:00 AM 12:00 02/22/01 12:00 AM 13:00 02/22/01 12:00 AM 18:00 02/22/01 12:00 AM 20:30 02/22/01 12:00 AM 21:30 02/22/01 12:00 AM 22:00 02/22/01 12:00 AM 22:30 02/23/01 12:00 AM 00:00 02/23/01 12:00 AM 03:00 02/23/01 12:00 AM 04:00 02/23/01 12:00 AM 04:30 02/23/01 12:00 AM 06:00 02/23/01 12:00 AM 11:00 02/23/01 12:00 AM 13:00 02/23/01 12:00 AM 19:30 02/23/01 12:00 AM 20:30 02/24/01 12:00 AM 00:00 02/24/01 12:00 AM 15:00 02/24/01 12:00 AM 16:00 02/24/01 12:00 AM 17:00 02/24/01 12:00 AM 18:30 02/24/01 12:00 AM 21:00 02/24/01 12:00 AM 22:00 02/24/01 12:00 AM 22:30 02/25/01 12:00 AM 00:00 02/25/01 12:00 AM 02:30 00:00 00:30 02:30 03:30 05:30 07:30 09:00 10:30 12:00 13:00 18:00 20:30 21:30 22:00 22:30 00:00 03:00 04:00 04:30 06:00 11:00 13:00 19:30 20:30 00:00 15:00 16:00 17:00 18:30 21:00 22:00 22:30 00:00 02:30 03:00 TEST FLOOR SAFETY VALVES - KELLY VALVES - MANIFOLD 250/5000. REPLACE KR VALVE ON KOOMEY UNIT. TEST WITNESS WAIVED BY JOHN CRISP WITH AOGCC. PJSM. PULLED WEAR BUSHING. TEST BOPE AS PER PAl POLICY TO 250 PSI LOW/5,000 PSI HIGH. HYDRILL TO 250 PSI/3500 PSI. VOLUME TEST KOOMEY. NO LEAKS. TEST WITNESS WAIVED BY JOHN CRISP WITH AOGCC. R.D. TEST EQUIP - PULLED TEST PLUG AND SET WEAR RING. DOWNTIME - CHANGE BREAKER FOR #3 GENERATOR - PJSM - BLOW DOWN RIG. CHANGE OUT BREAKER. GET STEAM AROUND. DOWN TIME - MOVE BHA TO UPPER PIPE SHED. PRE SPUD / PJSM. P.U. BHA #1- TAGGED UP AT 32'. ICE PLUG IN SURFACE CSG - THAW OUT SAME CHECK SPERRY TOOLS - FAIL TO COMMUNICATE. LAYDOWN TOOL & REPAIR CONNECTOR. TIH W/4" DRILLPIPE FROM DERRICK DRIFTING W/2.125" DRIFT TAG CEMENT @2553' DRILL FIRM CEMENT 2553-2571' CIRCULATE & CONDITION MUD LAYDOWN 2 STDS FROM DERRICK PJSM CUT DRILLING LINE PJSM. DRILL GOOD CEMENT FROM 2571' - 2680'. UABLE TO GET MWD TO WORK - TOOL FAILURE. CIRC HOLE CLEAN FOR TRIP OUT. POOH FOR MWD TOOL. REMOVE RA SOURCES. DOWN LOAD. CHANGE OUT PULSER. SURFACE TEST O.K. ORIENT TOOLS AND LOAD RA SOURCES. RIH TO 2680'. DRILL FROM 2680' - 3052' . KICKED OFF CMT PLUG AT 2700'. DISPLACED HOLE WITH 9.6 PPG LSND MUD WHILE DRILLING. CIRCULATE HOLE CLEAN & PERFORM PWD BASELINE TEST DRILL FROM 3052' - 3338' Drill from 3338' - 4422'. Pump sweep around and circ hole clean for wiper trip. Pulled four stands to 3997' - 25K drag / swabbing - +3 bbls hole filI.RIH. Cir¢ btms up - hole unloaded large amount clay - pumped high vis sweep around. Made 19 stand wiper trip to shoe - 5k - 10K drag - slight swabbing. Observe well. TIH TD @4422' - No problem Circ btms up Drill from 4422' - 4518' Drill from 4518' - 4645'. Auger packed off and froze up. Operations Summary Palm lA 02/25/01 12:00 AM 03:00 02/26/01 12:00 AM 00:00 02/26/01 12:00 AM 06:30 02/26/01 12:00 AM 08:30 02/26/01 12:00 AM 09:30 02/26/01 12:00 AM 10:30 02/26/01 12:00 AM 11:30 02/27/01 12:00 AM 00:00 00:00 06:30 08:30 09:30 10:30 11:30 00:00 00:00 Drill from 4645' - 5921'. Drill K-3 from 4774' - 5220' at 90 fph for Iwd logs. DRILL FROM 5921' -6399'. PUMP SWEEP AROUND AND CIRC HOLE CLEAN FOR WIPER TRIP. POOH WITH 23 STANDS TO 4100'. NO PROBLEMS - HOLE IN GOOD SHAPE. RIH - NO PROBLEMS. CIR BTMS UP - 157 UNITS TRIP GAS. HOLE UNLOADED CLUMPS CLAY / THICK MUD. DRILL FROM 6399' - 7165' Drill from 7165' - 8171' Max gas 538 units. ART = 11.0 Hrs. ADT = 1.75 Hrs. Mud wt increase 10.6# - 10.8#. 02/28/01 12:00 AM 00:00 02/28/01 12:00 AM 04:00 02/28/01 12:00 AM 04:30 02/28/01 12:00 AM 10:30 02/28/01 12:00 AM 12:30 02/28/01 12:00 AM 13:00 02/28/01 12:00 AM 14:00 02/28/01 12:00 AM 20:30 02/28/01 12:00 AM 21:30 03/01/01 12:00AM 00:00 03/01/01 12:00AM 01:00 03/01/01 12:00 AM 01:30 03/01/01 12:00 AM 02:00 03/01/01 12:00 AM 06:30 03/01/01 12:00 AM 07:00 03/01/01 12:00 AM 11:30 03/01/01 12:00 AM 13:00 03/01/01 12:00 AM 13:30 03/01/01 12:00 AM 15:00 03/01/01 12:00 AM 16:00 03/01/01 12:00 AM 18:00 03/01/01 12:00 AM 20:00 03/02/01 12:00 AM 00:00 04:00 04:30 10:30 12:30 13:00 14:00 20:30 21:30 00:00 01:00 01:30 02:00 06:30 07:00 11:30 13:00 13:30 15:00 16:00 18:00 20:00 00:00 02:30 2300 hrs swab out on #1 pump. drlg with one pump. Drlg 8171' - 8385' Gas increasing 180-200 units to +700 units. Check for flow, well static. Circulate hole clean, recovered large pieces of clay with gas dropping to <250 units. Drill 8385' - 8643' LD single. Pump hivis - weighted sweep. Circulate hole clean, recovered good amount of cuttings. POOH to 8111' Perform F.I.T. to 13.3 PPG EMW at 8643 md/5657 tvd - mud weight 10.8 PPG - Surface pressure 725. Monitor well, static. Pump dry job. Pooh - 6453' 20k overpull - work thru several times, continue pooh with no problem to csg shoe. Monitor well static - continue pooh to BHA. PJSM - Sperry Sun remove RA sources. Sperry Sun attempt down load tools. Not able to down load. Trouble shoot problem find bad connector - repairing same, Download Sperry Sun Tools. Stand tools in derrick, PJSM - pull wear bushing Drain & clean BOP stack. Rig up to test BOPE Weekly BOP test annular 300/3500# - rams - valves - manifold 300/5000#. Good test no failures. Install wear bushing. Witness of test waived by John Crisp AOGCC. Replace air boot on riser. Makeup BHA - orient- load RA sources-program tools. TIH w/HWDP - test Sperry tools. TIH to casing shoe @2616' CBU @2616' TIH to 5145' no problem CBU @5145' - mud very viscous & large amount cuttings. TIH to 8590' Break circulation - hole try packoff. Laydown 1 jt. break circulation. Circulate hole clean. Max gas 230 units. Begin weight up mud system in 0.3# increments from 10.8# to 11.8# at report time. Finish weight up mud system 11.8# - 12.2#. Take slow pump rates. 03/02/01 12:00AM 00:00 03/02/01 12:00 AM 02:30 03/02/01 12:00 AM 07:00 03/02/01 12:00 AM 08:30 03/02/01 12:00 AM 15:30 03/02/01 12:00 AM 16:30 03/02/01 12:00 AM 19:00 03/02/01 12:00AM 20:30 03/02/01 12:00 AM 22:00 03/02/01 12:00 AM 23:00 03/03/01 12:00AM 00:00 03/03/01 12:00 AM 11:30 03/03/01 12:00 AM 13:00 03/03/01 12:00 AM 14:00 03/03/01 12:00 AM 14:30 03/03/01 12:00 AM 16:00 03/03/01 12:00 AM 16:30 03/03/01 12:00 AM 21:30 03/03/01 12:00 AM 22:30 03/04/01 12:00 AM 00:00 03/04/01 12:00AM 03:00 03/04/01 12:00 AM 05:00 03/04/01 12:00 AM 05:30 03/04/01 12:00 AM 13:00 03/04/01 12:00 AM 15:30 03/04/01 12:00 AM 16:30 03/04/01 12:00 AM 21:30 03/04/01 12:00AM 23:30 03/05/01 12:00AM 00:00 03/05/01 12:00AM 01:00 03/05/01 12:00 AM 06:00 03/05/01 12:00 AM 09:00 02:30 07:00 08:30 15:30 16:30 19:00 20:30 22:00 23:00 00:00 11:30 13:00 14:00 14:30 16:00 16:30 21:30 22:30 00:00 03:00 05:00 05:30 13:00 15:30 16:30 21:30 23:30 00:00 01:00 06:00 09:00 11:30 Operations Summary Palm lA Finish weight up mud system 11.8# - 12.2#. Take slow pump rates. Ddll 8643' - 8810' TVD 5723' Art = 3,4 hrs Check for flow on all connections, Gas increase from 150 - 1400 units. Check flow - shutin well - 0 pressure. Open choke well static. Open hydril no flow. Circulate out gas. Drill 8810' - 9015' Art = 4.75 hrs. Ast = 0.5 hrs Gas increase to 962 units - circulate out gas. Drill 9015' - 9105' Art = 1.5 hrs. Check drlg break 9023' no flow. Gas increase to 905 units. Circulate out gas check flow - static. Drill 9105' - 9137' Art = 0.75 hrs. Gas increase to 766 units. Circulate out gas. *** Work on #1 mud pump replace swab. Drill 9137' - 9160' Art = 0.5 hrs. Drill 9160' - 9318' TVD 5914' TD hole section. Art = 9.7 hrs. Pump Hi vis sweep - circulate hole clean. Monitor well, static. Pump dry job. Blow down kelly. Pooh to 8500' no problem. Monitor well, static. TIH no problem. Circulate - pump Hi vis sweep - Max gas 163 units. Monitor well, static. Pump dry job - blow down kelly. Pooh 70 stds to csg shoe @2616' no problems. Bop drill. Service rig & adjust brakes. Tighten bolts on brakes equalizer bar. TIH 25 stds & fill pipe @report. Finish tih 9268' no problems. Broke circulation @7475' wash from 9268' - 9318' 50' - no fill. Circulate & condition mud, pumped hi vis - hi density sweep. Hole clean Monitor well, static, Pump dry job & drop 2.375" drift w/100' wire. POOH - S.L.M. - Monitor well @ shoe & HWDP,static continue pooh to dcs. PJSM with Sperry Sun. Remove RA sources. Download tools. LD Sperry tools & drill bit. PJSM - Schlumberger safety mtg - logging tools run on drillpipe. RU tools & equipment. PU Schlumberger logging tools & 33 joints drillpipe - drifted w/2.375" drift. Fill pipe & break circulation for 10 minutes every 10 stands. TIH 10 stds to 2618' - fill pipe & break circulation. Prepare to hang wireline sheave in derrick. Crew change & PJSM with Schlumberger. PJSM - Schlumberger hang wireline sheave in derrick. TIH w/drillpipe to 7376' filling pipe every 10 stds & circulate 10 minutes. RU Schlumberger side entry sub & xo subs. TIH w/wireline & stab onto connector. TIH w/drillpipe & wireline to 9180' Operations Summary Palm lA 03~5~1 03/05/01 03/05/01 03/05/01 03/06/01 03/06/01 03~6~1 03~6~1 03~6~1 03~6/01 03~6~1 03~6~1 03~6~1 0~06~1 03~6~1 03~6~1 03~6~1 03~6~1 03~7/01 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 12:00 AM AM AM AM AM AM AM AM AM AM AM AM AM AM AM AM AM AM AM 11:30 18:00 21:00 22:30 00:00 02:30 08:30 09:00 09:30 10:30 12:00 13:00 13:30 14:00 15:30 16:00 21:00 23:00 00:00 18:00 21:00 22:30 00:00 02:30 08:30 09:00 09:30 10:30 12:00 13:00 13:30 14:00 15:30 16:00 21:00 23:00 00:00 08:00 Schlumberger log CMR from 9180' - 9000' POOH to 8100' log 8100' · 7400'. POOH to 7376' side entry sub. POOH w/wireline to side entry sub. LD side entry sub & finish pooh w/wireline. TIH to 9225' - below Kuparuk formation, no problerr Circulate & condition mud @ 3bpm - 600# Cir / cond bottoms up prior to POOH w/DP conveyed logging tools. POOH w/logging tools & LD tools. RU cementing stand pipe in derrick. PJSM. Iniate radio silence procedures & RU Schlumberger. LD Schlumberger tools as directed. RIH w/11 stands DP. PJSM & LD 11 stands of DP. Monitor well & PJSM. PU BHA TIH to csg shoe @ 2616'. Cir BU Gas of 183 units. RIH to 9160, breaking circ @ 5127' & 7710' Wash / ream (precautionary) 5 joints to TD of 9318, circulating up max BU gas of 500 units. Drlg 9318 to 9325'. Drlg as directed to td of 9400' md. Palm lA Test Rpt Date 03/07/01 12:00 AM 03/08/01 12:00 AM 03/09/01 12:00 AM 03/10/01 12:00 AM Comments Monitor well & pump dry slug. Make wiper trip to shoe, tight spot 6 stands off td on way out, did not see upon returning to rd, no detectable fill on bottom. Pump high vis sweep, ¢ir / cond mud to 12.2 in lout, viscosity 55 sec. Observed light sh / ss w/sweep. Max gas 430u. Pooh for 7" production csg, @ midnight had 55 stands out, shoe is @ 77 stands out.. Complete Tooh laying down tools, stood back 21 jts hwdp for cleanout ops. Recover wear bushing & install test plug. PJSM X-out top rams to 7" & press test same 300 / 3500 psi. PJSM Rig up casing crew. PJSM / Review ops plan. Make up float equip to 7" csg & rih w/csg as per csg program. Cir bu @ shoe, filling each jt w/fill up line & cir 50 bbl each 1000 ft. Completed running 7" csg to 9389'. Make up hanger to csg & rih on Idg jt. Install cmt head. Cir / cond mud from 12.7 ppg / 87 vis out to 12.2 in / out / 54 vis, yp reduced to 13. PJSM. Cement 7" as per program, see csg / cmt rpt for details. Plug did not Idg on calculated disp of 357 bbl - no press increase as plug approached Idg collar. Cip 1131 hrs 03092001. Floats / plug did not hold - Si for cmt to gel. Wash up trucks & surface lines. WOC Open up 7", no flow, observe for 30 min. Recover Idg jr. Run pack off assby & test to 5kpsi/30 min. PJSM. X-out pipe rams to 4" & test to 5k psi. Set wear bushing. Make up bha & tih filling dp each 3000'. Depth @ midnight 3000" Continue to tih to 4660'. Si well due to LEL alarm on rig floor, ck no gas on rig floor w/portable gas meter, cir well over shakers via choke manifold, no gas @ shakers. Trouble shoot contineous alarm @ rig floor - traced to faltly control pannel. Ele¢ repairing same, open well Continue rih to tag cmt @ 9063'. Pick up kelly, singles & clean out from 9063' to 9235'. Rig repair- leaking kelly swivel- repair same. Continue to clean out to 5' above float collar @ 9337'. Circulate bottoms up. Pressure test csg to 3000 psi with mud. Run injection test on 9 5/8 x 7" annulus: pumped 50 bbl mud highest pressure observed 680 psi. See lot form for additional info. Displaced 7" csg to 8.5 ppg filtered sea water [ Final returned fluid - 36k cl- turbidity 53.2 NTU 100 unit range]: Pumped 150 bbl FW Followed by 480 bbls filtered SW as above. Pressure test 7" csg to 3500 psi / 30 min. Operations Summary · Palm lA Test 03/11/01 12:00 AM 03/12/01 12:00 AM 03/13/01 12:00 AM 03/14/01 12:00 AM Pooh / Id dp filling w/filtered sea water [incomplete rpt time]. x Simultaneous ops: Displaced 9 5/8 x 7" x 2000' annulus to diesel - pumped on e bbl diesel followed by 100 bbl FS [80deg F] chased w/60 bbl diesel. Initial pressure 900 psi / 2 bpm final 1 Complete Id dp, jt count 269 correct. PJSM Break kelly, safety valves, & remove spinner motors. Ld bha Pull wear bushing, install test plug & X-O top pipe rams to 3.5". Problems w/bushing & test plug clearing hydril element. Unsuccessful attempt @ testing hydril & upper pipe rams. Prepare to X-O Hydril element & inspect top 3.5" pipe rams. PJSM & ru Schlumberger to run USIT/GR. Rih w/Ioging tools & run cmt eval log [incomplete @ rpt time]. Loggers start logging @ 9320' - precautionary - did not want to tag td.. No fluid loss or gain. Complete USIT logging run & rd Sch. PJSM. Preplace Hydril element & X-O upper pipe rams to new 3.5". Test Hydril to 250 / 3500 psi & upper pipe rams / blind rams to 250 / 5000 psi. Recover test plug & set wear bushing. PJSM. Make 4 W.L. junk basket runs: #1 stopped @ 4200', recovered bits of cmt / steel / larger rubber, rec 3/4 of 10 oz cup. #2 ran to bottom of 9337', took wt @ 4200' worked same, re¢ vol as above, cmt & steel, one 3 x 2 x 1" chunk rubber. #3 ran Rd Schlumberger. PJSM. P.U. Howco tubing conveyed perforating guns. Run 3 1/2" tubing. Change out tubing tongs.. Run 3 1/2" completion assembly as per well plan - pkr at 8876'. PJSM. R.U. Schlumberger- ran GR/CCL correlation log. Packer 5' high. R.D. wire line Spot top shot at 9047' - rig up to circ. Cleared tubing. Dropped ball and rod. Set packer at 8881' with 2500 psi. PBR sheared off at 2,000psi. Held 2500 psi for 10 min. Test packer to 1500 psi for 10 min. Held. SPACE OUT TUBING WITH SEALS 1' OUT OF PBR. M.U. TBG HANGER. LAND TUBING. RILDS. TEST HANGER SEALS TO 1,000 PSI. SET TWCV. TEST TO 500 PSI AGAINST BLINDS. L.D. LANDING JT. R.D. TEST EQIPMENT. PJSM. CHANGE TOP RAMS TO 4". N.D. BOP'S. N.U. TBG HEAD ADAPTOR / 3 1/8" 5M TREE. TEST HANGER, ADAPTOR, AND TREE TO 250 / 5000 PSI. R.U. TO TEST TUBING / CSG. TEST LINES TO 3500 PSI. TEST TUBING TO 3,000 PSI FOR 30 MIN. HELD. TEST PACKER / 7" CSG TO 3,500 PSI FOR 30 MIN. HELD. SHEARED VALVE IN GLM AT 2507'. FREEZE PROTECTED 3 1/2" TBG AND 3 1/2" X 7" ANNULUS WITH 95 BBLS DIESEL. CIRC DIESEL TO SURFACE. Set BPV in tree. Install gages in tree and wellhead, clean cellar area & pits. Rig released 1900 hrs. 3/14/01. Palm #lA Well Test Summary Dr, hour, I ..t.:'n.,. I ~to:'n,~ I "":"'"' I psig I ,~,0~: I r~,.. I p.,,io I % I ~ I "'""=~" I '~ I h,~ I co,,,,~.t.: 5.9 4/01 10:47 4/01 16:41 5:54 1034 53 22 1006 9% 2974 gas not measured 305 Avg. rates based on manifested transfer volumes Well Shut-in at 16:41 hfs on 4/1 to tag guns and run gauges (EST) Flow Period #1 duration = 5.9 hrs. Shut-in period #1 duration = 7.8 hrs 13.7 4/01 16:41 4/02 00:30 7:49 1418 <<Shut-In Period ~ 18.2 4/02 00:30 4/02 05:00 4:30 1161 47 23 324 0% 1080 gas not measured 4 23.2 4/02 05:00 4/02 10:00 5:00 1157 55 24 694 0% 1891 gas not measured 3 27.2 4/02 10:00 4/02 14:00 4:00 1047 59 24 894 0% 2059 gas not measured 0 28.2 4/02 14:00 4/02 15:00 1:00 1077 60 24 1004 0% 1384 0,417 302 7 29.7 4/02 15:00 4/02 16:32 1:32 920 62 36 1123 0% 1842 0.438 267 8 30.5 4/02 16:33 4/02 17:15 0:42 831 63 48 1200 0% 2206 0.767 341 0 37.2 4/02 17:16 4/02 23:59 6:43 300 76 66 794 0% 3153 0.973 310 0 Oil rate from tank strap measurements Oil rate from tank strap measurements Off bypass in test separator, lining out gas meter 38.9 4/03 00:00 4/03 01:40 1:40 267 80 66 640 0% 2940 0.965 328 0 42.6 4/03 02:43 4/03 05:22 2:39 303 80 54 681 0% 2692 0.887 329 0 48.6 4/03 05:23 4/03 11:23 6:00 349 80 54 720 0% 2551 0.872 342 0 54,6 4/03 11:24 4/03 17:24 6:00 338 81 54 758 0% 2536 0.918 362 0 61.2 4/03 17:25 4/03 23:59 6:34 324 83 54 806 0% 2497 0.920 369 0 Reduced backpressure, excessive foaming in tanks 67.2 4/04 00:00 4/04 06:00 6:00 332 84 54 837 0% 2437 0.898 369 0 73.2 4/04 06:00 4/04 12:00 6:00 329 85 54 869 0% 2471 0.909 368 0 79.2 4/04 12:00 4/04 18:00 6:00 319 86 54 902 0% 2486 0.922 371 0 85.2 4/04 18:00 4/04 23:59 5:59 329 86 54 914 0% 2407 0.893 371 0 23:25 Oilphase commenced separator saml:)ling 91.2- 4/05 00:00 4/05 06:00 6:00 329 86 54 928 0% 2394 0.895 374 0 03:15 Oilphase completed sampling 93.7 4/05 06:00 4/05 08:28 2:28 329 86 54 943 0% 2389 0.895 374 0 93.8 4/02 00:30 4/05 08:35 80:05 <<Flow Period ~2 Well Shut in at 08:35 hfs on 4/5 to pull gauges Flow period #2 duration = 80.1 hrs Shut-in period #2 duration = 6.7 hrs in prep for production log 100.5 4/05 08:35 4/05 15:15 6:40 1347 <<Shut-In Period ~2 Shut-in for Slickline and Eline Rig Up 101.3 4/05 15:15 4/05 16:05 0:50 408 66 54 164 0% 3558 gas not measured 0 Restarting well in prep for log 103.72 4/05 16:30 4/05 18:30 2:00 341 74 54 564 0% 2665 1,012 391 0 SWS Production Loc~ 103.75 4/05 15:15 4/05 18:32 3:17 <<Flow Period Well Shut in at 18:32 hrs on 4/5 to run gauges for final flow and build up test Flow period #3 duration = 3.3 hrs Shut-in period #3 duration = 8.5 hrs 112.2 4/05 18:32 4/06 03:00 8:28 1372 <<Shut-In Period ~3 113.7 4/06 03:15 4/06 04:31 1:16 724 61 54 22 0% 2592 gas not measured 0 119.8 4/06 04:35 4/06 10:35 6:00 337 76 54 594 0% 2668 1.028 385 0 125.8 4/06 10:35 4/06 16:35 6:00 338 82 54 858 0% 2499 0.931 373 0 . 133.2 4/06 16:35 4/07 00:00 7:25 341 85 54 945 0% 2445 0.907 371 0 Restarting well 139.2 4/07 00:00 4/07 06:00 6:00 340 86 54 986 0% 2419 0.899 372 0 145.2 4/07 06:00 4/07 12:00 6:00 342 87 54 1002 0% 2396 0.888 371 0 151.2 4/07 12:00 4/07 18:00 6:00 346 88 54 1025 0% 2376 0.878 370 0 157.2 4/07 18:00 4/08 00:00 6:00 349 88 54 1039 0% 2365 0.875 370 0 163.2 4/08 00:00 4/08 06:00 6:00 348 87 54 1046 0% 2360 0.873 370 0 169.2 4/08 06:00 4/08 12:00 6:00 348 88 54 1054 0% 2354 0.873 371 0 171.8 4/08 12:00 4/08 14:35 2:35 348 89 54 1067 0% 2350 0.873 371 0 172.1 4/06 03:00 4/08 14:52 59:52 <<Flow Period #4 Well Shut in at 14:52 hrs on 4/8 with closing of downhole shut-in tool Flow period #4 duration = 59.9 hrs Shut-in period #4 duration = 264.1 hrs 436.1 4/08 14:52 4/19 14:56 264:04 1600 <<Shut-In Period #4 Confidential Palm #lA Testing ChronologY' Date Daily Summary. 03/14/2001 Nabors 19E Released from well at 1900 hrs. 03/20/2001 All Nabors 19E equipment off Palm ice pad. 03/24/2001 Nordic 2 Camp on location. 03/25/2001 Halliburton Energy Services testing equipment rig-up initiated. 03/27/2001 Pulled back pressure valve in preparation for testing. Continue equipment rig-up. 03/30/2001 Test equipment in-place and pressure tested. 03/31/2001 Rig up slickline, verified tubing to inner annulus (7", IA) communication by pumping diesel down tubing to annulus via open shear valve at 2514' MD to bleed tank at 0.25 bpm, shutdown pumping, pull RHC rod, pull shear valve at station 1, run DGLV in station 1, pressure test IA to 2500 psi (held solid, OA constant at 500 psi, tubing at 0 psi) retrieve RHC body from XN profile at 8987' MD. RD slickline. 04/01/2001 Presurized tubing to 4500 psi to fir~e tubing conveyed 4 5/8" 5 SPF Vannguns (HMX Super DP charges with Stim-Sleeve, EHD of 0.38", 45" penetration) from 9047'MD - 9137'MD (reference 3/11/2001 Schlumberger GR/USIT log). Bled wellhead pressure to 0 psig, opened to tanks, guns fired at 10:47 hrs (u_..n__de_.r_b. al_a_.n_~_e_....e_~t_!_~a.t_e~d__a~.2_.00_O_p~i) with an immediate response at surface; well began flowing to tanks via test bypass at rates of 900 to 3550 BFPD at a 18/64 to 22/64 choke setting with flowing tubing pressures of 500 to 1300 psi. BS&W dropped to less than 5% within two hours after approximately 200 bbls fluid were returned to surface. Gas rates are not available until flow begins through the test separator (currently on bypass during cleanup operations). Continued to flow well at restricted choke to clean-up, then shut-in for slickline work at 16:41 hrs (flow period gl: 5.9 hrs.). Drifted tubing and tagged guns at 9188' SLM, 51' below the bottom perf, ran Electronic Shut-In Tool (EST) with redundant gauges in XN profile at 8987'MD. Transferred 656 bbls Palm crude oil, 75 bbls water and 50 bbls diesel to KRU CPF-3 facility. 04/02/2001 Slickline off well at 12 AM (SITP:1418 psi), test restarted at 00:30 hrs (shut-in period gl 7.82 hrs) while bypassing separator, liquids to surface at 00:44 hrs. Placed well in separator at 11AM and lit flares (two tips, 60' high rated at 2.5MM each). Begin opening choke. Transferred 846 bbls Palm crude oil (cum. @ 1501 bbls) and 4 bbls water (cum. @ 79 bbls.) to KRU CPF-3 facility. 04/03/2001 The palmary rates continued throughout the day and into the night! Transferred 2517 bbls Palm crude oil (cum. @ 4019 bbls) and 12 bbls water (cum. @ 91 bbls.) to KRU CPF-3 facility. ). On-site gravity measured with hydrometer at 28.2 API; collected oil sample for AP1 analysis at KRU lab. 04/04/2001 Well performance continues to be strong at 2400-2600 STBOPD (wellhead pressure at 327 psi). Received KRU Lab API measurement: 25.5 API (no report issued). Oilphase initiated surface sampling program. Transferred 2567 bbls Palm crude oil (cum. @ 6586 bbls) and 0 bbls water (cum. @ 91 bbls.) to KRU CPF-3 facility. 04/05/2001 Oilphase completed surface sampling program for PVT recombination analyses and geochemical studies. Shut-in well at 08:35 hrs. (flow period #2:80.1 hrs), rig up slickline and pull electronic shut-in tool (EST) and gauges in preparation for production profile, rig down slickline. Rig up electric line unit, return well to production at 15' 15 hrs (shut-in period #2:6.67 hrs) log production profile (spinner-temp-gradio-pressure-gamma ray) utilizing Schlumberger's (SWS) 3.5" fullbore spinner-production logging tool at an average stable rate of 2665 bopd (WHP 341 psi, Temp 74.4 degrees F, bottomhole pressure and temperature approximately 1750 psi and 156 degrees F). Preliminary analysis indicates first Palm #lA Testing Chronology{. hydrocarbon production occurs at 9047' MD (top of the perfs, logs tied into CMR dated 3/5/2001), with relatively uniform production from the interval 9047'-9090' MD accounting for the majority of flow into the wellbore. Some production is entering the wellbore below 9090' MD, however it is below the spinner threshold (temperature data indicates production as evidenced by the increased temperature across the zone). Following the production profile the well was shut-in at 18:32 hrs (flow period #3:3.3 hrs) with SWS gauges at 9102' MD to record a build-up test while waiting for the HES slickline unit to return to the site (SWS recorded approximately 2 1/2 hours of data after shutting in at surface with pressure building from 1750 psi to 3400 psi). With the well shut-in, Schlumberger rigged down, and HES rigged up slickline to rerun the electronic shut-in tool. Transferred 1449 bbls Palm crude oil (cum. @ 8035 bbls) and 0 bbls water (cum. @ 91 bbls.) to KRU CPF-3 facility. 04/06/2001 Slickline rig down complete, returned well to production at 03:00 hrs (shut-in period #3:8.5 hrs) Well performance at 2400 to 2500 bopd and 370 scf/stbo GOR and 0% watercut. Transferred 1856 bbls Palm crude oil (cum. @ 9891 bbls) and 0 bbls water (cum. @ 91 bbls.) to KRU CPF-3 facility. 04/07/2001 Continued to flow well for final test flow period, average daily rates: 2376 STBOPD, 880 MSCFPD, 346 psi WHP (54/64 choke), 370 scf/stbo measured GOR. Transferred 2561 bbls Palm crude oil (cum. @ 12452 bbls) and 0 bbls water (cum. @ 91 bbls.) to KRU CPF-3 facility. 04/08/2001 Continued to flow well for final test flow period, average daily rates: 2354 STBOPD, 869 MSCFPD, 348 psi WHP (54/64 choke), 348 scf/stbo measured GOR. Completed flow test at 14:52 hrs with downhole closing of electronic shut-in tool (flow period #4:59.9 hrs). On- site gravity measured with hydrometer at 27.4 AP1 (sample sent to KRU lab for analysis). Left well with +/- 75 psi on the tubing with both master and wing closed. Flushed lines and equipment with 65 bbls diesel followed by 100 bbls. fresh water with 1 drum of WR-6. All fluids removed from tanks and equipment. Insulation and heat trace removed from lines in prep. for load-out tomorrow. Transferred 1967 bbls Palm crude oil (cum. @ 14419 bbls), 133 bbls water (cum. @ 224 bbls.) and 52 bbls diesel (cum. @ 102 bbls) to KRU CPF-3 facility. 04/09/2001 Rigging down test equipment. 04/10/2001 Rigging down test equipment. KRU lab results from 4/8 sample: API Gravity 25.6, 0% water, 0% sand. 04/11/2001 Test equipment rig down complete. 04/19/2001 Rig up slickline, pull guages at 14:56 hrs. (shut-in period #4:264 hrs), set 2.813" XXN plug at 8987', would not pressure test. Rig down for night. 04/20/2001 Rig up slickline, pull XXN plug at 8987', rerun plug, pressure test tubing to 2000 psi, open CMU sliding sleeve at 8819' MD, circulate 157 bbls diesel, 180 bbls 14.7 ppg mud and 78 bbls diesel in-place from tubing to IA (7"), shut sleeve at 8819', pressure test tubing to 2650 psi. Rig down. 04/21/2001 Rig up coiled tubing, displace tubing from 8800' to 2000' with 14.7 ppg mud with diesel freeze protect from surface to 2000'. Pressure tested tubing to 1500 psi and casing to 1000 psi per AOGCC. 04/23/2001 Set back pressure valve, close valves and remove handles. Install tapped blind flanges with V:," plugs screwed into flanges on all valves. Removed tree cap and installed a blind flange on swab. Clean-up cellar. Palm #lA Operation Shutdown complete. North Slope, Alaska Phillips Exploration Exploration 2001, Slot Palm #1 Palm #lA Job No. AKMM10063, Surveyed: 3 March, 2001 SURVEY REPORT 20 April, 2001 Your Reft AP1-501032036101 Surface Coordinates: 5993842.52 N, 475954.69 E (70° 23' 39.3813" N, Kelly Bushing: 60.38ft above Mean Sea Level 150° 11'44.3266" W) DRILLING SERVlr'Es Survey Ref: svy9403 A Halliburton Company Sperry-Sun Drilling Services Survey Report for Palm #lA Your Ref: APl-501032036101 Job No. AKMM10063, Surveyed: 3 March, 2001 North Slope, Alaska Measured Depth (ft) Incl. Azim. Sub-Sea Depth (ft) Vertical Depth (ft) 2643.27 0.830 114.050 2582.31 2642.69 2700.00 0.630 117.750 2639.03 2699.41 2747.69 3.660 104.580 2686.68 2747.06 2779.50 5.400 92.360 2718.39 2778.77 2812.10 6.620 87.610 2750.82 2811.20 2875.72 9.260 79.110 2813.82 2874.20 2940.53 11.950 72.320 2877.52 2937.90 3004.07 14.690 71.640 2939.35 2999.73 3067.69 17.280 69.720 3000.50 3060.88 3131.31 19.700 68.300 3060.83 3121.21 3195.05 22.000 67.930 3120.40 3180.78 3258.95 24.590 66.730 3179.08 3239.46 3322.92 27.010 66.470 3236.67 3297.05 3386.62 29.720 68.660 3292.72 3353.10 3450.24 32.720 70.420 3347.12 3407.50 3513.85 35.820 69.650 3399.68 3460.06 3577.73 39.030 68.480 3450.41 3510.79 3642.07 42.000 66.440 3499.32 3559.70 3705.24 44.660 67.230 3545.26 3605.64 3768.70 47.620 67.350 3589.23 3649.61 3833.08 50.920 66.890 3631.23 3691.61 3896.54 54.350 67.070 3669.74 3730.12 3960.25 57.820 66.330 3705.28 3765.66 4023.97 60.370 67.450 3738.01 3798.39 4087.72 62.620 67.630 3768.43 3828.81 4183.49 66.830 67.770 3809.31 3869.69 4279.12 66.930 67.770 3846.86 3907.24 4349.04 66.670 67.120 3874.40 3934.78 4438.04 66.250 67.160 3909.95 3970.33 4533.57 65.980 66.290 3948.63 4009.01 Local Coordinates Global Coordinates Northings Eastings Northings Eastings (ft) (ft) (ft) (ft) 15.57 S 50.28 E 5993826.79 N 476004.92 E 15.88 S 50.93 E 5993826.47 N 476005.57 E 16.39 S 52.64 E 5993825.96 N 476007.27 E 16.71S 55.12 E 5993825.64 N 476009.75 E 16.69 S 58.53 E 5993825.64 N 476013.16 E 15.57 S 67.22 E 5993826.73 N 476021.86 E 12.55 S 78.73 E 5993829.72 N 476033.38 E 8.01 S 92.65 E 5993834.21 N 476047.31 E 2.19 S 109.17 E 5993839.97 N 476063.86 E 5.05 N 128.00 E 5993847.16 N 476082.71 E 13.51 N 149.05 E 5993855.55 N 476103.78 E 23.26 N 172.36 E 5993865.22 N 476127.12 E 34.32 N 197.91E 5993876.20 N 476152.71E 45.84 N 225.88 E 5993887.63 N 476180.72 E 57.34 N 256.78 E 5993899.04 N 476211.65 E 69.58 N 290.44 E 5993911.17 N 476245.35 E 83.46 N 326.69 E 5993924.93 N 476281.64 E 99.50 N 365.27 E 5993940.85 N 476320.28 E 116.55 N 405.12 E 5993957.76 N 476360.19 E 134.21N 447.33 E 5993975.29 N 476402.45 E 153.18 N 492.27 E 5993994.11 N 476447.45 E 172.90 N 538.68 E 5994013.68 N 476493.93 E 193.81 N 587.23 E 5994034.44 N 476542.54 E 215.26 N 637.52 E 5994055.73 N 476592.89 E 236.66 N 689.29 E 5994076.97 N 476644.73 E 269.52 N 769.39 E 5994109.56 N 476724.95 E 302.79 N 850.80 E 5994142.57 N 476806.46 E 327.44 N 910.15 E 5994167.03 N 476865.89 E 359.14 N 985.34 E 5994198.49 N 476941.18 E 393.65 N 1065.58 E 5994232.74 N 477021.53 E Dogleg Rate (°/lOOft) 0.36 6.40 6.23 4.04 4.53 4.57 4.32 4.15 3.87 3.61 4.12 3.79 4.56 4.93 4.92 5.15 5.05 4.30 4.67 5.15 5.41 5.53 4.28 3.54 4.40 0.10 0.93 0.47 0.88 Phillips Exploration Exploration 2001 Vertical Section Comment 40.36 Tie On 40.84 KOP 42.22 44.38 47.53 55.98 67.77 82.36 99.85 120.01 142.69 167.96 195.80 226.05 258.99 294.77 333.56 375.35 418.69 464.44 513.22 563.65 616.51 671.18 727.20 813.78 901.72 965.99 1047.58 1134.92 20 April, 2001 - 13:49 Page 2 of 5 DrillQuest 2,00,08,005 Sperry-Sun Drilling Services Survey Report for Palm #lA Your Ref: API-501032036101 Job No. AKMM10063, Surveyed: 3 March, 2001 North Slope, Alaska Measured Depth (ft) Incl. Azim. Sub-Sea Depth (ft) Vertical Depth (ft) 4629.57 65.310 66.050 3988.22 4048.60 4725.57 66.050 67.440 4027.76 4088.14 4821.32 66,580 68.620 4066.22 4126.60 4916.78 65.560 67.240 4104.94 4165.32 5012.59 66,240 66.550 4144.07 4204.45 5108.07 65,650 66,530 4182.98 4243.36 5203.76 65.910 68.140 4222.24 4282.62 5298.52 67.050 67,230 4260.06 4320.44 5394.29 66.430 67.430 4297.88 4358.26 5490.20 66.920 66.510 4335.85 4396.23 5586.02 66.860 66,240 4373.46 4433.84 5681.83 66.270 65.990 4411.57 4471.95 5777.90 66.700 67.390 4449.90 4510.28 5873.16 67.060 67.380 4487.30 4547.68 5969.10 66.730 66.330 4524.95 4585.33 6064.61 66.460 65.540 4562.89 4623.27 6160.45 66.510 65.900 4601.13 4661.51 6256.28 66.190 65.060 4639.58 4699.96 6352.36 66.040 64,760 4678.48 4738.86 6448.06 66.930 66,100 4716.66 4777.04 6543.71 66.640 66,750 4754.37 4814.75 6639.40 66.250 66.540 4792.61 4852.99 6735.02 65.680 67.060 4831.55 4891.93 6830.80 65.230 66.950 4871.34 4931.72 6926.83 65.500 67.990 4911.37 4971.75 7022.21 65.450 67.470 4950.96 5011.34 7117.89 66.520 68.320 4989.90 5050.28 7213.52 66.660 69.040 5027.90 5088.28 7309.08 66.300 68.330 5066.03 5126.41 7404.53 65,990 67.040 5104.64 5165.02 Local Coordinates Global Coordinates Northings Eastings Northings Eastings (ft) (ft) (ft) (ft) 428.99 N 1145.58 E 5994267.82 N 477101.64 E 463.52 N 1225.95 E 5994302.09 N 477182.13 E 496.32 N 1307.27 E 5994334.64 N 477263.55 E 529.10 N 1388.13 E 5994367.15 N 477344.51 E 563.42 N 1468.57 E 5994401.22 N 477425.06 E 598.13 N 1548.55 E 5994435.67 N 477505.15 E 631.76 N 1629.07 E 5994469.04 N 477585.79 E 664.75 N 1709.45 E 5994501.77 N 477666.27 E 698.66 N 1790.64 E 5994535.42 N 477747.57 E 733.12 N 1871.69 E 5994569.61N 477828.73 E 768.44 N 1952.43 E 5994604.67 N 477909.58 E 804.03 N 2032.81E 5994640.01N 477990.08 E 838.89 N 2113.71E 5994674.60 N 478071.09 E 872.57 N 2194.58 E 5994708.03 N 478152.07 E 907.26 N 2275.72 E 5994742.45 N 478233.32 E 943.00 N 2355.76 E 5994777.94 N 478313.47 E 979.14 N 2435.86 E 5994813.81N 478393.69 E 1015.56 N 2515.73E 5994849.99 N 478473.67 E 1052.82 N 2595.29 E 5994886.98 N 478553.35 E 1089.30 N 2675.09 E 5994923.21N 478633.27 E 1124.46 N 2755.66 E 5994958.11 N 478713.96 E 1159.23 N 2836.19 E 5994992.62 N 478794.60 E 1193.63 N 2916.46 E 5995026.77 N 478874.97 E 1227.67 N 2996.66 E 5995060.54 N 478955.28 E 1261.11 N 3077.29 E 5995093.73 N 479036.02 E 1294.00 N 3157.59 E 5995126.36 N 479116.42 E 1326.88 N 3238.56 E 5995158.98 N 479197.50 E 1358.79 N 3320.31 E 5995190.62 N 479279.36 E 1390.64 N 3401.94 E 5995222.21 N 479361.09 E 1423.78 N 3482.70 E 5995255.09 N 479441.95 E Dogleg Rate (°/100ft) 0.73 1.53 1.26 1.70 0.97 0.62 1.56 1.49 0.68 1.02 0.27 0.66 1.41 0.38 1.06 0.81 0.35 0.87 0.33 1.59 0.69 0.45 0.78 0.48 1.02 0.50 1.38 0.71 0.78 1.28 Phillips Exploration Exploration 2001 Vertical Section Comment 1222.36 1309.84 1397.51 1484.76 1572.21 1659.39 1746.66 1833.54 1921.52 2009.59 2097.71 2185.60 2273.69 2361.30 2449.54 2537.16 2625.01 2712.75 2800.53 2888.23 2976,12 3O63.84 3151,16 3238.29 3325.57 3412.34 3499.73 3587.47 3675.06 3762.35 20 April, 2001 - 13:49 Page 3 of 5 DrillQuest 2.00,08,005 Sperry-Sun Drilling Services Survey Report for Palm #lA Your Reft API-501032036101 Job No. AKMM10063, Surveyed: 3 March, 2001 North Slope, Alaska Measured Sub-Sea Vertical Local Coordinates Global Coordinates Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings (ft) (ft) (ft) (ft) (ft) (ft) (ft) 7500.13 67.180 67.750 5142.63 5203.01 1457.50 N 3563.68 E 5995288.55 N 479523.04 E 7595.74 66.840 66.700 5179.97 5240.35 1491.57 N 3644.83 E 5995322.36 N 479604.30 E 7692.33 66.520 67.730 5218.21 5278.59 1525.92 N 3726.61 E 5995356.45 N 479686.19 E 7787.37 66.180 66.360 5256.33 5316.71 1559.87 N 3806.77 E 5995390.14 N 479766.46 E 7883.30 65.700 66.210 5295.44 5355.82 1595.10 N 3886.97 E 5995425.11 N 479846.77 E 7978.75 66.180 66.500 5334.36 5394.74 1630.06 N 3966.81 E 5995459.81 N 479926.72 E 8074.37 66.030 66.730 5373.09 5433.47 1664.76 N 4047.05 E 5995494.25 N 480007.08 E 8169.80 67.040 66.850 5411.09 5471.47 1699.26 N 4127.51E 5995528.49 N 480087.64 E 8265.33 66.570 65.710 5448.71 5509.09 1734.58 N 4207.90 E 5995563.55 N 480168.14 E 8361.08 65.970 66.000 5487.25 5547.63 1770.43 N 4287.88 E 5995599.15 N 480248.24 E 8456.37 67.390 64.920 5524.97 5585.35 1806.78 N 4367.48 E 5995635.24 N 480327.96 E 8552.55 67.320 64.210 5562.00 5622.38 1844.90 N 4447.64 E 5995673.10 N 480408.24 E 8648.15 67.110 66.240 5599.03 5659.41 1881.83 N 4527.66 E 5995709.78 N 480488.38 E 8743.84 66.650 64.630 5636.60 5696.98 1918.42 N 4607.70 E 5995746.11 N 480568.53 E 8839.44 68.040 66.730 5673.43 5733.81 1954.74 N 4688.09 E 5995782.17 N 480649.04 E 8935.10 68.180 66.580 5709.09 5769.47 1989.91 N 4769.58 E 5995817.08 N 480730.65 E 9030.55 67.990 67.190 5744.72 5805.10 2024.68 N 4851.03 E 5995851.58 N 480812.20 E 9126.05 68.050 66.290 5780.46 5840.84 2059.65 N 4932.38 E 5995886.29 N 480893.67 E 9221.87 67.640 66.470 5816.60 5876.98 2095.21 N 5013.70 E 5995921.59 N 480975.10 E 9400.00 67.640 66.470 5884.36 5944.74 2160.97 N 5164.73 E 5995986.87 N 481126.35 E All data is in Feet unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to 24' Ice Ele+35' RKB. Northings and Eastings are relative to H Ref (Palm #1 SHL). Magnetic Declination at Surface is 25.950° (21-Feb-01) The Dogleg Severity is in Degrees per 100 feet. Vertical Section is from H Ref (Palm #1 SHL) and calculated along an Azimuth of 67.270° (True). Based upon Minimum Curvature type calculations, at a Measured Depth of 9400.00ft., The Bottom Hole Displacement is 5598.60ft., in the Direction of 67.295° (True). Dogleg Rate (°/100ft) 1.42 1.07 1.03 1.37 0.52 0.57 0.27 1.06 1.20 0.69 1.82 0.69 1.97 1.62 2.49 0.21 0.63 0.88 0.46 0.00 Phillips Exploration Exploration 2001 Vertical Section Comment 3850.07 3938.09 4026.79 4113.84 4201.42 4288.57 4375.99 4463.52 4551.31 4638.94 4726.40 4815.07 4903.14 4991,10 5079.28 5168.04 5256.59 5345.14 5433.88 5598.60 Projected Survey 20 April, 2001 - 13:49 Page 4 of 5 DrillQuest 2.00.08.005 Sperry-Sun Drilling Services Survey Report for Palm #lA Your Ref: AP1-$01032036101 Job No. AKMM10063, Surveyed: 3 March, 2001 North Slope, Alaska Phillips Exploration Exploration 2001 Comments Measured Depth (ft) Station Coordinates TVD Northings Eastings (ft) (ft) (ft) 2643.27 2642.69 15.57 S 50.28 E 2700.00 2699.41 15.88 S 50.93 E 9400.00 5944.74 2160.97 N 5164.73 E Comment Tie On KOP Projected Survey Survey tool program for Palm #lA From To Measured Vertical Measured Depth Depth Depth (ft) (ft) (ft) 0.00 0.00 9400.00 Vertical Depth (ft) 5944.74 Survey Tool Description MWD Magnetic (Palm #1) 20 April, 2001 - 13:49 Page $ of $ DrillQuest 2.00.08.005 i I e1/28/m RLS B~M PER KSB ~OllSACS' ZONE 4, NAD27. ~. GEOGRAPHIC COORDINA~S ARE NAD27. 4. E~VA~ONS SHO~ ARE BRI~SH PEPLUM M~N 5, A~ DISTANCES ARE ~UE. · 6. ICE PAD IS ROTA~ 7g' EAST ~OV NOR~. 7. DA~S Of SUR~Y: ~1/28/01; ~: LOI-ll-PG'S 1~15. I ~ UMIAT MERIDIAN, EAT= 7e' 23' 39,499" LONG = 1Se' 11' 44,3ee" VICINITY MAP 1"= 2 Miles Y= 5,993,842,52' X= 475,954,69' 2,574 F,N,L, 1.3~5 F,E,L ..~_.9.:..A/g~%.~...... '.,.~ ,." GROUND ELEVATION = 22,2' TOP ICE PAD ELEVA~ON =' 24,2' 7 .................................. SURVEYOR'~ CERTIFICATE REGfSTERED AND LICENSED TO PRACTICE L~ND SURVEYING IN THE STATE OF ALASKA AND THaT THIS PL~T ~EPRESENTS X~ t ~ k~::: ~ SURVEY DONE BY ME OP UNDER MY / ~ DIRECT SUPERVISION AND THAT ~LL ~ CORRECT ~S OF JANUARY 28, 200t. MODULE: UNIT: PHILLIPS Alaska, Inc. PALM1 A Subsidiary o( PHILLIPS PETROLEUM COMPANY EXPLORATORY WELL CONDUCTOR AS BUILT LOCAT[ON CADD ~LE NO, J m DRA~NO NO: i s.E~: iREv: LK6elD374 el/28/el CEA-M1XX-6elD374 INTER-OFFICE CORRESPONDENCE ANCHORAGE, ALASKA Date: 4/23/01 Subject: Abnormal Pressure in Palm #1 & #lA From/Location: T.J. Brassfield Telephone: 265-6377 To/Location: Sharon Allsup-Drake As requested from the DNR for data submittal on the Palm #1 & lA wellbores, we are required to advise the agency of any abnormally pressured zones encountered while drilling these wells. Please find attached the mud weight graph plotted by depth for Palm 4/1 & #lA. The Kupamk interval was abnormally pressured and the required mud weight of 12.2 ppg was needed to drill and trip through this interval. Further details will be available from the logs and testing data to be submitted. 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Spud Well 0030 hrs 2/2/01 0 5 10 15 20 25 30 35 40 45 TIME TO DRILL (DAYS) Release Rig @ 1900 hrs 3/14/01 12.4 12.2 12 11.8 11.6 11.4 ;~l' 11.2 11 10.8 10.6 t-. 10.4 _~ 10.2 ~ 9.8 9.6 9.4 9.2 9 8.8 8.6 8.4 8.2 8 prepared by TJB 4/23/01 PHILLIPS Alaska, Inc. A Sul~idlary of PHIl. UPS PETROi. EUM COMPANY TRANSMITTAL CONFIDENTIAL DATA FROM: Sandra D. Lemke, ATO1486 TO: Phillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Palm ].&]A DATE: 05/26/2001 Lisa Weepie State of Alaska - AOGCC 333 W. 7~ Avenue, Suite 100 Anchorage, Alaska 99501-3539 Transmitted herewith is the following: Palm 1 501032036100 and Palm 1A ( 501032036101) EIx~ch - End of well report, Palm 1, 2/15/2001, Well resume, formation summary, rig activities, . mud record, directional survey, bit record, ddlling progress, rig time, final logs [//£poch - End of well report, Palm lA, 03/04/2001, Well resume, formation summary, rig activities, mud records, directional survey, bit record, drilling progress, rig time, final logs Log Data (film reproduc/ble) v" Epoch.Formation Log, Palm 1; 2"= 100'; 115'-6620'md ,, v/' Epoch Formation Log, Palm lA; 2"= 100'; 2800'-9318'md Please check off each item as received, sign and return transmittal to address below All data to be held confidential until State of Alaska designated release date (AOGCC) Approx 4/2003 CC: Rick Levinson, PAI Geologist Approved for tr~ Receipt: ~:::~J r-~ _ Return receipt to: . Phillips Alaska,. Inc. ~ .... Date: AI'FN: S. Lemke, ATO- 1486 700 G. Street Anchorage, AK 99501 Prepared by: Sandra D. Lemke Phillips Alaska I'T' Technical Databases MEMORANDUM TO: THRU: Julie Heusser Commissioner ~ 191ai~~~ o.~'~sUBJECT: P.I. Supervisor % {~.,~-~ ~, FROM: Chuck Scheve Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: April 21, 2001 Suspension Pressure Test Palm lA Phillips Exploration 201-040 ~Nr CONF!0JENTIAL ,~tion: 18 Township: 12N Range: 8E Lease No.: Ddlling Rig: Rig Elevation: Operator Rep.: Dan Riedel ...... Meridian: UM Total Depth: .... ~Caslnart'ub!na Data; Conductor:. 16" O.D. Shoe~ 115' Surface: ~ ~1..8 ,,, O.D. Shoe~ 2616'' ...... Intermediate: O.D. Shcet~ ' Production: 7" O,D. Shoe~ 93891.. . Liner: _ O~D. Shoe(~ L_ . .~ Tubing: -:~'-;1~2';' ' O.D. Tail(~ 9005: ..... Ca~In~ Removal: Casing Cut~ NIA Feet Casing Cutl~ NIA Feet Casing Cut~ N/A Feet Casing Cut~ NIA Feet Casing Cut~ N/A Feet Casing Cut~ NIA Feet Pluguln~ Data: Tvoe Plug Fc~unded on Bottom Top of Cement Mud Weight Pressure (bottom up) ~ of Cem.~nt Depth _v_e_rlfled? above pi ,u,,g Test Applied TV~e Plue. F.e~ndedkon: Verified? · . Open Hole Bottom Ddllpipe tag Perforation Bddge plug Wireline tag Annulus Balanced C.T. Tag Casing Stub Retainer No Surface I traveled to the phillips Alaska Inc. Palm lA exploration location and witnessed the preSSUre testing of the tubing and 7" casing in p'mperafion of suspending operations on ~is well A mechanical plug had been set in the tubing tail and both tubing and casing loaded with 14.7 ppg mud and a 2000 tUbi~ was PreSsure tested 11500 psi with no pressure loss observed.: The casing was then pressure tested to 1000' psi with the same result. E.C.;. Attachments: Distribution: orig - Well File c - Operator c- DNR/DOG c- Database c - Rpt File c- Inspector Rev.:5/28/00 by L.R.G. Suspension Palm lA 4.21-01 CS 4/26/01 an electronic image file in a format acceptable to the commission may be substituted for the sepia; (7) a tape, diskette, or other electronic medium acceptable to the commission and a verification listing of the digital data for all logs nm, except velocity surveys and experimental logs; the verification listing must include a written description of the logical and physical format of the digital data; and (8) the following items, or a written request proposing a date for submitting those items, subject to commission approval of that date for timeliness, if those items are unavailable within the 30-day filing period set out in this subsection: (A) a copy of all drill stem test and production test data and charts; (B) a brief summary of production tests, drill stem tests, wireline formation tests, and other formation tests performed, including test date, time, depth, duration, method of operation, recovered fluid types, fluid amounts, gas-oil ratio, oil gravity, pressure, and choke size; (C) conventional and sidewall core analysis determinations, if any, of porosity, permeability, and fluid saturation; (D) geochemical and formation fluid analyses obtained, if any. (c) The commission will, in its discretion, waive or modify the requirements of this section for a well if those requirements would not significantly add to the geologic knowledge of the area in light of the information that is available from other wells in the area. (d) In this section (1) "experimental l°gs'' means logs that are not commercially available from a well logging contractor; and (2) "velocity survey" means a survey, the primary purpose of which is to determine velocity of seismic waves through formations penetrated by a well by measuring travel times of seismic pulses from or near the surface to geophones placed at various depths in the well. History - Eft. 4/2/86, Register 97; am 11/7/99, Register 152 Authority - AS 31.05.030 AS31.05.035 20 AAC 25.072 TEMPORARY SHUTDOWN OF DRILLING OR COMPLETION OPERATIONS. (a) If circumstances prevent the continuation of the program approved on a Permit to Drill (Form 10-401), or if an operator wishes to change drill rigs, the operator shall apply to the commission for approval.to shut down drilling or completion operations temporarily. Based on the information received under this subsection, the commission will decide whether to approve the temporary shutdown of drilling or completion 33 operations. The request for operation shutdown must be submitted on an Application for Sundry Approvals (Form 10-403), providing a full justification for the shutdown, a description of the proposed condition of the wellbore upon shutdown of drilling or completion operations, the approximate date when drilling or completion operations will resume, and a proposed program for securing the well during the period of shutdown. An Application for Sundry Approvals is not required for planned shutdowns of well operations, if those shutdowns are described in the approved Permit to Drill. (b) The operator shall file with the commission, within 30 days after operation shutdown, a complete well record on a Report of Sundry Well Operations (Form 10-404), including a summary of daily well operations as described in 20 AAC 25.070(3) and a copy of all logs mn in the well as required by 20 AAC 25.071(b)(6). The commission will, in its discretion, waive the requirements of this subsection if drilling or completion operations are to be resumed within 60 days after operation-shutdown. (c) Shutdown of well operations does not establish a completion, suspension, or abandonment date for a well. (d) If well operations are not resumed within 12 months, the operator shall immediately proceed to abandon or suspend the well. Upon application of the operator, the commission will extend the 12-month period, if the operator shows that operational circumstances beyond the operator's control prevent resumption within the 12-month period. History - Elf. 4/2/86, Register 97; am 11/7/99, Register 152 Authority - AS 31.05.030 20 AAC 25.075 OTHER WELLS IN DESIGNATED AREAS. There are areas in the state where drilling operations could unexpectedly encounter oil, gas, or hazardous substances at shallow depths. When the commission obtains sufficiem evidence to define a specific area and the approximate depth range of the substances, it will issue an order that will present the evidence, define the area, and stipulate a drilling depth. After the issuance of such an order, any well drilled in the defined area, for any purpose, that exceeds the stipulated depth will require a drilling permit and may be subject to the other requirements of this chapter. History - Eft. 4/13/80, Register 74 Authority - AS 31.05.030 34 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 Tom Brassfteid Phone (907) 266-6377 Fax: (907) 265-6224 Emil: tbrass~ppco.com April 17, 2001 Daniel T. Seamount, Jr., Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 279-1433 P,e~ Application for Sundry approval for an Operations Shutdown Phillips Palm #lA C~O ~ - (3 ~ ~ Surface Location: 2574' FNL, 1305' FEL, Sec. 18, T12N, RSE, UM or ASP4, NAD 27 coordinates of X=475,955 & Y=5,993,843 Target Location: 531' FNL, 1686' FEL, Sec. 17, T12N, R8E, UM BHL: 431' FNL, 1446' FEL, Sec. 17, Tt2N, R8E, UM CONFIDENTIAL Dear Commissioner Seamount: Phillips Alaska, Inc. would like to request an operations shutdown at the Palm #lA wellbore located approximately 4 miles west of the Kuparuk River Unit's 3G Pad. This exploration well was drilled and completed by Nabors 19E and is in the final stages of being tested. This well was accessed via ice road originating near Kuparuk's 2G Pad. The attached Sundry and back-up information describes the operations shutdown for the existing wellbore. Phillips Alaska, Inc. would like to preserve the option of additional wellbore testing, diagnostics, and/or evaluation next winter exploration season. If you have any questions or require any further information, please contact me at 263-4603 or Tom Brassfield at 265-6377. Sincerely, Paul Mazzolini Exploration/Cook Inlet Team Leader Palm #lA Operations Shutdown CONFIDENTIAL Revised 4/16101 Reason for Operations Shutdown: Phillips would like to preserve the option of additional wellbore testing/diagnostics/evaluation next exploration season for the Palm #lA well. Notify AOGCC 24 hours in advance of the well suspension operations. Hold pre-job meeting with all personnel to discuss objectives, as well as safety and environmental issues. . Mobilize and rig up wireline unit and pumping unit after downhole gauges have been pulled from the well. Confirm status of the wellbore with personnel at location or call Mike Morgan at 263-4332. 2. RIH and set "XXN" tubing plug in the 3-1/2" Halliburton 'XN' nipple (2.750" ID) located at 8987' MD DPM. . RIH with Baker SMU sliding sleeve opening/closing tools to 8819' MD DPM. Open sliding sleeve and leave tools in position. Circulate kill weight fluid (see note below) down tubing and up the annulus-approx. 309 bbls of fluid. Note: Final BHP will determine kill weight fluid density. If the BHP is 3400 psi (~5805' TVD) the kill weight fluid will be 13.6 ppg. if the BHP is 3555 psi ((~5805' TVD) the kill weight fluid will be 14.4 ppg. The kill weight fluid will be a 9.6 ppg sodium chloride brine weighted up with barite to the 13.6 or 14.4 ppg. Contact Baroid mud plant for this NaCI LSND fluid. Approximate crystallization point is 10 deg F. . Freeze protect the 7" x 3-1/2" annulus & 3-1/2" tubing to 2000' by pumping 70 bbls of diesel down the annulus taking returns from the tubing. Place the tubing and annulus into communication and allow the fluids to swap out. , Close the sliding sleeve at 8819' MD DP~and POOH with wireline. RD wireline and pumping units, c,,~t-,,~3 \~ The 9-5/8" x 7" annulus was freeze protected to 2000' with 60 bbl of diesel on 3/10/01. 8. Set BPV, close all valves, and remove handles, Install tapped blind flanges with %" plugs screwed into the flanges on all valves including the wellhead annular valves. Risks: A spill could result if vandalism occurred during the Operations Shutdown. Level: Low Mitigation: All valves will have handles removed and tapped blind flanges installed. 9. Clean-up cellar and location to prepare for inspections and Summer Operations shutdown. 10. Hang sign on tree with the following information: Phillips Alaska, Inc. Palm #lA PTD # 201-040 APl # 50-103-20361-01 SHL: 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM TJB 4/16/01 i' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS CONFIDENTIAL 1. Type of Request: Abandon _ Suspend _ Alter casing _ Repair well _ Change approved program __ Operation Shutdown X Re-enter suspended well _ Plugging _ Time extension _ Stimulate_ Pull tubing _ Variance _ Perorate _ Other 2. Name of Operator phillips Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 4. Location of well at surface 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM At top of productive interval 531' FNL, 1686' FEL, Sec. 17, T12N, R8E, UM At effective depth At total depth 431' FNL, 1446' FEL, Sec. 17, T12N, R8E, UM 5. Type of Well: Development Exploratory Stratigraphic Service 6. Datum elevation (DF or KB) 34.8' RKB P.~124.2' 7. Unit or Property name Exploration 8. Well number . Palm. lA 9. Permit number 201-04O 10. APl number . 50-10.3-20361-01 11. Field/Pool Exploration fe~t ,, 12. Present well condition summary Total Depth: (approx) true vertical Effective depth: measured (approx) true vertical Casing Length Structural Conductor 108' Surface 2581' Intermediate Production 9354' Liner measured drilling @ 9400 5946 9342 5888 Size 16" 9.625" 7" feet feet feet feet Plugs (measured) Junk (measured) Cemented Measured depth True vertical depth 225 sx AS1 108' 108' 580 sx ASLite plus 340 SX Cl "G" 2616' 2616' 680 sx CI "G" 9389' 5935' Perforation depth:' 9047' to 9137' MD measured Tubing (size, grade, and measured depth) 3-112" 9.3 ppf L-80 8rd EUE M {~ 9148' MD Packers and SSSV (type and measured depth) Baker SAB-3 ~ 8881' MD w/DS nipple at 506' MD 13. Attachments Description summary of proposal X,,. Detailed operation program __ Contact Paul Mazzolini at 263-4603 or Tom Brassfield @ 265-6377with any questions. BOP sketch _ LOT test, surface cement details and casing detail sheets 14. Estimated date for commencing operation 4111~/0t , , . 16. If proposal was verbally approved 15. Status of well classification as: Oil Gas__ Suspended X,.. Name of approver Date approved 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Exploration Team Leader Date Paul Mazzolini FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity _ BOP Test_ Location clearance Mechanical Integrity Test_ Subsequent form require 10~. ...... IApproval No. I. Approved bY the order of the Commission Commissioner Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE Palm #lA, ~r:E #AX 2143 Completion Schematic, Sheet 2 of 2 Exploration Well - CONFIDENTIAL PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY See Sheet 1 for Completion Assembly Above PBR I Packer Assembly +1- 8,864' MD 5,742' TVD (1) Joint Tubing 6-foot Handling Pup Seal Stem / PBR with seal stem pinned to shear from PBR with 39ksi overpull. 6-foot Handling Pup Tubing Anchor, Model K-22, with Seal Nipple Baker SAB-3 Hydraulic set Packer XO, 4" LTC Box x 3-1/2" EUE 8rd pin 6-foot Handling Pup (2) Gas Lift Mandrels: CAMCO 'KBUG', 3-1/2" x 1", with Dummy Valve and Latch, with 10 foot handling pups top and bottom Production Tubing 3.112", 9.3#, L-80, EUE 8rd AB Modified (1) Landing Nipple: 3-1/2" Halliburton °XN', with 2.750" ID polished bore, with RHC plug loaded, and with 10 foot handling pups top and bottom (1) Cross over: 3-1/2" EUE 8rd box x 2-7/8" EUE 8rd Pin Kuparuk Top: 9,046' MD / 5,810' TVD Kuparuk Bottom: 9,138'MD / 5,845'TVD PBTD @ Float Collar @ 9343' Production Casing 9389' MD 1 5942' TVD 7", 26~, J-55, BTC (1) Tubing Conveyed Perforating Assembly, by Halliburton Energy Services, consisting of: (1) Ported Sub (Balanced Isolation Tool): Halliburton, 2-7/8" EUE 8rd Box (1) Time Delay Firing Head: Halliburton, 2-1/2", pinned with 7 pins for minimum 3543 psi surface pressure in 8.6 ppg seawater (1) Tubing Auto Release: Halliburton (3) 15 foot Spacers: Halliburton, 3-3/8" (x) Perforating Guns with Top Shot @ 9,046' MD: Halliburton, 90 foot length, 4-5/8", 5 SPF, with Stim Sleeve (1) Firing Head: Halliburton, Time Delay, with Ported Bull Plug, pinned with 7 pins for minimum 3543 psi surface pressure in 8.6 ppg seawater TD 8-112" Hole: 9,400' MD, 5,946' TVD Palm #lA, AFE #AX 2143 Completion Schematic, Sheet 1 of 2 Exploration Well - CONFIDENTIAL PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY aborn t9E RKB ~ 0' Fastings: 475,954 Northings: 5,993,843 Elevation: 59.0' BPMSL 16" Conductor ~ 115' MD (1) Tubing Hanger: FMC Gen V with 3-1/2" L-80 EUE 8rd pin down (1) Full Length Joint Tubing under Hanger (x) Spaceout Pups as Required (1) Landing Nipple @ 500' MD: Camco 'DS' nipple w/2.875" No-Go Profile (1) Gas Lift Mandrel @ + I - 2500' MD: Camco 'KBMM', 3-1/2" x 1", wi shear valve and latch (Max. OD 5.968", ID 2.92"), pinned for 3000 psi shear (casing greater than tubing differential), 6-foot handling pups installed above and below. Surface Casing 2616' MD 12615' TVD 9-5/8", 36#, J-55, BTC TD of 12-1/4" hole (3) Gas Lift Mandrels: Camco 'KBMM', 3-1/2" x 1", with dummy valves and latchs (Max. OD 5.390", ID 2.867"), 6-foot handling pups installed above and below on GLM. Spaced out w/3-1/2" 9.3# L-80 EUE 8rd tubing as follows: Production Tubing 3-112", 9.3#, L-80, EUE 8rd AB Modified GLM,# MD-RKB TVD-RKB 1 7,745' 5,300' 2 6,195' 4,675' 3 3,978' 3,775' (1) Gas Lift Mandrel ~ +i- 8,775' MD 1 5,709': Camco 'KBMM', 3-112" x 1", with Dummy Valve and Latch (Max. OD 5.390", ID 2.92"), 6-foot handling pups installed above and below. (1) Joint Tubing (1) Sliding Sleeve: Baker CMU with Camco 2.813 'D' profile above. Production Casing 9390' M D 1 5942' TVD 7", 26#, J-55, BTC (1) Joint Tubing (1) PBR I Packer Assembly by Baker Oil Tools ~ +1- 8,864' MD 15,742' TVD: See Sheet 2 for details See Sheet 2 for Packer Assembly and Below Palm #lA Operational Shutdown Subject: Palm #lA Operational Shutdown Date: Mon, 16 Apr 2001 17:10:36 -0800 From: "Tom J Brassfield" <tbrass@ppco.com> To: Tom Maunder <tom_maunder@admin.state.ak. us> CC: "Paul Mazzolini" <pmazzol@ppco.com> Tom, here is a proposed Operations Shutdown procedure for the Palm #lA wellbore. We would like to start this activity sometime this week after the downhole gauges are pulled. Any questions, please call me at 265-6377. The handover form is from Drilling to the Operations folks before the well was perforated and the guns dropped to bottom. Thanks, Tom (See attached file: Palm lA Agency Ops SD Proc by TJB 4 16 01 .doc)(See attached file: Palm lA Ops SD AOGCC cover w Phillips logo 4 16 01.rtf)(See attached file: Palm lA Ops SD AOGCC 403 4 11 01 .doc)(See attached file: Palm #lA Handover 031301.xls) (See attached file: Palm lA Sheet 1.doc)(See attached file: Palm lA Sheet 2.doc) PalmlA Agency Ops SD Proc by TJB 4 16 01 .doc Name: Palm lA Agency Ops SD Proc by TJB 4 16 01.doc Type: WINWORD File (application/msword) Encoding: base64 ~Palm lA Ops SD AOGCC cover w Phillips logo 4 16 01.rtf Name: Palm lA Ops SD AOGCC cover w Phillips logo 4 16 01.rtf Type: WINWORD File (application/rtf) Encoding: base64 BPalmlA Ops SD AOGCC 403 4 11 01 .doc Name: Palm lA Ops SD AOGCC 403 4 11 01.docI Type: WINWORD File (applicationlmsword) Encoding: base64 i Name: Palm #lA Handover 031301,xls [~-~ Palm #lA Handover 031301 .xls Type: EXCEL File (application/msexcel) Encoding: base64 PalmlA Sheet 1.doc Name: Palm lA Sheet 1.doc Type: WINWORD File (application/msword) Encoding: base64 PalmlA Sheet 2.doc Name: Palm lA Sheet 2.doc Type: WINWORD File (application/msword) Encoding: base64 I of 1 4117/01 8:17 AM PHILU._ Alaska, Inc. Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 Tom Brassfield Phone (907) 265-6377 Fax: (907) 265-6224 Email: tbrass@ppco.com c>~O ?- 0 ~/0 April 17, 2001 Daniel T. Seamount, Jr., Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 279-1433 Re: Application for Sundry approval for an Operations Shutdown Phillips Palm #lA Surface Location: 2574' FNL, 1305' FEL, Sec. 18, T12N, RaE, UM or ASP4, NAD 27 coordinates of X=475,955 & Y=5,993,843 Target Location: 531' FNL, 1686' FEL, Sec. 17, T12N, RaE, UM BHL: 431' FNL, 1446' FEL, Sec. 17, T12N, RaE, UM CONFIDENTIAL Dear Commissioner Seamount: Phillips Alaska, Inc. would like to request an operations shutdown at the Palm #lA wellbore located approximately 4 miles west of the Kuparuk River Unit's 3G Pad. This exploration well was drilled and completed by Nabors 19E and is in the final stages of being tested. This well was accessed via ice road originating near Kuparuk's 2G Pad. The attached Sundry and back-up information describes the operations shutdown for the existing wellbore. These procedures have been discussed with AOGCC personnel. Phillips Alaska, Inc. would like to preserve the option of additional wellbore testing, diagnostics, and/or evaluation next winter exploration season. If you have any questions or require any further information, please contact me at 263-4603 or Tom Brassfield at 265-6377. Sincerely, ~aul Mazzolini Exploration/Cook Inlet Team Leader ORIGINAL STATE OF ALASKA (' ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS CONFIDENTIAL 1. Type of Request: Abandon__ Alter casing _ Repair well Change approved program __ 2. Name of Operator Phillips Alaska1 Inc. ,3. Address i P. O. Box 100360, Anchorage, AK 99510 4. Location of well at surface 2574' FNL, 1305' FEL, Sec. 18, T12N, RSE, UM At top of productive interval 531' FNL, 1686' FEL, Sec. 17, T12N, R8E, UM At effective depth At total depth 431' FNL, 1446' FEL, Sec. 17, T12N, R8E, UM Suspend _ Operation Shutdown X Re-enter suspended well _ Plugging__ Time extension_ Stimulate_ Pull tubing_ Variance__ Perforate__ Other _ 5. Type of Well: Development __ Exploratory X Stratigraphic __ Service 6. Datum elevation (DF or KB) 34.8' RKB Pad 24.2' 7. Unit or Property name Exploration 8. Well number Palm lA 9. Permit number 201-040 10. APl number 50-103-20361-01 11. Field/Pool Exploration feet 12. Present well condition summary Total Depth: measured drilling @ 9400 (approx) true vertical 5946 Effective depth: measured 9342 (approx) true vertical 5888 Casing Length Size Structural Conductor 108' 16" Surface 2581' 9.625" Intermediate Production 9354' 7" Liner feet feet feet feet Plugs (measured) Junk (measured) Cemented 225 sx AS1 580 sx ASLite plus 340 sx CI "G" 680 sx CI "G" Measured depth 108' 2616' 9389' True vertical depth 108' 2616' 5935' Perforation depth: measured 9047' to 9137' MD Tubing (size, grade, and measured depth) 3-1/2" 9.3 ppf L-80 8rd EUE M @ 9148' MD Packers and SSSV (type and measured depth) Baker SAB-3 @ 8881' MD w/DS nipple at 506' MD APR .1 7 Alaska 0il & Gas Cons. Commission Anchr~r~¢e 13. Attachments Description summary of proposal X Detailed operation program __ BOP sketch Contact Paul Mazzolini at 263-4603 or Tom Brassfield @ 265-(~377with any questions. LOT test, surface cement details and casin-~ detail sheets 14. Estimated date for commencing operation 4/18/01 16. If proposal was verbally a v N f ,~.. vj~~ ~ld~ ams o approver Tom Maund~, 4/17/01 " approved 15. Status of well classification as: Oil__ Gas__ Suspended X 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed "'"--'~-J~- ~aul~l~ Title Exploration Team Leader Date FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness ~./ IApproval No. Plug integrity_ ., BOP Test_ Location clearance~ ,,,. I Test'j~, Subsequent form require 10 ~ ,, -- Mechanical Integrity · . L~ ¢~.~"~"-j ~ ~,,.%,[:)¢,.C._"~'- %,~::~ ~: t'~,,~ 'k,k5 \~;;~-,~ Approved by the order of the Commission D Taylor Seamoum Commissioner Date / / Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLI CATE Palm #lA Operations Shutdown, CONFIDENTIAL Revised 4/17/01 Reason for Operations Shutdown: Phillips would like to preserve the option of additional wellbore testing/diagnostics/evaluation next exploration season for the Palm #lA well. Notify AOGCC 24 hours in advance of the well suspension operations. Hold pre-job meeting with all personnel to discuss objectives, as well as safety and environmental issues. Mobilize and rig up wireline unit and pumping unit after downhole gauges have been pulled from the well. Confirm status of the wellbore with personnel at location or call Mike Morgan at 263-4332. 2. RIH and set "XXN" tubing plug in the 3-1/2" Halliburton 'XN' nipple (2.750" ID) located at 8987' MD DPM. . RIH with Baker SMU sliding sleeve opening/closing tools to 8819' MD DPM. Open sliding sleeve and leave tools in position. Circulate kill weight fluid (see note below) down tubing and up the annulus-approx. 309 bbls of fluid. Note: Final BHP will determine kill weight fluid density. If the BHP is 3400 psi (@5805' TVD) the kill weight fluid will be 13.6 ppg. If the BHP is 3555 psi (@5805' TVD) the kill weight fluid will be 14.4 ppg. The kill weight fluid will be a 9.6 ppg sodium chloride brine weighted up with barite to the 13.6 or 14.4 ppg. Contact Baroid mud plant for this NaCl LSND fluid. Approximate crystallization point is 10 deg F. . Freeze protect the 7" x 3-1/2" annulus & 3-1/2" tubing to 2000' by pumping 70 bbls of diesel down the annulus taking returns from the tubing. Place the tubing and annulus into communication and allow the fluids to swap out. 5. Close the sliding sleeve at 8819' MD DPM and POOH with wireline. 6. Pressure test tubing and casing to 1000 psi to confirm wellbore integrity. 7. RD wireline and pumping units. 8. The 9-5/8" x 7" annulus was freeze protected to 2000' with 60 bbl of diesel on 3/10/01. 9. Set BPV, close all valves, and remove handles. Install tapped blind flanges with Y2" plugs screwed into the flanges on all valves including the wellhead annular valves. · Risks: A spill could result if vandalism occurred during the Operations Shutdown. · Level: Low · Mitigation: All valves will have handles removed and tapped blind flanges installed. 10. Clean-up cellar and location to prepare for inspections and Summer Operations shutdown. 11. Hang sign on tree with the following information: Phillips Alaska, Inc. Palm #lA PTD # 201-040 APl # 50-103-20361-01 SHL: 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM TJB 4/17/01 WELL HISTORY HANDOVER FORM To Production XXX To Drilling Well Palm #lA ver APl # 50-103-20361-01 New Well XXX PTD# 201-040 Completion Date 3/14/01 WELL INFORMATION SITP lAP OAP BHP /Depth / Date / Inst. 0 0 225 3/14/01 Description Weight(ppg) Packer fluid Diesel/Sea water 8.5 Tubing fluid D esel/Produced fluids approx. 6.8 ppg DIRECTIONAL INFORMATION RKB 29.6 KOP 2800' Avg Hole Angle 68 Max angle of 68.18 @ 8935' Hole Angle @ TD 67.6 NEW~ ADDED OR RE-PERFED INTERVALS Top Bot SPF Gun Type Date 9047 9137 5 4 5/8" w/stim sleeve Well perforated and ~luns dropped to bottom I Approx Depths 1800 8881 1800 9047 Ddllers TD 9400' _ Number AX2143 DOWNHOLE INFORMATION PBTD/Tcp cf fill cr Junk: 9337' BPV Installed Way Check Downhole Plug Size Wt. Cond. 16" 65.5 Surf. 9 5/8" 36 Prod. 7" 26 Prod. Tubg. 3.5" 9.3 KNOWN Communication Date Tagge¢ IA VR Plug OA VR Plug 3/10/01 CASINGfTUBING DATA Depth Top Bot 0-115' Grade Conn. WELD J-55 BTCM 0-2616' J-55 BTCM 0-9389' L-80 8rdMod 0'- 9005 Tubing E~ IA [-~ OA SURFACE EQUIPMENT Tree FMC Gen 5, 5000 psi (Type/Pressure Rating) Tree Cap Conn 3" otis Tbg Hgr Conn 3.5" 8rd COMPLETION INFORMATION Depth Item Mfgr Model Vlv Size OD ID Valve Latch 506 Nipple Camco DS 4.562 2.875 2514 GLM Camco KBMM 1" 5.39 2.92 DCK2 BEK 3995 GLM Camco KBMM 1" 5.39 2.92 DV BK5 6194 GLM, Camco KBMM 1" 5.39 2.92 DV BK5 7764 GLM Camco KBMM 1" 5,39 2.92 DV BK5 8777 GLM Camco KBMM 1" 5.39 2.92 DV BK5 8819 SS/CMU Baker DS 4.375 2.812 8859 Seal Ass. Baker 4.5 2,992 8860 PBR Baker 5.875 3 8881 Packer Baker SAB-3 5.9375 3.25 8934 GLM Camco KBUG-2 1" 5,39 2.92 DV BK5 8961 GLM Camco KBUG-2 1" 5.39 2.92 DV BK5 8987 Nipple Howco XN 4.25 2.75 8999 XO Howco 3.5 to 2 7/8 4.5 2.25 9000 Sub Howco BIT 3.38 1.5 Rig released subsequent to full well completion as required on State Drilling permit; Yes No If no, specify remaining operations: ENVIRONMENTAL SITE INSPECTION __ Debris cleaned up on and around site __ Equipment and supply staging areas are clean and no evidenc( No debris is left on tundra __ No drums or garbage receptacles remain __ Well house area and does not show evidence of subsidence __ Well cellar is in good condition and small spills are cleaned up. Other - GENERAL INFORMATION Well SI for pressure build-up. Drilling Dept. Rep. Mike Whiteley/Ralph Bowie rev. 4/17/01 by Tom Brassfield Wells Group Review Title Field Drlg. Supv. Date 3/14/01 Title Date Production/Oper Dept. Rep. (hard copy pickup) Title Date Tom Maunder <tom_maunder@admin.state.ak.us> 04/17/01 10:31 AM To: Tom J Brassfield/PPCO @ Phillips cc: Bob Crandall <bob_crandall@ admin.state.ak, us>, John D Hartz <jack_hartz @admin.state.ak. us>, AOGCC North Slope Office <aogcc_prudhoe_bay @ admin.state.ak, us> Subject: Re: Palm #lA Operational Shutdown Tom, Further to our conversation. Jack, Bob, John Spaulding and myself have reviewed your proposal for securing Palm lA for operational shutdown. You are aware that since the brine will be weighted with bar, that some settling may occur and it may be necessary to use coil to retrieve the tail pipe plug. As we discussed, the only addition we recommend is that after the sliding sleeve is closed when all circulation and u-tubing is done that the tubing and annulus be pressure tested. The pressure test value is PPCo's choice, but we did talk of about 1000 psi. You indicated you would be sending over "hard" copies of the sundry application, incorporating the pressure testing discussed above. We will look forward to receiving those documents. Based on the information you have provided and incorporating what we have discussed, your proposal is approved. 30 days after this seasons work is accomplished, we will look forward to receiving the 404 with the well details. Please call with any questions. Tom Maunder, PE Petroleum Engineer AOGCC Tom J Brassfield wrote: > Tom, here is a proposed Operations Shutdown procedure for the Palm #lA > wellbore. We would like to start this activity sometime this week after the > downhole gauges are pulled. Any questions, please call me at 265-6377. The > handover form is from Drilling to the Operations folks before the well was > perforated and the guns dropped to bottom. > Thanks, Tom > > (See attached file: Palm IA Agency Ops SD Proc by TJB 4 16 01.doc) (See > attached file: Palm lA Ops SD AOGCC cover w Phillips logo 4 16 01.rtf) (See > attached file: Palm lA Ops SD AOGCC 403 4 11 01.doc) (See attached file: > Palm ~iA Handover 031301.xls) > > (See attached file: Palm lA Sheet 1.doc) (See attached file: Palm lA Sheet > 2 .doc) > > SD Proc by TJB 4 16 01.doc > Palm lA Agency Ops SD Proc by TJB 4 16 01.doc Type: WINWORD File (application/msword) > Encoding: base64 > > Name: Palm lA Ops SD AOGCC cover w Phillips logo 4 16 01.rtf > Palm lA Ops SD AOGCC cover w Phillips logo 4 16 01.rtf Type: WIN-WORD File (application/rtf) > > > 11 01.doc > Palm lA Ops SD AOGCC 403 4 11 01.doc (application/msword) > Name: Palm iA Agency 0ps Encoding: base64 Name: Palm iA Ops SD AOGCC 403 4 Type: WIN-WORD File Encoding: base64 Name: Palm #lA Handover 031301.xls Palm #lA Handover 031301.xls Type: EXCEL File (application/msexcel) Encoding: base64 Name: Palm iA Sheet 1.doc Palm iA Sheet 1.doc Type: WINWORD File (application/msword) Encoding: base64 Name: Palm iA Sheet 2.doc Palm iA Sheet 2.doc Type: WINWORD File (application/msword) Encoding: base64 tom_rnaundor.¥cf TRANSMITTAL CONFIDENTIAL DATA FROM: Sandra D. Lemke, ATO1486 TO: Phillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Palm lA DATE: 04/10/2001 Lisa Weepie State of Alaska - AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Transmitted herewith is the following: Palm iA (501032036101) ~OloqO CD ROM D/g/ta/ dat~. f Schlumberger- Open Hole Edits: CMR log- CMR processed; LWD6 format 7392-9180'md logged 03/04/2001, CD created 4/3/01; job 21154 / .Sperry Sun -EWR/ROP/DGR & CNP/SLD & DGR/Bimodal Acoustic; MD/TVD logging files/Directional Survey print and .PDF Acrobat formats. Digital LIS verification list Log Prints and sepia fi/ms (1 b/ue/ine and 1 fi/m each) /Schlumberger- Combinable Magnetic Resonance Log 03/05/01 /' Schlumberger-CMR-True Vertical Depth log display 03/04/01 ~ Schlumberger-Correlation Log-pre packer setting 03/13/01 ~'" .Schlumberger-Production Profile-spinner/temperature/pressure-gradio 4/5/01 vg' .Sperry Sun- MWD log data: ROP/DGR/EWR 2"&5"=100' MD Display log and TVD Display Log 3/3/01 / /'Sperry Sun- MWD log data; SLD/CNP/DGR 2"&5"-100' MD Display log and TVD display log 3/3/01 //' Sperry Sun-MWD log data; DGR/BAT (Bimodal Acoustic Log) MD and TVD display logs 3/3/01 Co/or Presentation log / Schlumberger- Ultrasonic Imager Log ,/Schlumberger-CMR total porosity (t2cutoff:33ms) (same display as Schlumberger CD listed above) Please check off each item as received, sign and return transmittal to address below All data to be held confidential until State of Alaska designated release date (AOGCC) Approx 4/2003 CC: Rick Levinson, PAI Geologist /,~ ~ RAeP;ri ~d f° r t ra~= ~'~/'~~ Return receipt to: Phillips Alaska, ]:nc. A'rrN: $. Lemke, ATO-1486 700 G. Street Anchorage, AK 99501 Date: APR 1 1 2001 ,.. a~a~. ~. ~ ~as ~Jons, ~;ommi~. .~nehorage Prepared by: Sandra D. Lemke Phillips Alaska ]:T Technical Databases STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon _ Suspend _ Operational shutdown _ Re-enter suspended well _ Other_X Alter casing _ Repair well _ Plugging _ ~me extension _ Stimulate _ Rig change & Change approved program _ Pull tubing _ Variance _ Pedorate _ Complete and Test 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB feet) Phillips Alaska, Inc. Development_ 34.8' RKB feet 3. Address Exploratory _X 7. Unit or Property name P. O. Box 100360 Stratigraphic__ Anchorage, AK 99510-0360 Service __ Kuparuk River Unit 4. Location of well at surface 8. Well number 2574' FNL, 1305' FEL, Sec.18, T12N, R8E, UM Palm lA At top of productive interval 9. Permit number / approval number 531' FNL, 1686' FEL, Sec. 17, T12N, R8E, UM 201-040 At effective depth 10. APl number 50-103-20361-01 At total depth 11. Field / Pool 431' FNL, 1446' FEL, Sec. 17, T12N, RSE, UM Exploration/ 12. Present well condition summary Total depth: measured 9438' feet Plugs (measured) cement abandonment plug from 6620'-5900' & 5880'-5200' true vertical 9438' feet cement abandonment plug #2 from 4700'-4100' & 3100'-2660 Effective depth: measured 9438' feet Junk (measured) true vertical 9438' feet Casing Length Size Cemented Measured Depth True vertical Depth Conductor 108' 16" 225 sx AS I 108' 108' Surface 2581' 9.625" 580 sx AS III Lite & 340 sx Class 2616' 2616' G Production Liner RECEIVED Perforation depth: measured No perforations MAR 0 9 2001 true vertical No Perforations Alaska 0il & Gas Cons. Commission Tubing (size, grade, and measured depth No tubing run Anchorage Packers & SSSV (type & measured depth) No packers, No SSSV 13. Attachments Description summary of proposal __X Detailed operations program m BOP sketch __ ! Refer to attached morning drilling report for LOT test, surface cement details and casing detail sheets, schematic i 14. Estimated date for commencing operation 15. Status of well classification as: March 10, 2001 16.~sal was verbally approved~ ~t...~ ~ ,.~a,, ~,-u, a~rov,=,~J~(~2'~' ~DD~a e~l~v~e t d Oil__ Service__ Gas__ Suspended__ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Questions? Call Todd Mushovic 265-6974 Title: Drilling Team Leader Date ri M~.zofini Prepared b)z Sharon AIlsup-Drake FOR COMMISSION USE ONLY Conditions of approval: PIugN°tify Commission so representative may witneSSintegrity __ BOP Test I Location clearance I I Approval no...~[_(~.~...~_ Mechanical Integrity Test ._~.. ,.:?. ~i~i NAL SIGN~"L~equent form required 10- ~,~1~"~ Approved by order of the Commission Commissioner Date Form 10-403 Rev 06/15/88 · i SUBMIT IN TRIPLICATE TO: SAMPLE TRANSMITTAL AOGCC 333 WEST 7TH SUITE 100 ANCH. AK. 99501 279 1433 AIR BILL: FEDX AUTO CHARGE CODE: AX2142 OPERATOR: PAl NAME: PALM #lA APl NO: SAMPLE TYPE: DRIES NUMBER OF BOXES: 1 SAMPLES SENT: ADDITIONAL PALM lA DRY DITCH SAMPLES- DEPTH RANGE 9318'-9400' T.D. SENT BY: D. L. PRZYWOJSKI UPON RECEIPT OF THESE SAMPLES, PLEASE NOTE ANY DISCREPANCIES AND MAIL A SIGNED COPY OF THIS FORM TO: RECEIVED: CC: L. ST. AUBIN ATO 1558 R. LEVINSON ATO 1604 AOGCC PHILLIPS BAYVIEW GEOLOGICAL FACILITY 619 EAST SHIP CREEK AVE SUITE 102 ANCHORAGE, AK. 99510 ~ ,/~DAN PRZYWOJSKI ABV100 · ".,,-~" ,:.~. ~ --,,.' Steve McKeever 03/07/2001 11:22 AM To: Nabors 19E Company Man/PPCO @ Phillips cc: Paul Mazzolini/PPCO @ Phillips, Tom J Brassfield/PPCO @ Phillips, Todd J Mushovic/PPCO@ Phillips Subject: Re: Palm #lA (201-040), Application for Sundry Approval We're good to go. ...................... Forwarded by Steve McKeever/PPCO on 03/07/2001 11:22 AM ........................... Tom Maunder <tom_maunder@admin.state.ak.us> on 03/07/2001 09:09:51 AM ............. To: Steve McKeever/PPCO @ Phillips cc: AOGCC North Slope Office <aogcc_prudhoe_bay@admin.state.ak. us> Subject: Re: Palm #lA (201-040), Application for Sundry Approval Steve, I have received you note regarding casing, cementing and completing the subject well. I have checked the well file and you are correct, these operations were not contained in the original approval. You have approval to proceed as you have indicated. I will look forward to receiving the sundry as you indicate. Good luck. Tom Maunder, PE Petroleum Engineer AOGCC Steve McKeever wrote: Following up on our recent telephone conversation, Phillips Alaska will tomorrow submit an Application for Sundry Approval to complete and test the Palm #lA. With this e-mail I am hoping for a verbal approval, should the rig activities this evening proceed faster than expected. The general procedure of what we expect to do is: 1) Circulate and condition the hole to run casing (we are currently running in the hole now to do this) 2) Run 7" 26# J-55 casing from surface to TD, then cement the string in accordance with AOGCC regulations. 3) Test casing to 3500 psi. 4) Shut in and secure well. 5) Rig down and move off Nabors Rig 19e. (Expected maximum period of time with no rig on well is 7 days. During this time casing pressure will be monitored daily) 6) Move in and rig up Nabors Rig 16e. 7) Complete the well with 3-1/2", 9.3~, L-80, EUE 8rd tubing. RECEIVED MAR 0 9 Z001 Alaska Oil & Gas Cons. Commissio~ Anchorage i' ,, 8) Nipple down BOPE, nipple up and test tree. 9) Rig down and move off Nabors 16e. 10) Hook up well for flow testing to surface tanks. Produced fluids will be trucked to Kuparuk production facilities or injected back into the Palm ~IA well bore. 11) Test zones as appropriate. When testing is complete the well will either be permanently abandoned in accordance with AOGCC regulations, or, if the well is deemed to be of commercial value, a request may be made (via Application for Sundry Approval) to the AOGCC to "keep" this well as part of a future development. The Application would include suspension and maintenance plans until either development is complete and the well can be brought on line, or the decision is made to permanently plug and abandon the well. Thanks kindly, Steve McKeever ~- tom_maunder.vcf RECEIVED Alaska Oil & Gas Cons. Commission Anchorage PHILLIPS Alaska, Inc. Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 P. Mazzolini Phone (907) 263-4603 Fax: (907) 265-6224 March 7, 2001 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Application for Sundry Approval Palm #lA (201-040) Dear Mr. Commissioner: Phillips Alaska, Inc. submits the attached Application for Sundry Approval on the exploratory well Palm lA. The well will be cased and cemented with the 7" casing procedure. We will then use the Nabors 16E to complete and test this well. These plans are per conversations and emails with Tom Maunder. The attached email outlines the procedure. If you have any questions regarding this matter, please contact me at 263-4603 or Todd Mushovic at 265-6974. Sincerely, P. Mazzolini Exploration Drilling Team Leader PAI Drilling PM/skad RECEIVED M/IR 0 9 2001 Alaska Oil & Gas Cons. Commission ,Anchorage APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon _ Suspend _ Operational shutdown _ Re-enter suspended well _ Other_X Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Rig change & Change approved program _ Pull tubing _ Variance _ Perforate _ Complete and Test 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB feet) Phillips Alaska, Inc. Development_ 34.8' RKB feet 3. Address Explorato~j_X 7. Unit or Property name P. O. Box 100360 Stratigraphic_ Anchorage, AK 99510-0360 service_ Kuparuk River Unit 4. Location of well at surface 8. Well number 2574' FNL, 1305' FEL, Sec.18, T12N, RSE, UM Palm lA At top of productive interval 9. Permit number / approval number 531' FNL, 1686' FEL, Sec. 17, T12N, RSE, UM 201-040 At effective depth 10. APl number 50-103-20361-01 At total depth 11. Field / Pool 431' FNL, 1446' FEL, Sec. 17, T12N, RSE, UM Exploration/ 12. Present well condition summary Total depth: measured 9438' feet Plugs (measured) cement abandonment plug from 6620'-5900' & 5880'-5200' true vertical 9438' feet cement abandonment plug ~Y2 from 4700'-4100' & 3100'-266¢ Effective depth: measured 9438' feet Junk (measured) true vertical 9438' feet Casing Length Size Cemented Measured Depth True vertical Depth Conductor 108' 16" 225 ex AS I 108' 108' Surface 2581' 9.625. 580 sx AS III Lite & 340 sx Class 2616' 2616' G Production Liner Perforation depth: measured No perforations R E C E iV E D true vertical No Perforations MAR Tubing (size, grade, and measured depth No tubing run Alaska 0il & Gas Cons. Commission Anchorage Packers & SSSV (type & measured depth) No packers, No SSSV 13. Attachments Description summary of proposal __X Detailed operations program m BOP sketch__ ! Refer to attached morning drilling report for LOT test, surface cement details and casing detail Sheets, schematic 14. Estimated date for commencing operation 15. Status of well classification as: March 10, 2001 Narr~'~f approver t d Service _ 17. I herebycertify that the foregoing is true and correct to the best of my knowledge. Questions? Call Todd Mushovic 265-6974 Signe~ ~z~ ~ Title: Drilling Team Leader Date ./ . · ' . Prepared by Sharon Al/sup-Drake FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness I Approval no. ~,~,. I c'"'-"~ Plug integrity m BOP Test _ Location clearance __ I,//~"7 I Mechanical ,ntegr~y Test __ Subsequent ,cfm required 10-~ ~' . Approved by order of the Commission D 1-c~ytor Sec~moun~: commissioner Date ..- . Form 10-403 Rev 06/15/88 · DUPLICATE / SUBMIT IN TRIPLICATE ....."v'" " .... ¥..- ¥ "Steve McKeever 03/07/2001 11:22 AM · , . : To: Nabors 19E Company MaWPPCO@ Phillips cc: Paul Mazzolini/PPCO@ Phillips, Tom J Brassfield/PPCO@ Phillips, Todd J Mushovic/PPCO@ Phillips Subject: Re: Palm #lA (201-040), Application for Sundry Approval We're good to go. ...................... Forwarded by Steve McKeever/PPCO on 03/07/2001 11:22 AM ........................... Tom Maunder <tom_maunder@admin.state.ak.us> on 03/07/2001 09:09:51 AM To: Steve McKeever/PPCO @ Phillips cc: AOGCC North Slope Office <aogcc_prudhoe_bay@admin.state.ak. us> Subject: Re: Palm #lA (201-040), Application for Sundry Approval Steve, I have received you note regarding casing, cementing and completing the subject well. I have checked the well file and you are correct, these operations were not contained in the original approval. You have approval to proceed as you have indicated. I will look forward to receiving the sundry as you indicate. Good luck. Tom Maunder, PE Petroleum Engineer AOGCC Steve McKeever wrote: > Following up on our recent telephone conversation, Phillips Alaska wil'l > tomorrow submit an Application for Sundry Approval to complete and test the > Palm %lA. With this e-mail I am hoping for a verbal approval, should the > rig activities this evening proceed faster than expected. > > The general procedure of what we expect to do is: > > 1) Circulate and condition the hole to run casing (we are currently running > in the hole now to do this) > > 2) Run 7" 26% J-55 casing from surface to TD, then cement the string in > accordance with AOGCC regulations. > > 3) Test casing to 3500 psi. > > 4) Shut in and secure well. > > 5) Rig down and move off Nabors Rig 19e. > > (Expected maximum period of time with no rig on well is 7 days. During > this time casing pressure will be monitored daily) > > 6) Move in and rig up Nabors Rig 16e. > RECEIVED > 7) Complete the well with 3-1/2", 9.3%, L-80, EUE 8rd tubing. > Alaska Oil & Gas Cons.. Commission Anchora§e 8) Nipple down BOPE, nipple up and test tree. 9) Rig down and move off Nabors 16e. 10) Hook up well for flow testing to surface tanks. Produced fluids will be trucked to Kuparuk production facilities or injected back into the Palm #lA well bore. 11) Test zones as appropriate. When testing is complete the well will either be permanently abandoned in accordance with AOGCC regulations, or, if the well is deemed to be of commercial value, a request may be made (via Application for Sundry Approval) to the AOGCC to "keep" this well as part of a future development. The Application would include suspension and maintenance plans until either development is complete and the well can be brought on line, or the decision is made to permanently plug and abandon the well. Thanks kindly, Steve McKeever ~- tom_maunder.vcf RECEIVED Alaska Oil & Gas Cons. Commission Anchorage PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 P. Mazzolini Phone (907) 263-4603 Fax: (907) 265-6224 March 7, 2001 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: APplication for Sundry Approval Palm #lA (201-040) Dear Mr. Commissioner: Phillips Alaska, Inc. submits the attached Application for Sundry Approval on the exploratory well Palm lA. The well will be cased and cemented with the 7" casing procedure. We will then uSe the Nabors 16E to complete and test this well. These plans are per conversations and emails with Tom Maunder. The attached email outlines the procedure. If you have any questions regarding this matter, please contact me at 263-4603 or Todd Mushovic at 265-6974, Sincerely, P. Mazzolini Exploration Drilling Team Leader PAI Drilling PM/skad DUPLICA-i"E RECEIVED ~/~R 0 9 200'1 Alaska Oil & Gas Cons. Commission Anchorage Re: Palm #lA (201-040), Application for Sundry Approval Subject: Re: Palm #lA (201.040), Application for Sundry Approval Date: Wed, 07 Mar 2001 11:09:51 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Steve UcKeever <smckeev@ppco.com> CC: ^OGCC North Slope Office <aogcc_prudhoe_bay@admin.state.ak.us> Steve, I have received you note regarding casing, cementing and completing the subject well. I have checked the well file and you are correct, these operations were not contained in the original approval. You have approval to proceed as you have indicated. I will look forward to receiving the sundry as you indicate. Good luck. Tom Maunder, PE Petroleum Engineer AOGCC Steve McKeever wrote: Following up on our recent telephone conversation, Phillips Alaska will tomorrow submit an Application for Sundry Approval to complete and test the Palm #fA. With this e-mail I am hoping for a verbal approval, should the dg activities this evening proceed faster than expected. The general procedure of what we expect to do is: 1) Circulate and condition the hole to run casing (we are currently running in the hole now to do this) 2) Run 7" 26# J-55 casing from surface to TD, then cement the string in accordance with AOGCC regulations. 3) Test casing to 3500 ps£ 4) Shut in and secure well. 5) Rig down and move off Nabors Rig 19e. (Expected maximum period of time with no rig on well is 7 days. During this time casing pressure will be monitored daily) 6) Move in and rig up Nabors Rig 16e. 7) Complete the well with 3-1/2", 9.3#, L-80, EUE 8rd.tubing. 8) Nipple down BOPE, nipple up and test tree. 9) Rig down and move off Nabors 16e. 10) Hook up well for flow testing to surface tanks. Produced fluids will be trucked to Kuparuk production facilities or injected back into the Palm #lA well bore. 1 of 2 3t7/01 11:10 AM Re: Palm #lA (201-040), Application for Sundry Approval > 11) Test zones as appropriate. When testing is complete the well will > either be permanently abandoned in accordance with AOGCC regulations, or, > if the well is deemed to be of commercial value, a request may be made (via > Application for Sundry Approval) to the AOGCC to "keep" this well as part > of a future development. The Application would include suspension and · maintenance plans until either development is complete and the well can be · brought on line, or the decision is made to permanently plug and abandon > the well. · · Thanks kindly, > Steve McKeever Tom Maunder <tom maunder~admin.state.ak, us> Petroleum Engineer Alaska Oil and Gas Conservation Commission 2 of 2 3/7/01 11:10 AM TO: SAMPLE TRANSMITTAL AOGCC 333 WEST 7TH SUITE 100 ANCH. AK. 99501 279 1433 DATE: MARCH 6, 2001 AIR BILL: FEDX AUTO AFT: 01-03-06-01 CHARGE CODE: AX2142 OPERATOR: PAl SAMPLE TYPE: DRIES SAMPLES SENT: BOX 1 2760-4350' BOX 2 4350-5700' BOX 3 5700-7220' BOX 4 7220-8320' BOX 5 8320-9320' NAME: PALM #lA APl NO: NUMBER OF BOXES: 5 SENT BY: D. L. PRZYWOJSKI UPON RECEIPT OF THESE SAMPLES, PLEASE NOTE ANY DISCREPANCIES AND MAIL A SIGNED COPY OF THIS FORM TO: RECEIVED: ~ CC: L. ST. AUBIN ATO 1558 R. LEVINSON ATO 1604 AOGCC PHILLIPS BAYVIEW GEOLOGICAL FACILITY 619 EAST SHIP CREEK AVE SUITE 102 ANCHORAGE, AK. 99510 ATTN: DAN PRZYWOJSKI ABV100 Palm. lA Poro.,Pressure Prediction Subject: Palm lA Pore Pressure Prediction Date: Wed, 21 Feb 2001 16:35:24-1000 From: "Charles W Landmesser" <clandme~ppco.com> To: steve_davies~admin.state.ak.us CC: "Steve McKeever" <smckeev~ppco.com>, "Tom J Brassfield" <tbrass~ppco.com>, "W Dallam Masterson" <wmaster~ppco.com>, "Kathy J Heinlein" <kheinle~ppco.com>, "Rick Levinson" <rlevins~ppco.com> With reference to our telephone conversation this morning, the attached file contains seismic displays along a traverse through the Palm 1 and lA well paths and the pore-pressure profile along the planned Palm lA well path. A basemap showing the location of this traverse on the K-3 marker time surface is also included. After evaluation of the seismic data and the pore pressure volume along the Palm lA well path, we anticipate the stratigraphy and the pore pressures in Palm lA to be the same as those encountered in Palm 1. The horizontal offset of the two well penetrations at the K-3 level is approximately 2900 feet. (See attached file: PalmlA PorePressure 022101.ppt) -- -- The zone in question from our earlier report (Pre-Drill Seismic Pore Pressure Prediction for Palm %1 and Palm %2, December 19, 2000) occured just below the "K-3" horizon along the original sidetrack wellpath. The wellpath being permitted for Palm iA is not expected to penetrate any zones of elevated pressure at this level (see attached pore pressure profile). The mud program in Palm iA calls for mud weight of 10.2 ppg at the K-3 level consistent with what we encountered on drilling at Palm 1. Additionally, with the casing shoe test at 16 ppg we do not anticipate any problem increasing the mud weight if necessary. Drilling personnel have been advised of the potential for pressures above those anticipated from this evaluation, and will be alert to taken appropiate measures to ensure a safe drilling operation. Please advise if you have any questions or require any additional information. C. W. Landmesser Staff Geophysicist Phillips Alaska, Inc. 265-6384 Na~ne: Palm 1..'\_l~orc.Pressu,'e (.)221 (.)1 .ppt ~ [~Palml.\ 'PorcPrcssurc 02210_1..p_1?_[ Type: PO\VI-iRi~N'I'' .File (application ppt). it i Encoding' base64 ~ 1 of 1 2/21/01 4:42 PM ALASKA OIL AND GAS CONSERVATION COMMISSION Paul Mazzolini Exploration/Cook Inlet Team Leader Phillips Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Kuparuk River Unit Palm # 1-A Exploratory Phillips Alaska, Inc. Permit No: 201-040 Sur. Loc. 2574'FNL, 1305'FEL, Sec. 18, T12N, R8E, UM Btmhole Loc. 43 I'FNL, 1446' FEL, Sec. 17, T12N, R8E, UM Dear Mr. Mazzolini: TONY KNOWLES, GOVERNOR 333 Wo 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you fi.om obtaining additional permits required by law from other govemmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. A weekly status report is required fi.om the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's intemal use. Annular disposal of drilling wastes will not be approved for this well until sufficient data is submitted to ensure that the requirements of 20 AAC 25.080 are met. Annular disposal of drilling waste will be contingent on obtaining a well cemented surface casing confirmed by a valid Formation Integrity Test (FIT). Cementing records, FIT data, subsequent LOT data following setting production casing, and any CQLs must be submitted to the Commission on form 10-403 prior to the approval of disposal operations. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or fi.om where samples are first caught and 10' sample intervals through target zones. The blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE tests must be given so that a representative of the Commission may witness the tests. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. ~Si r y, anie . eamoun, r. Commissioner BY ORDER OF THE C.O~M~SSION DATED this 2t/ ~ day of February, 2001 dlf/Enclosures cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.OO5 la. Type o! work: Ddll [] Redrill L.~ I lb. Type of well. Exploratory [] Stratigraphic Test [] Development Oil [] Re-entry [] Deepen DI service [] Development Gas [] Single Zone [] Multiple Zone[] 2. Name of Operator 5. Datum elevation (DF or KB) 10. Field and Pool Phillips Alaska, Inc. CONFIDENTIAL RKB 34.8 feet Kuparuk River Field/Pool 3. Address 6. Property Designation Exploration P.O. Box 100360 Anchorage, AK 99510-036~ ADL 380107 ALK 4624 Moraine/Kuparuk 4. Location of well at sudace 7. Unit or property Name 11. Type Bond (see 2O AAC 25.0251) 2574' FNL, 1305' FEL, Sec. 18, T12N, R8E, UM Kuparuk River Unit Statewide At top of productive interval 8. Well number Number 531' FNL, 1686' FEL, Sec. 17, T12N, R8E, UM Palm #lA #59-52-180 At total depth 9. Approximate spud date Amount 431' FNL, 1446' FEL, Sec. 17, T12N, R8E, UM January 20, 2001 $200,000 12. Distance to nearest property line I 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) 1064 @ TD feetI Colville #1 2.7 mi @ surface feet 2448 9600' MD / 5913' ']'VD 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(3)) Kickoff depth: 2780 MD Maximum hole angle 72 Maximum surface 3188 psig At total depth (TVD) 3580 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of Cement Hole Casin~l Wei~lht Grade Couplin~l Le%lth MD TVD MD TVD (include sta~le data) 24" 16" 62.5# H-40 Weld 80 28 28 108' 108' 9 cy High Early 12.25 9.625" 36# J-55 BTC 2632 28 28 2616' 2615' 590 sx AS III L & 350 sx Class G 8.5" 7.0" 26# J-55 BTC Mod 9572 28 28 9600' 5913' 260 sx Class G 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total Depth: measured 6620 feet Plugs (measured) 5400' MD to 6620' TD, 4100' MD to 4700' MD true vertical 6029 feet 2800' MD to 3100' MD Effective Depth: measured 2800 feet Junk (measured) true vertical 2799 feet Casing Length Size Cemented Measured depth True Vertical depth Conductor 80.00 16 9 cy High Early 115.00 115 Surface 2,581 9.625 580 sx ASIII, 340 sx Class G 2,616.00 2,515 RECEIVED Pedoration depth: measured F E B g O ZO 01 true vertical Alaska 0ii & Gas Cons. Commission Anchorage 20. Attachments Filing fee [] Property Plat [] BOP Sketch [] Diverter Sketch [] Drilling pmgramr~l Ddlling fluid program [] Time vs depth plot [] Refraction analysis [] Seabed report [] 20 AAC 25.050 requirements [] 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Questions? Call Steve McKeever265-682( Signed Title: Exploration/Cook Inlet Team Leader Date Paul Mazzolini Pr¢~ar~d bv .~t~v~ McK~ver Commission Use Onl} Permit Number.,7..(~/-~(:2:> -- I I ~//~,. APl number Approval date I See cover letter 5o- /O ~-' ~.'~ / -' Lb ! For other requirements Conditions of approval Samples required [] Yes [] No Mudlog required [] Yes [] No Hydrogen sulfide measures [] Yes [] No__., Directional survey required [] Yes [] No Required working pressure for BOPE [] 2M; [] 3M; '~L~ [] ~0U;[] [] Other: by order of Approved by Commissioner the commission Date ,,, Form 10-401 Rev. 12/1/85 · Submit in triplicate Well Plan Summary Palm #lA Sidetrack General Znformation, Drilling Fluid Program, Pressure Calculations, Drilling Area Risks & General Procedure Surface Location: (Global Coordinates) I 2574' FNL J North/n£s: 5~993,842.52 JTop of Productive Interval (Kuparuk C Sand): (Global Coordinates) J Northin£s: 1305 FEL I Eastings: [47S~954.~9 531' FNL J 1686' FEL I 5~ggs~8?S J Easting$: 148~849 Bottom Hole Location: [ 431' FNL (Global Coordinates) [ NorthinEs:[ ~ 995~ 972. 88 I AFE Number: [ AX2142 Sec 18, T12N, R8E UM Sec 17~ T12N~ R8E UM Estimated Start Date: 1446' FEL J Sec 17r T12Nr R8E UM I Eastin~Is: 15481~088. g6 I 12/21/01 114.8 I I Ri9: INab°rst9e I I Estimated Operatin9 Days: I.D: 19,eoo . I I VD=I S,gZ . I IRK.= Type of Well: I Exploration Formation Markers (all depths adjusted for Nabors 19E, and pad elevation) Measured Hole Angle True Vertical True Vertical Formation Tops Depth (RKB feet) (Degrees) Depth (RKB feet) Depth (SS feet) C50 3,843 32 3,794 3,735 040 (K-3) 4,321 48 4,159 4,100 Moraine 7,199 72 5,176 5,117 Top HRZ (K-2) 8,137 72 5,464 5,405 C20 (HRZ midpoint) 8,570 72 5,597 5,538 Base HRZ 8,711 72 5,640 5,581 K-1 9,099 72 5,759 5,700 Kuparuk C 9,327 72 5,829 5,770 LCU/Kuparuk A 9,408 72 5,854 5,795 Miluveach 9,490 72 5,879 5,820 TD 9,600 72 6,059 6,000 Casing/Tubing Program Hole/Csg Csg/Tbg Top Btm Size OD Wt/Ft Grade Conn. Length MD/TVD MD/TVD 12-1/4' OH 9-5/8' (see 36# 3-55 BTC 2,581' Surface 2,616' / 2,615' note below) 8-1/2" OH 7" (see note 26# 3-55 BTC 9,572' Surface 9,600' / 5,913' below) Notes: 9-5/8' Casing has already been set and cemented. 7" Casing, if run, may be set shallower, based on hole conditions. RECEIVED FEB g 0 2001 Alaska Oil & Gas Cons. Commission Anchorage Palm #lA Sidetrack Permit to Dr///Application Information & Procedure Page I of 3 Casing and Tubing Ratings Wt 85% of 85% of OD (ppf) Grade Range Conn. Collapse Collapse Burst Burst 7" 26 ]-55 3 BTC 4330 3680 4980 4,233 9-5/8" 36# ]-55 3 BTC 2,020 1,717 3,520 2,992 Logging/Formation Evaluation Program IOpen Hole I HWD (Directional / Pressure while Drilling)/LWD (Gamma Ray / Resistivity / Neutron I Density / Sonic), Mud Logging Samples Mud Program For Tnterval from Kickoff Point to K-3 Formation @ 4321' MD Density YP PV 10 s LSYP AP[ pH :[nterval (ppg) Gel Filtrate Initial 9.6 - 9.8 11-15 6-12 2-5 4-12 <6 9-9.5 Final 10.2 11-15 6-12 2-5 4-12 <6 9-9.5 For Interval from K-3 Formation @ 4321' MD to Morraine Formation @ 7200' MD Density YP PV 10 s LSYP AP:[ pH :Interval (ppg) Gel Filtrate Initial :[0.2 11-:[5 6-12 2-5 4-:[2 <6 9-9.5 Final :[0.5 11-15 :[0-20 4-7 4-12 <6 9-9.5 For Interval from Morraine Formation @ 7200' MD to Base of HRZ @ 8711' MD Density YP PV 10 s LSYP AP:[ pH :[nterval (ppg) Gel Filtrate Tnitial 10.5 18-25 10-20 4-7 4-8 <4 9-9.5 Final :[2.2 18-25 10-20 4-7 4-8 <4 9-9.5 For Tnterval from Base of HRZ @ 8711' MD to TD @ 9600' MD Density YP PV 10 s LSYP AP:[ pH :[nterval (ppg) Gel Filtrate Initial 12.2 18-25 10-20 4-7 4-8 <4 9-9.5 Final 12.2 18-25 10-20 4-7 4-8 <4 9-9.5 Reservoir Pressure and Well Control Reservoir pressures in the vicinity of the Palm :[A bottom hole location were obtained from the drilling and logging of the Palm #:[ well and are summarized below Formation TVD Pressure Pressure Gradient Pressure Gradient Formation (feet) (psi) (psi / ft) (EMW) Kuparuk C Sand 5830 3580 0.6:[ 11.8 ppg Based on this information the expected C-sand formation pressure will be 3580 psi (1:L.8 EMW). Assuming a 150 psi overbalance is required to safely drill and trip in this formation, and the expected formation pressure in the C sand (5,830' TVD) is a :[1.8 ppg EHW, then a required mud weight of :[2.2 ppg can be calculated as the mud weight needed to safely drill and trip in this formation. ([(:[:[.8*.052*5830)+:[50]/[0.052*5830]=::[2.2 ppg.) Consequently, a mud weight of 12.2 ppg will be used to drill the production zones, and the well will be closely monitored for flow and / or other indications of formation pressures in excess of this mud weight Maximum allowable surface pressure (HASP) while drilling the sidetrack hole is calculated using the formation integrity test obtained upon drilling out the existing 9-5/8" casing shoe. This value was 16.0 ppg EMW (0.83 psi/E) at 2635' TVD). Using this value and a gas gradient of 0.1:[ psi/it, formation breakdown could occur at a surface pressure of :[900 psi. RECEIVED FEB 0 2001 Alaska Oil & Gas Cons. Commission Anchorage Palm #lA Sidetrack Permit to Drill Application Information & Procedure Page 2 of_7 MASP = (2635 ft)(0.83- 0.11) t4ASP = 1900 psi Maximum Potential Surface Pressure (MPSP) while drilling the production hole is calculated assuming maximum formation pressure and a fully gas-filled (i.e. all mud evacuated) wellbore. Thus the MPSP is the maximum anticipated formation pressure less the product of the gas gradient and the TVD, or (3830 psi)-(.llpsi/ft * 5830 ft) = 3::[88 psi. Consequently the planned BOPE test pressure of 5,000 psi will be adequate. Drilling Area Risks Drilling risks and mitigation measures for the drilling of the Palm #lA sidetrack well are summarized on the included, postable "Palm #lA Drillinq Hazards Summary". Close Crossing and Offset Well Interception Risks There are no well bores, other than the plugged Palm #1 wellbore, with in 200 feet of the proposed well bore. Waste Drilling Fluids Disposal and Annular Pumping Activities As with the Palm #1 well, there will be no reserve pit for this well. Waste drilling mud will be hauled to a KRU Class !! disposal well. !f a production casing string is set in this well Phillips requests that Palm #:LA be permitted for annular disposal of fluids occurring as a result of drilling operations, per regulation 20 AAC 25.080. As in the past Phillips would submit a 10-403 Form to the Commission with the appropriate technical information. All cuttings generated will be either stored temporarily on site or hauled to the Prudhoe Bay Field for temporary storage and eventual processing for injection down an approved disposal well. if this well is tested, the produced fluids will either be hauled to Kuparuk for recycling or injection into an appropriate disposal well or the produced fluids will be reinjected into the Palm #lA wellbore. General Drilling Procedure Drilling 8-1/2" Hole 1. After setting cement kickoff plug in Palm #1 wellbore, wait on cement a minimum of 6 hours. Perform any required rig maintenance and test all BOP equipment to 5000 psi, in accordance with the procedures detailed in the PA! Drilling Policy. Record results. Notify AOGCC at least 24 hours prior to the BOP test. 2. !nstall wear ring in casing head. 3. Pick up rebuilt 8-1/2' bit, 6-3/4.' Sperry motor and remainder of directional BHA and R!H to top of cement kickoff plug. A 'Stripping' drill and a 'Well Kill' drill should be held with rig crews prior to drill out as per PA! Drilling 'Drill Expectations and Procedures' document Version 1.0. Document drills and record on morning report. Dress off plug to required kick off point and directionally drill to 8-1/2" hole TD (+/- 9600' MD / 6000'-FVD). Continue to emphasize ECD management and proper hole cleaning. TD may be modified based on geological results ° Mud weights should be elevated to and maintained at the weights specified in the mud program for each of the intervals specified. Keep the mud in good shape in order to maintain a thin wall cake and to minimize gel strengths and PV's for ECD control. Weight up slowly in 0.3 ppg increments or less. Trip slowly and carefully and break circulation gently in order to minimize surge and swab pressures. 5. At TD, condition the wellbore as required for open hole wireline logging runs, if required. 6. Continue to circulate and short trip as much as necessary until the Phillips Drilling Foreman is comfortable with hole conditions. Do not POOH without the prior consent of the Phillips Drilling Foreman on location. !f need be, POOH, lay down the "smart" BHA, and run back to bottom with a hole opener. 7. POOH for logging run, or to plugback open hole. 8. Plug and abandon well in accordance with the requirements of AOGCC. 9. Thoroughly clean location and block off access to Palm ice road. NOTE: An Application for Sundry Approval will be submitted at a later date for the plug back and abandonment of the Palm #lA well. .. RECEIVED FEB 2, 0 2001 Alaska Oil & Gas Cons. Commission Anchorage Palm #lA Sidetrack Permit to Dr/Il Application [nformation& Procedure Page 3 of 3 Palm #lA Drillin Hazards Summary (to be posted in Rig Floor Doghouse Prior to Spud) 12-1/4" Hole / 9-5/8" Casing Interval Event I Risk Level I I~litigation Strategy Conductor Broach Moderate Monitor cellar continuously during interval. Well Collision NA Nearest well is approximately 2.7 miles away. Gas Hydrates Moderate Monitor well at base of permafrost, increased mud weight, decreased mud viscosity, increased circulating times, controlled drilling rates, Iow mud temperatures, addition of 2.0 ppb of Driltreat (Lecithin) plus Y2% by volume Dril- N-Slide Running Sands and Low Maintain planned mud parameters, Gravels Increase mud weight, use weighted sweeps, run gravel isolation string. Abnormal Pressure in Low Diverter drills, increased mud weight. Offset Surface Formations wells (Colville #1 & Kalubik Creek #1) and 3G Pad wells indicate Iow probability of encountering abnormal pressures. Lost Circulation Low Reduced pump rates, mud rheology, lost circulation material, use of Iow density cement slurries 8-1/2" Hole / 7" Casing Interval Event Risk Level Mitigation Strategy Lost circulation Low Reduced pump rates, reduced trip speeds, real time equivalent circulating density (ECD) monitoring, mud rheology, lost circulation material Hole swabbing on trips Moderate Reduced trip speeds (especially thru the C80 interval @ 2760' MD), mud properties, proper hole filling, pumping out of hole, real time equivalent circulating density (ECD) monitoring, weighted sweeps. Abnormal Reservoir Moderate Well control drills, increased mud weight, Pressure contingencies for top set casing string. Hydrogen Sulfide gas Low H2S drills, detection systems, alarms, standard well control practices, mud scavengers RECEIVED FEB 2 0 ;~001 Alaska Oil & Gas Cons. Commission Anchorage Palm # la Drilling Hazards Summary. doc prepared by Steve McKeever 2/19/01 Page I of I Palm #lA Exploration Well, CemCADE* summary. Use 75 % excess. Drilled with 8 1/2" bit. 7 ", 26 # casing TMD 9600'. Top of Cement is @ 8326' MD ( 1000' above the West Sak top). Fluid Sequence: Pump 20 bbls CW100 Preflush, Drop Bottom Plug, Pump 20 bbls MudPUSH XL Spacer @ 11.0 ppg. Cement from TD to 8326' with GasBLOK @ 15.8 ppg. Tail Slurry Requirements: 15.8 ppg GasBLOK w/Class G + D53, D600, D135, DS00, D047, D065, per lab testing @ BHCT - 3.5 to 4.5 hour thickening time. Yield = 1.2 ft3/sx. (9600'-8326') x 0.1268 ft3/ft x 1.75 (75% excess) = Shoe Joints: (80') x 0.2148 ft3/ft = 282.7 ft3 + 17.2 ft3 = 299.9 ft3/1.2 ft3/sk = 282.7 ft3 17.2 ft3 299.9 ft3 249.9 sks - Round up to 260 sks Estimated BHST = 150 deg F CemCADE* Summary: Fluid sequence: Establish circulation using FW, 20 bbl CW100 Preflush, Drop Bottom Plug, 20 bbls 11.0 ppg MudPUSH XL Spacer, 260 sks (56 bbl) GasBLOK Tail. Drop Top Plug. Displacement is approximately 364 bbls. Circulation: Circulation and cementing at or less than 7 bpm is within the safe ECD to avoid breaking down the formation. Recommend dropping the rate to 5 bpm when lift pressure is observed and dropping the rate below 3 bpm for the last 20 bbls of displacement for bumping the plug as well as maintaining returns. Expected pressure to bump the plug is 900 psi. At 7 bpm, expect 25 minutes of u-tubing after dropping the top plug. Recommended Conditioned Mud Properties: 10.0 ppg or less, Pv = 15 or under, Ty = 15 or under. NOTE: If mud weight is over 10 ppg, the spacer/cement densities must be adjusted to allow for a minimum of 1.0 ppg differences between each subsequent fluid. Recommended Centralizers: Recommend 1 centralizer per joint from TD to 200' over TOC (approx. 37 centralizers). RECEIVED FEB 2 0 200 Alaska Oil & Gas Cons. Commission Anchorage 3000 4000 0~!t i 115' ----T ...... ~ --I 1000 ~Dril112-1/4" Hole i 2000~ 5OOO 6OOO 7OOO t T I 9-5/8" set @ 2616' 16.0 ppg FIT DRILLING TIME AND MUD WEIGHT CURVE Palm #1 --e- Depth .......... Mud Weight i ~ i I I I ...... T ...... -I ............... F ...... -f ....... I ....... F ....... .................................T ] ~'~.e~T~., .... I ....... I-' ...... ..... ~ W .... ~* '~~ ........ _ [ /, , , I I I i I I I I I -I- I I 12.4 12.2 12 11.8 11.6 11.4 Spud Well 0030 hrs 2/2/01 ', ~- ...... ~ ......] ...... ~ ............. ~- ....... 11.2 I I'- T ] ...... ] ................... I , , , , 11 ]' L ' ' ' '- Drill8-1/2" Hole , - , , T \ , , , .... ~--, ........ ~--- ~ ~-~ .....~ ....... ~ ......~ ......., .......~ ....... 10.8 ..... X-' ........ ~ - - - ~ ~ ....... I ....... ~ ...... ~ ....... ' ....... c ...... ......~~ ........ '~--- , ~ ' ' .~ ' I ' ' ~ ' ....... ,---~ .... ~--- ~-~---~ .............. ~ ......~ ......., .......~ ....... 10.4 , ~ , ~ , ~ ~ , , , ....... ~ ..... ~--~--- ~ ....... ~ .............. r ...... n ....... ~ ....... ~ ...... ....... ~ _ _~¢7% _ } ...... ~ .............. [ ......4 .......', ....... ~ ....... 10.2 ....... , ..... ~r~ ..... ~ ...... n .... ~ ......... r ...... ~ ....... , ....... ~ ...... , ~' , X , [ I , , , ' , ~ , ....... [---~---~-- %-- ~ ...... ~ ....... ~ ....... ~ ...... ~ ....... , ....... , ....... I ~ XI I I I I ~-~:~~ ; ~ X- ' / Tr,p , , , : I I 'l I ............ r ...... ~ ....... ,--- lD&ko~ --- ~.4 I i -~ ~ ...... ~ ...... ~ ...... ~ ....... I ....... I I I I 9.2 9 10 15 TD WELL 0700 hrs 2/15/01 TIME TO DRILL (DAYS) prepared by TJB 11/700 Phillips Exploration North Slope, Alaska Exploration 2001 Palm #lA (wp06) Proposal Data for Palm #lA WPO6 Vertical Origin: 24' Ice Ele+35* RKB Horizontal Origin: H Ref (Palm #1 SHL) Measurement Units: ft North Reference: True North Dogleg sevedty: Degrees per 100 feet Vertical Section Azimuth: 67.281° Vertical Section Description: H Ref (Palm #1 SHL) Vertical Section Origin: 0.00 N,O,O0 E Comment Measured Incl, Azlm. Vertical Northlngs Eastlngs Vertical Dogleg Depth Depth Section Rate Sidetrack at 2800' MD ... Build @ 5°/100' in 8-1/2" Ho]e 2800.00 3.445 267.799 2799.36 16.26 ,q 4~.62 E 38,57 End of Build ... Hold 72.13o inc & 67.40':. AZ 5034.49 72,128 67.218 4511.72 4(~1.27 N 1121.1gE 1213.,tg 3.37 Intersect Target Top @ 5829' TVD 9326.91 72.128 67.218 5829.(X) 204621 N 4887.75 E 5298.78 Driller's TD 0:, 9600' MD 9600.00 72]28 67.218 5912.81 2146.86 N 5127.39 E 5558.70 0.00 Single Well Target Data for Palm #1 Measurement Units: ft Target TVD Northings Eastings TVD Norlhlngs Eastlngs Name 2250 -- 2550 -- 2850 -- 3150 -- 3450 -- 3750 -- ~4050 - 4350 - 4650 - 4950 - 5250 - ii E 5550- 5850- 6150 - I I -900 -600 -300 ~ 9-5/8" Casing Pt (2616' MD) ... Drill 8-1/2" Hole to TD '-~Sidetrack off of Cmt plug at 2800' MD ... Build @ 5°/100' in 8-1/2" Hole ],200.00 Coordinate Point Type Current Well Properties Palm #1 Well: Horizontal Coordinates: Ref. Global Coordinates: Ref. H Ref (Palm #1 SHL): Ref. Geographical Coordinates: 5993842.52 N, 475954.69 E 0,00 N, 0.00 E 70° 23' 39.3813' N, 150° 11' 44.3266' W End of Build i.. Hold 72.13~ Inc & 67.40° AZ ~ ~ ~ /i W/306 6800.,~,,_7200.00 ('3 03 oD ~ rtl I I I I I I I I I I 300 600 900 1200 1500 1800 2100 2400 2700 3000 RKB Elevation: 59.00~t above Mean Sea Level 59.0Oft above V Ref (MSL) North Reference: True North Units: Feet sper mj-suq DRILLING SERVICES A Halliburton Company Target Shape .00 intersec! Target Top c¢ 5829' TVD ~- ~8~.00 "'. Dr'ller's 5' D ~'~ 9'~.~ @'9600' MD t'ah, IA g;P06 ..................... / ~ecta~tgle, Sides: 150.00 x 200.Ot)fi 5829.00 TVI), 2046.21 & 4,g,~7.75 E Taroet Base (M~luvoach) (¢ 5879' 'TVD 3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 Scale: 1em = 300ft Proposal Data for Palm #lA WPO6 vertical Origin: 24' Ice Ele+35' RKB Horizontal Origin: H Ref (Palm #1 SHL) Measurement Units: ft North Reference: True North Dogleg sevedty - Degrees per 100 feet Vertical SecUon ~.imuth:67.281 ° Vertical Section Description: H Ref (Palm #1 SHL) Vertical Section Origin:0.00 N,0.00 E Comment Measured Incl. Azim. Vertical Northings Easfings VerticalDogleg Depth Depth Section Rate Sidelrack at 28(X)' MD ... Build (b 5°/100. in 8-1/2" Hole 2800.00 3.445 267.799 2799.36 16.26 S 48.62 E 38.57 End of Build ... Hold 72.13° Inc & 67.40° AZ 5034.49 72.128 67.218 4511.72 464.27 N 1121.18 E 1213.49 3.37 Intersect Target Top @ 5829' TVD 9326.91 72.128 67.218 5829.00 2046.21 N 4887.75 E 5298.78 Driller's 'rD @ 9600' MD 9600.00 72.128 67.218 5912.81 2146.86 N 5127.39 E 5558.70 0.00 Single Well Target Data for Palm #1 Measurement Units: ft Coordinate Target Point TVD Northings Eastings TVD Northings Eastings Target Name Type Shape 1-~?~i~ i .~% W?(!6 5S29.C'(." 3M-6.21 .,",' 4887.75 I::5779.64 5'~')5873.C:~) '..-xi :I-8'..q8~).C~/ri i:' n-". r y ?oini ibt:-'i~&-'.y h~i--".-t A D 5829.C-'0 214~.05 N ~37.4.'.' Iz. 577'0.0057}~573.('g} N:~:'a¢7~9/d~d E 5-.<.29.{~3 214<53 N 49~7.4.'.- [{ 577:}.{85~"."5~)'73.{~} N 4B09~9.:3~) I?~ 58.'.'9::}~ i t}~-.':-.5-~ N 49,S837 l.-'. 577':).(~;-' 5%5773.,'}~} N4g0949.i3i) 5825~.{g~ 1944.05 N 4S?~S.¢8 E 577.'}.{}:{} 5~95773.0} N 180799.00 I~ / ....................... ,.., Phillips Exploration North Slope, Alaska Exploration 2001 Palm # lA (wp06) Current Well Properties Well: Horizontal Coordinates: Ref. Global Coordinates: Ref. H Ref (Palm #1 SHL): Ref. Geographical Coordinates: RKB Elevation: North Reference: Unils: Palm #1 5993842.52 N, 475954.69 E 0.00 N, 0.00 E 70° 23' 39.3813' N, 150° 11' 44.3266' W 59.0Oft above Mean Sea Level 59.0Oft above V Rel (MSL) True North Feet 2400 2100 800 500 1200 900 g 600 ii 1-- ~ 300 _ 0 -300 -300 480( t*alm iA ~Vt~fi6 Recttt,gle, .Sides: 150, O0 ;r 200, OOft 5829.00 'I'FI). 2046.21 3/, 48,¥7.75 E Driller's TD @ 9600' MD Target Base (Miluv~ach) ~' 587.0,, TVD Intersect Target Top (.'¢ 5829' TVD N 'End of Build ... Hold 72.13° Inc & 67.40° AZ Sidetrack off of Cmt plug at 2800' MD ,., Build @ 5°/100' in 8-1/2" Hole SHL (2574' FNL& 1305' FEL, Sec. i8 -T12N - R8B ' I I I I I I I I I 300 600 900 1200 1500 1800 2100 2400 2700 Reference is True North spenr /-sun, DRILLING SERVICES I I I I I I I I I 3000 3300 3600 3900 4200 4500 4800 5100 5400 A Halliburton Company Scale: 1em = 300ft Eastings Prepared by: Dave Egedahl Date/Time: 19 February, 2001 - 16:23 Phillips Exploration' ~ ~ Expl~ion '200~ Pal ~A Wp06 REPORT 19 February, 2001 Your Ref: ... per Steve McKeever w/ Phillip's (2-19-01) Surface Coordinates: 5993842.52 N, 475954.69 E (70° 23' 39.3813" N, 150° 11' 44.3266" W) Kelly Bushing: 59.0Oft above Mean Sea Level A Halliburton Company Proposal Reft pro9388 Sperry-Sun Drilling Services Proposal Report for Palm #1 Your Ref: ... per Steve McKeever w/ Phillip's (2-19-01) North Slope, Alaska Measured Depth (ft) Incl. Palm #1 Rig Azim. 0.00 0.000 0.000 100.00 0.000 0.000 200.00 1.045 117.994 300.00 1.268 108.706 400.00 1.442 114.624 500.00 0.930 116.519 600.00 1.282 102.435 700.00 1.319 118.464 800.00 1.506 117.232 900.00 ' 1.214 117.471 1000.00 1.276 112.794 1100.00 1.205 112.115 1200.00 1.210 105.024 1300.00 1.193 100.843 1400.00 1.000 94.388 1500.00 1.186 87.666 1600.00 1.268 87.346 1700.00 1.296 97.437 1800.00 1.478 99.301 1900.00 1.572 101.135 2000.00 1.478 99.146 2100.00 1.423 104.989 2200.00 1.225 110.964 2300.00 1.116 112.863 2400.00 0.799 119.250 Sub-Sea Vertical Local Coordinates Depth Depth Northings (ft) (ft) (ft) .%:i:.;~i:'~;~¢'' 41.00 100.00 ,.~,,:j~!~i]~i~;~:.,... '"~..,00~N? 140.99 199,99 .......................... ";~82 S 440~:. .:;~99.~? 3.19 S 540.9~;~90.90 3.78 S 640.88 '?~ 699.88 4.57 S 740.84 799.84 5.75 S 840.82 899.82 6.84 S Eastings ====================================== ....... ~':"O.00 E5993842.52 N 475954.69 E 0.00 E 5993842.52 0.97 E 5993841.90 2.86 E 5993841.10 5.08 E 5993840.29 N 475954.69 E N 475955.66 E N 475957.54 E N 475959.76 E 7.04 E 5993839.31 8.77 E 5993838.72 10.86 E 5993837.91 13.12 E 5993836.73 15.13 E 5993835.64 N 475961.72 E N 475963.45 E N 475965.53 E N 475967.79 E N 475969.80 E 940.79 999.79 7.72 S 1040.77 1099.77 8.60 S 1140.75 1199.75 9.25 S 1240.72 1299.72 9.72 S 1340.71 1399.71 10.00 S 17.15 E 5993834.74 19.14 E 5993833.86 21.08 E 5993833.21 23.22 E 5993832.73 25.08 E 5993832.44 N 475971.81E N 475973.80 E N 475975.74 E N 475977.88 E N 475979.74 E 1440.69 1499.69 10.00 S 1540.66 1599.66 9.88 S 1640.64 1699.64 9.92 S 1740.61 1799.61 10.35 S 1840.57 1899.57 10.79 S 26.87 E 5993832.43 29.17 E 5993832.54 31.29 E 5993832.50 33.69 E 5993832.06 36.33 E 5993831.61 N 475981.53 E N 475983.82 E N 475985.95 E N 475988.35 E N 475990.99 E 1940.54 1999.54 11.30 S 2040.51 2099.51 11.78 S 2140.48 2199.48 12.50 S 2240.46 2299.46 13.27 S 2340.44 2399.44 13.99 S 38.98 E 5993831.09 41.44 E 5993830.60 43.66 E 5993829.88 45.54 E 5993829.11 47.06 E 5993828.38 N 475993.63 E N 475996.10 E N 475998.31E N 476000.19 E N 476001.71E Dogleg Rate (°/100ft) 0.00 1.05 0.29 0.22 0.51 0.44 0.36 0.19 0.29 0.12 0.07 0.15 0.09 0.23 0.23 0.08 0.23 0.19 0.11 0.11 0.16 0.24 0.12 0.33 Phillips Exploration Exploration 2001 Vertical Section Comment 0.00 0.00 0.66 2.09 3,83 5.26 6.63 8.25 9.88 11.32 12.83 14.34 15.87 17.67 19.27 20.92 23.09 25.03 27.08 29.34 31.59 33.68 35.45 36.89 38.01 SHL (2574' FNL & 1305' FEL, Sec. 18 -T12N - R8E) 19 February, 2001 - 16:09 Page 2 of 9 DrillQuest 2.00.06 Sperry-Sun Drilling Services Proposal Report for Palm #1 Your Ref: ,,, per Steve McKeever w~ Phillip's (2-19-01) North Slope, Alaska Measured Depth (ft) Incl. Azim. 2500.00 0.889 * 113,843 2600.00 0.835 116.290 2616.00 0.833 115.465 Sub-Sea Depth (ft) Palm Vertical Local Coordinates Depth Northings (ft) (ft) 2440.43 2499.43 14.64 S 2540.42 2599.42 15.30 S 2556.42 2615.42 15.41S 2700.00 0.632 117.751 2640.41 2800.00 3.445 267.799 2740.36 #lA WP06 2900.00 1.199 344.307 2840.29 2899.29 3000.00 3.708 48.901 2940.20 2999.20 3100.00 6.987 57.838 3039.76 3098.76 3200.00 10.325 61.052 3138.60 3197.60 3300.00 13.681 62.704 3236.40 3295.40 3400.00 ' 17.043 63.714 3332.82 3391.82 3500.00 20.408 64.400 3427.51 3486.51 3600.00 23.775 64.898 3520.16 3579.16 3700.00 27.144 65.279 3610.43 3669.43 3800.00 30.513 65.581 3698.03 3757.03 3843.24 31.970 65.694 3735.00 3794.00 3900.00 33.883 65.828 3782.64 3841.64 4000.00 37.253 66.036 3863.97 3922.97 4100.00 40.624 66.214 3941.74 4000.74 4200.00 43.994 66.368 4015.68 4074.68 Global C~rdinates Eastings N ort h i n~ ~!!i:!~.~i~ Eastings (fi) ............ ~, .......... ~'~iI .- ~;7~:, ~$093827.06 N 476004.35 E 49.92~::~;:~;:~f3{~93826.95 N 476004.56 E :,.¢ .... "--":;; ...... ......... 50.93 E5993826.47 N 476005.57 E 48.62 E 5993826.10 N 476003.26 E 15.37 S 12.24 S 6.87 S 0.71 N 10.47 N 45.34 E 5993827.00 N 475999.98 E 47.49 E 5993830.13 N 476002.14 E 55.08 E 5993835.47 N 476009.75 E 68.07 E 5993843.01 N 476022.77 E 86.43 E 5993852.71 N 476041.15 E 22.39 N 36.41N 52.50 N 7O.6O N 90.64 N 110.08 E 5993864.55 N 476064.85 E 138.95 E 5993878.49 N 476093.76 E 172.94 E 5993894.47 N 476127.80 E 211.93 E 5993912.44 N 476166.84 E 255.78 E 5993932.34 N 476210.76 E 99.89 N 112.55 N 136.27 N 161.70 N 188.76 N 276.21 E 5993941.52 N 476231.22 E 304.34 E 5993954.10 N 476259.39 E 357.44 E 5993977.64 N 476312.57 E 414.90 E 5994002.88 N 476370.11 E 476.53 E 5994029.75 N 476431.82 E Dogleg Rate (°/100ft) 0.12 0.07 0.08 0,24 4.00 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 Phillips Exploration Exploration 2001 Vertical Section Comment 38.97 39.94 40.10 40.85 38.57 9-5/8" Casing Pt (2616' MD)... Drill 8-1/2" Hole to TD 9 5/8" Casing Sidetrack off of Cmt plug at 2800' MD ... Build @ 5°/100' in 8-1/2" Hole 35.88 39.08 48.15 63.06 83.77 110.19 142.24 179.80 222.75 270.94 293.35 324.19 382.33 445.16 512.45 C50 19 February, 2001 - 16:09 Page 3 of 9 DrillQuest 2,00.06 Sperry-Sun Drilling Services Proposal Report for Palm #1 Your Ref: ... per Steve McKeever w~ Phillip'$ (2-19-01) North Slope, Alaska Measured Depth (ft) Incl. Azim. 4300.00 47.365 66.505 4321.50 48.090 66.533 4400.00 50.737 66.628 4500.00 54.108 66.740 4600.00 57.479 66.843 4700.00 60.851 66.938 4800.00 64.222 67.027 4900.00 67.594 67.111 5000.00 70.965 67.191 5034.49 72.128 67.218 5100.00 72.128 67.218 5200.00 72.128 67.218 5300.00 72.128 67.218 5400.00 72.128 67.218 5500.00 72.128 67.218 5600.00 72.128 5700.00 72.128 5800.00 72.128 5900.00 72.128 6000.00 72.128 6100.00 72.128 6200.00 72.128 6300.00 ' 72.128 6400.00 72.128 6500.00 72.128 67.218 67.218 67.218 67.218 67.218 67.218 67.218 67.218 67.218 67.218 Sub-Sea Vertical Local Coordinates Depth Depth Northings (ft) (ft) (ft) 4085.54 4144.54 217.35 N 4100.00 4159.00 223.69 N 4151.07 4210.07 247.38 N 4212.04 4271.04 27.E},~75 N 4268.25 4327,25 ..~-~'~!:i~ I'~N Giob.p!. C~.rdinates N o rt hi n:'~:~ii~::.'!ii~ili Eastings Eastings (ft) ~i (ft) .~.~.~!!i;ili,~, (ft) ....... ~..542.10~?:i~:i~:~;~94058.13 N ?:~476497.48 E .~:j~?'~':~556':69:.:.~ .... ~5994064.42 N 476512.10 E ~ 611~ :E~:~;;~?~6994087.94 N 476566.87 E ~'~:. 68~ E 5994119.06 N 476639.74 E ~:~:~;~:'6 E 5994151.40 N 476715.85 E 4319.50 4378.50 .................... ?~5.0'3~;~,~¢/~:!~;.. 839.12 E 5994184.85 N 476794.92 E 4365.61 4424.61 .:~'~:':~'~.~'~!~:~'~i~.'::~';~ 3~,72~N~ ..... 920.78 E 5994219.27 N 476876.68 E ~:.~ ~::~:~'.'~ ~.':~. 4406.43 ~ ~:~-.%~.~;?:::-~:~¥~:.~41:~5~8 N 1004.84 E 5994254.56 N 476960.86 E 4441.8~;~?~45~'0 ~'~?~..~:~?~51.59 N 1091.02 E 5994290.60 N 477047.16 E 44~ .......... ~:~i'~2 ~:~;~;?~;":'~" 464.27 N 1121.18 E 5994303.18 N 477077.36 E 4472.82~'~531.82 488.41 N 1178.67 E 5994327,14 N 477134.92 E 4503.51 '~ 4562.51 525.26 N 1266.42 E 5994363.71 N 477222.79 E 4534.20 4593.20 562.12 N 1354.16 E 5994400.28 N 477310.66 E 4564.89 4623.89 598.97 N 1~1.91 E 5994436.85 N 477398.52 E 4595.58 4654,58 635.83 N 1529.66 E 5994473.42 N 477486.39 E 4626.27 4685.27 672.68 N 1617.41E 5994510.00 N 477574.26 E 4656.95 4715.95 709.54 N 1705.16 E 5994546.57 N 477662.13 E 4687.64 4746.64 746.39 N 1792.91E 5994583.14 N 477749.99 E 4718.33 4777.33 783.25 N 1880.66 E 5994619.71N 477837.86 E 4749.02 4808.02 820.10 N 1968.41E 5994656.28 N 477925.73 E 4779,71 4838.71 856.95 N 2056.16 E 5994692.86 N 478013.60 E 4810.40 4869.40 893.81 N 2143.91 E 5994729.43 N 478101.46 E 4841.09 4900,09 930.66 N 2231.66 E 5994766.00 N 478189.33 E 4871.77 4930.77 967.52 N 2319.41E 5994802,57 N 478277,20 E 4902.46 4961.46 1004.37 N 2407.16 E 5994839.14 N 478365.07 E Dogleg Rate (°/100ft) 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 3.37 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0,00 0.00 Phillips Exploration Exploration 2001 Vertical Section Comment 583,98 599.89 659.49 738.73 821.42 9O7.27 995.98 1087.26 1180.78 1213.49 1275.84 1371 .O2 1466.19 1561.37 1656.54 1751.72 1846.89 1942.07 2037.24 2132.41 2227.59 2322.76 2417.94 2513.11 2608.29 C40 (K3) End of Build ... Hold 72.13° Inc & 67.40° AZ 19 February, 2001 - 16:09 Page 4 of 9 DrillQuest 2.00.06 Sperry-Sun Drilling Services Proposal Report for Palm #1 Your Ref: ... per Steve McKeever w~ Phillip's (2-19-01) North Slope, Alaska Measured Depth (ft) Incl. Azim. Sub-Sea Vertical Depth Depth (ft) (ft) Local Coordinates Northings (ft) 6600.00 72.128 67.218 4933.15 4992.15 1041.23 N 6700.00 72.128 67.218 4963.84 5022.84 1078.08 N 6800.00 72.128 67.218 4994.53 5053.53 1114.94 N 6900.00 72.128 67.218 5025.22 5084.22 115..~,~79 N 7000.00 72.128 67.218 5055.91 5114.91 .... 7100.00'72.128 67.218 5086.59 5145.59 7199.08 72.128 67.218 5117.00 5176.00 :~ 7200.00 72.128 67.218 5117.28 ....... 5 ~ ~i%~!~!¢:~:'~ii!ii:i~2 ~2~ 5 N 7300.00 72.128 67.218 5147.9~';~i~!i?~,520/~97 ~ii!i~.:~.~:ili?~$299.21 N 7400.00 72.128 67.218 7500.00 72.128 67.218 7600.00 72.128 67.218 7700.00 72.128 67.218 7800.00 72.128 67.218 7900.00 72.128 67.218 8000.00 72.128 67.218 8100.00 72.128 67.218 8137.54 72.128 67.218 8200.00 72.128 67.218 8300.00 72.128 67.218 517~ ~'!~ii~23~66 ':<~'~ .... 1336.06 N 5209.3~:~ .......... ~:.~68.35 1372.92 N 5240.0¢~:::~;~?75299.04 1409.77 N 5270.73 ~ 5329.73 1446.63 N 5301.41 5360.41 1483.48 N 5332.10 5391.10 1520.33 N 8400.00 72.128 67.218 8500.00 72.128 67.218 8570.93 72.128 67.218 8600.00 72.128 67.218 8700.00 72.128 67.218 5362.79 5421.79 1557.19 N 5393.48 5452.48 1594.04 N 5405.00 5464.00 1607.88 N 5424.17 5483.17 1630.90 N 5454.86 5513.86 1667.75 N 8711.04 72.128 8800.00 72.128 8900.00 72.128 9000.00 - 72.128 9098.81 72.128 Eastings (ft) '~i. (ft) ......... ~.~2~94.91~ii;'~;~'~!~!~94875.72 . ¢i:1~i!i~'~;';2'B8'2': 6 ~E ... ;i5994912.29 .::~ ,: · ~-:::~s:.: ....... '~-.~(~'~,~. 2758 ~6 E 5994985.43 ~(i~90 E 5995022.00 Global C~.rdinates Northin~%~ }:!ii:i~ Eastings N '~;?7478452.93 E N 478540.80 E N 478628.67 E N 478716.54 E N 478804.4O E 2933.65 E 5995058.58 N 478892.27 E 3020.60 E 5995094.81 N 478979.33 E 3021.40 E 5995095.15 N 478980.14 E 3109.15 E 5995131.72 N 479068.01E 3196.90 E 5995168.29 N 479155.87 E 3284.65 E 5995204.86 N 479243.74 E 3372.40 E 5995241.44 N 479331.61 E 3460.15 E 5995278.01N 479419.48 E 3547.90 E 5995314.58 N 479507.34 E 3635.65 E 5995351.15 N 479595.21 E 5485.55 5544.55 1704.61N 5516.23 5575.23 1741.46 N 5538.00 5597.00 1767.60 N 5546.92 5605.92 1778.32 N 5577.61 5636.61 1815.17 N 3723.40 E 5995387.72 N 479683.08 E 3811.15 E 5995424.30 N 479770.95 E 3844.09 E 5995438.02 N 479803.93 E 3898.90 E 5995460.87 N 479858.81 E 3986.65 E 5995497.44 N 479946.68 E 67.218 5581.00 5640.00 1819.24 N 67.218 5608.30 5667.30 1852.02 N 67.218 5638.99 5697.99 1888.88 N 67.218 5669.68 5728.68 1925.73 N 67.218 5700.00 5759.00 1962.15 N 4074.40 E 5995534.01 N 480034.55 E 4162.15 E 5995570.58 N 480122.42 E 4224.38 E 5995596.52 N 480184.74 E 4249.90 E 5995607.16 N 480210.28 E 4337.65 E 5995643.73 N 480298.15 E 4347.34 E 5995647.77 N 480307.86 E 4425.39 E 5995680.30 N 480386.02 E 4513.14 E 5995716.87 N 480473.89 E 4600.89 E 5995753.44 N 480561.75 E 4687.60 E 5995789.58 N 480648.58 E Dogleg Rate (o/10oft) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Phillips Exploration Exploration 2001 Vertical Section Comment 2703.46 2798.64 2893.81 2988.99 3084.16 3179.33 3273.63 Moraine 3274.51 3369.68 3464.86 3560,03 3655.21 3750.38 3845.56 3940.73 4035.91 4131.08 4166.81 Top HRZ 4226.25 4321.43 4416.60 4511.78 4579.28 4606.95 4702.13 C20 (HRZ Midpoint) Base H RZ K-1 4712.64 4797.30 4892.48 4987.65 5081.69 19 February, 2001 - 16:09 Page 5 of 9 DrillQuest 2.00.06 Sperry-Sun Drilling Services Proposal Report for Palm #1 Your Ref: ... per Steve McKeever w~ Phillip's (2-19-01) North Slope, Alaska Measured Sub-Sea Vertical Local Coordinates Depth Incl. Azim. Depth Depth Northings Eastings (ft) (fl) (ft) (ft) (ft) 9100,00 72.128 67.218 5700,37 5759.37 1962,59 N ....... .~8.8,64 E 9200,00 72,128 67,218 5731.05 5790,05 1999,44 N ~i?~.~?~;39~ :.... E 9300.00 72.128 67.218 5761.74 5820,74 2036,30 N i;!~;i!i. 4864~.:~ E 9326,91 72,128 67,218 5770,00 5829,00 2046~21 N ~ii::iiilii~.~4887~ E 9400,00 72,128 67,218 5792.43 5851 ,~ ?:.~.~?~2073715 N 4951,89 E 9408,37 72,128 67,218 57~,00 5854,~p.~.:,. '~:'~:~?? 2076.24 N 4959,24 E 9489.83 72.128 67.218 5820,00 5879.~ 2106,26 N 5030.72 E Glob.~! C~rdinates Nort hi ng~i;iii:~ ..~?: Eastings 5995790.02 N '? 480649.62 E 5995826.59 N 480737.49 E 5995863.16 N 480825.36 E 5995873.00 N 480849.00 E 5995899,73 N 480913,22 E 5995902,79 N 480920,58 E 5995932.59 N 480992.16 E 9500,00 72,128 67,218 5823,12 5882,12 2110,01 N 5039,64 E 5995936.30 N 481001,09 E 9600,00 72,128 67,218 5853,81 5912,81 2146.86 N 5127,39 E 5995972.88 N 481088,96 E All data is in feet unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to 24' Ice Ele+35' RKB. Northings and Eastings are relative to H Ref (Palm #1 SHL). Magnetic Declination at Surface is 25.956° (15-Feb-01) The Dogleg Severity is in Degrees per 100 feet. Vertical Section is from H Ref (Palm #1 SHL) and calculated along an Azimuth of 67.281° (True). Based upon Minimum Curvature type calculations, at a Measured Depth of 9600.00ft., The Bottom Hole Displacement is 5558.70ft., in the Direction of 67.281° (True). Dogleg Rate (°/100ft) o,oo o,oo o,oo o,oo o,00 o,oo o,oo o,oo o.oo Phillips Exploration Exploration 2001 Vertical Section Comment 5082,83 5178,00 5273,18 5298,78 5368,35 5376.32 5453.85 5463,52 5558,70 Intersect Target Top @ 5829' TVD Kup C (Target Top) Target - Palm lA WP06, Current Target LCU/Kup A Target Base(Miluveach) @ 5879'TVD Miluveach Driller's TD @ 9600' MD 19 February, 2001 - 16:09 Page 6 of 9 DrillQuest 2.00.06 Sperry-Sun Drilling Services Proposal Report for Palm #1 Your Reft ... per Steve McKeever w~ Phillip's (2-19-01) North Slope, Alaska Comments Measured Depth TVD (ft) (ft) Station Coordinates Northings Eastings (ft) (ft) 0.00 0.00 2616.00 2615.42 2800.00 2799.36 5034.49 4511.72 9326.91 5829.00 9489.83 5879.00 9600.00 5912.81 Formation Tops Measured Vertical Depth Depth (ft) (ft) 3843.24 3794.00 4321.50 4159.00 7199.08 5176.00 8137.54 5464.00 8570.93 5597.00 8711.04 5640.00 9098.81 5759.00 9326.91 5829.00 9408.37 5854.00 9489.83 5879.00 ......... ~ .............. 0.00 N 0.00 E (;~,~;~74' FNE~'~:'~:':~:'~O5' FEE, S~. 18-T12N -R8E) 15.41 S 49.92 E ~?;~/8~}~gsing Pt (2616' MD)... Drill 8-1/2" Hole to TD 1~.2~ 8 48.~2~:¢~ '~tr~ of Cmt plu~ m 2800' MD ... Buil0 4~4.27 ~ 112t~,~:~:~-:~;:.:::~:.~. fi~f Budd ... Hold 72.~ Inc & ~7.40 ~Z 204~.21 N~..~::~:~::~%~. ~'7~¢':' ~:~¢~lnt~m~t l at, et lop ~ 582~' ~D 210~.2~;~:~:~ '~0~;72 E lar~et Base (Miluveach) ~ 587~' ~D Sub-Sea Depth Northings Eastings Dip Dip Dir, Formation Name (ft) (ft) (ft) Deg. Deg. 3735.00 99.89 N 276.21 E 0.000 359.816 C50 4100.00 223.69 N 556.69 E 0.000 359.816 C40 (K3) 5117.00 1262.01 N 3020.60 E 0.000 359.816 Moraine 5405.00 1607.88 N 3844.09 E 0.000 359.816 Top HRZ (K2) 5538.00 1767.60 N 4224.38 E 0.000 359.816 C20 (HRZ Midpoint) 5581,00 1819.24 N 4347.34 E 0,000 359,816 Base HRZ 5700.00 1962.15 N 4687.60 E 0.000 359.816 K-1 5770.00 2046.21N 4887.75 E 0.000 359.816 Kup C (Targ~Top) 5795.00 2076.24 N 4959.24 E 0,000 359.816 LCU/KupA 5820.00 2106.26 N 5030.72 E 0.000 359.816 Miluveach Phillips Exploration Exploration 2001 19 February, 2001 - 16:09 Page 7 of 9 DrillQuest 2.00.06 Sperry-Sun Drilling Services Proposal Report for Palm #1 Your Ref: ... per Steve McKeever w/ Phillip's (2-19-01) North Slope, Alaska Casing details From To Measured Vertical Measured Vertical Depth Depth Depth Depth (ft) (ft) (ft) (ft) <Surface> <Surface> 2616.00 2615.42 Casing Detail Targets associated with this wellpath~i~!i ~?.~i~i?!?~ Tar g et '~'~.~?? ..... Name Target Entry Coordinates TVD Northings Eastings (ft) (ft) (ft) Palm lA WP06 Mean Sea Level/Global Coordinates: Geographical Coordinates: 5829.00 5770.00 2046.21 N 4887.75 E 5995873.00 N 480849.00 E 70° 23'59.4917"N 150° 09'21.1233"W l'rl © Targ~ Boundaw Point#1 5829.00 2146.05 N 4837.43 E #2 5829.00 2146.53 N 4987.43 E #3 5829.00 1946.54 N 4988.07 E #4 5829.00 1946.05 N 4838.08 E Mean Sea Level/Global Coordinates #1 #2 #3 #4 5770.00 5995973.00 N 480799.00 E 5770.00 5995973.00 N 480949.00 E 5770.00 5995773.00 N 480949.00 E 5770.00 5995773.00 N 480799.00 E Phillips Exploration Exploration 2001 Target Target Shape Type Polygon Current Target 19 February, 2001 - 16:09 Page 8 of 9 DrillQuest 2.00.06 Sperry-Sun Drilling Services Proposal Report for Palm #1 Your Ref: ... per Steve McKeever w/ Phillip's (2-19-01) North Slope, Alaska Target Name Targets associated with this wellpath (Continued) #2 #3 #4 Target Eintry Coordinates ~ ~:orthings Eastings (ft) (ft) 70° 24' 00.4740" N 70° 24' 00.4778" N 70° 23' 58.5106" N 70° 23' 58.5068" N 150° 09' 22.5958" W 150° 09' 18.2010" W 150° 09' 18.1860" W 150° 09' 22.5807" W Phillips Exploration Exploration 2001 Target Target Shape Type 19 February, 2001 - 16:09 Page 9 of 9 DrillQuest 2.00.06 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 Fax: (907) 265-6224 February 20, 2001 Commissioner Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 RECEIVED FEB g 0 7_001 ^laska Oil & Gas Cons. Commission Anchorage Subject: Application for Permit to Drill, Palm #lA (Sidetrack from Palm #1 wellbore) Dear Commissioner: Phillips Alaska, Inc. hereby applies for a Permit to Drill a sidetrack from the previously permitted (Permit #201-005) Palm #1 well bore, which is located approximately 4 miles west of the Drill Site 3G in the Kuparuk River Unit. The department is requested to keep confidential the enclosed information due to the exploratory nature of this well. The application supplied to the Commission for the Palm #1 well included information required by 20 ACC 25.005 (c), and is therefore not included again in this package. The drilling of the Palm #1 well has provided new information for use in the drilling of this well. This information includes knowledge of the mud weights required to safely drill and trip in the target formations. Those mud weights will be used to drill Palm #lA sidetrack, and are summarized in the Mud Program portion of the Permit Information Section of this application package. As has been reported to the Commission, Palm #1 was found to have higher than expected formation pressures. These pressures are thought to be the result of recent water injection into the same formation at Kuparuk wells on 3G pad, 4 miles to the east. The pressure is thought to have reached the formation at the Palm location through a connecting formation conduit so thin as to be near the resolution of the seismic tools used to map the area. Additionally, intervening faults between 3G pad and the Palm location were thought to provide barriers to the pressure transmission. However, this pressure is not expected to pose any significant hazard to the drilling of the Palm #lA sidetrack given the proven, .. integrity (16.0 ppg equivalent mud weight) of the formation at the 9-5/8" casing' shoe, and the fact that the formation pressure is now known and the mud will be weighted up accordingly prior to penetrating the Kuparuk C sand. As with the Palm #1 well, there will be no reserve pit for this well. Waste drilling mud will be hauled to a KRU Class II disposal well. If a production casing string As with the Palm #1 w~,~, there will be no reserve pit for this we,. Waste drilling mud will be hauled to a KRU Class II disposal well. If a production casing string is set in this well Phillips requests that Palm #1 be permitted for annular disposal of fluids occurring as a result of drilling operations, per regulation 20 AAC 25.080. As in the past Phillips would submit a 10-403 Form to the Commission with the appropriate technical information. All cuttings generated will be either stored temporarily on site or hauled to the Prudhoe Bay Field for temporary storage and eventual processing for injection down an approved disposal well. If this well is tested, the produced fluids will either be hauled to Kuparuk for recycling or injection into an appropriate disposal well or the produced fluids will be reinjected into the Palm #1 wellbore. Please note that Phillips does not anticipate the presence of H2s in the formations to be encountered in this well. However, there will be H2S monitoring equipment operating, as is the usual case while drilling wells in and near the Kuparuk River Field. If you have any questions regarding this matter, please contact me at 265-4603 or Steve McKeever at 265-6826. Sincerely, Paul Mazzolini Exploration Drilling Team Leader PAl Drilling PM/SMcK RECEIVED FEB 0 ZOO1 A~aska Oi~ & Gas Cons. Corr~mission Anchorage · "z' ' ' · ' · ','" 'i"-" · .. American Express® Cash Advance Draft 117 DATE ~.~-~.~/~cJ&F.~y~)/ 82-4o, 1021 PAY TO THE . ~ Issued by Intesrated Payment System, Inc. En~lewood, Colorado Payable at Norwest Bank of Grand Junction - Downtown, --Grand Junction, Colorado PERIOD ENDING ~1~0 J~,, L~ t ~ ': ~,O ;~ ~,OO hOD': :~ 5 NOT VALID FOR AMOUNT OVER $1000 '"O ~ ? 5000 5 ~"'O ~ ~ ? WELL PERMIT CHECKLIST FIELD & POOL ADMINISTRATION A~7'~ DATE ~ 2~.~! COMPANY 7/"/L.////,,~._~ WELL NAME ~/'/'YJ /'/~ exp ~/"dev . / . . (~f, PROGRAM: INIT CLASS ~/~'X'/~ (?~)'/--~'r'- ,p/c.) GEO.,..~,L AREA ENGINEERING 1. Permit fee attached ....................... 2. Lease number appropriate ................... 3. Unique well name and number .................. 4. Well located in a defined pool .................. 5. Well located proper distance from drilling unit boundary .... 6. Well located proper distance from other wells .......... 7. Sufficient acreage available, in ddlling unit ............ 8. If deviated, is wellbore plat included ............... 9. Operator only affected party ................... 10. Operator has appropriate bond in force ............. 11. Permit can be issued without conservation order ........ 12. Permit can.be issued without administrative approval ...... 13. Can permit be approved before 15-day wait ........... 14. Conductor string provided ................... 15. Surface casing protects all known USDWs ........... 16. CMT vol adequate to circulate on conductor & surf csg ..... 17. CMT vol adequate to tie-in long string to surf csg ........ 18. CMT will cover all known productive horizons .......... 19. Casing designs adequate for C, T, B & permafrost ....... 20. Adequate tankage or reserve pit ................. 21 .* If a re-drill, has a 10-403 for abandonment been approved... 22. Adequate wellbore separation proposed ............. 23. If diverter required, does it meet regulations .......... 24. Drilling .fluid program schematic & equip list adequate ..... 25. BOPEs, do they meet regulation ................ 26. BOPE press rating appropriate; test to ..~.~c~ psig. 27. Choke manifold complies w/APl RP-53 (May 84) ........ 28. Work will occur without operation shutdown ........... 29. Is presence of H2S gas probable ................. __ redril J serv. wellbore seg __ann. disposal para req UNIT# ."t,'/~ ON/OFF SHORE GEOLOGY 30. Permit can be issued WIG hydrogen sulfide measures ..... Y(~ ,, / ' / ,~ / / / /_ ' / /.//. ~ 31. Data presented on potential ove~ressure zones ....... ~N II 34. Contact name/phone forweekly progress repods JJ ANNULAR DISPOSAL35. With proper cementing records, this plan . ~-~& JJ (A) will contain waste in a suitable receiving zone; ....... Y N APPR DATE (B) will not contaminate freshwater; or cause drilling waste... Y N to sudace; (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recove~ Eom a Y N pool; and (E) will not circumvent 20 ~C 25.252 or 20 ~C 25.412. Y N GEOLOGY: ENGINEERING: UIC/Annular COMMISSION: Commentsllnstructions: c:\msoffice\wordian\diana\checklist (rev. 11/01//00) PHILLIPS PHILLIPS Alaska, Inc. PALM #lA Section ~8 TI2N-RaE, UM North Slope Borough, Alaska March 4, 2001 Brian O'Fallon, Sr. Logging Geologist Bob Nichol, Logging Geologist EPOCH TABLE OF CONTENTS PHILLIPS Phillips Alaska, Inc. Palm #fA North Slope Borough TABLE OF CONTENTS .................................................................................................. 2 WELL RESUME . 3 ~~~~~.·~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~u~~~~~~~~~~~~·~~~~~~~~~~~~~~~~~~~~~~~~~ Inllnnlllllllllnllllnllllllln FORMATION SUM, IVL~RY ................................................................................................ 4 RIG ACTIVITIES 27 a .·.mu mumm·ua··muumuu· uuu·· ·.mum · ~ m.mlU·UlUU.mmlm.mmunnll.mmllllllllllnllll··llalmm el· · Il I uumllmUlllm ·ill·la mnuu·nn.m MUD RECORD. ............................................................................................................. 29 SURVEY RECORD ..................... 30 uumllui man·mum · mum· · u··lmUll·n.m·lmnlm·mu·m·· · mu·mnm·uumu···m·muuuml·llml·· m n m·nnmu DAYS VS DEPTH 35 · · ·uu.u· ..··~u·a··u.muu. · · · u.m.mwmnmm·l·mnmnlm.mnu·ulnu·· mill n.mnmml.mlmuuumu·nmnumunnu.mmnml· · ii nm,mill umnlnu·nnnl EPOCH 2 Operator Well Name: Location: Coordinates: Elevation: County: State: APl Index: Spud Date: Contractor: Foremen: Rig: Logging Unit: Geologists: Co. Geologist: Log Interval: Dates: Mud Types: Casing Data: Hole Size: ~ PHILLIPS Alaska, Inc. Palm #lA WELL RESUME Phillips Alaska, Inc. Palm #lA North Slope, AK Sec 18, 12N, 8E, UM 2574' FNL, 1305' FEL KB: 60.38' AMSL North Slope Borough Alaska 500103-20361-00 2/23/2001 (Sidetrack date) Nabors Alaska Drilling Bobby Morrison, Mike Whiteley #19E - Land Built In Brian O'Fallon, Bob Nichol Rick Levinson, Jim Sallee 2800" to 9318' 2/23/2001 to 3141012001 LSND to 9318'. 16" at 115', 9 5/8" at 2616' 8 1/2" to 9318' [:1 EPOCH 3 ~ PHILLIPS Alaska, Inc. Palm #lA FORMATION SUMMARY C-80 2770' SAND = medium gray; occasionally clear, medium gray, common black; grain size predominantly very fine with occasionally fine quartz grains; sub angular to sub rounded; moderately sorted; predominantly quartz with scattered igneous and meta lithics. 2820' Claystone / Mudstone = light to medium brownish gray; thick, homogeneous; adhesive; poorly indurated; moderately smooth to abrasive occasionally silty; common carbonaceous material disseminated; commonly dull/earthy; disseminated microsparkles; non-reactive with dilute hydrochloric acid; easily hydrated; quick milky fluorescence noted; scattered bright light yellow mineral fluorescence; 2865' Siltstone = light gray to medium gray brown; soft to moderately firm; mushy with occasionally poorly indurated cuttings; gritty, abrasive texture; appears to grade to and intercalate claystone/mudstone; common carbonaceous material; scattered bright light yellow mineral fluorescence blebs probably from contamination from original hole. Note - Horizons of <cm wide siltstone/mudstone are capped by <mm thin layers of dolomitized/silicified, hard rock material-reddish-brown; weak-moderately reactive with dilute hydrochloric acid (seen in 2930' sample)- poor porosity/permeability possible oxidized horizon. Fractures preferable along weak shaley cleavages. 2945' Ash fall Tuff = light gray, pi yellowish brown; very soft- soft; smooth to slight grainy texture; occasionally calcareous; commonly appears waxy; scattered gray ashy streaks; moderately bright yellow mineral fluorescence - no visible oil. 3040' Siitstone = light gray to medium gray brown; soft to moderately firm; mushy with occasionally poorly indurated cuttings; gritty, abrasive texture; appears to grade to and intercalate with claystone/mudstone; common carbonaceous material; scattered bright light yellow mineral fluorescence blebs probably from contamination from original hole. 3125' Ash fall Tuff = light gray, pi yellowish brown; very soft- soft; smooth to slight grainy texture; occasionally calcareous; commonly appears waxy; scattered gray ashy streaks; moderately bright yellow mineral fluorescence - no visible oil. 3185' EPOCH 4 ~ PHILLIPS Alaska, Inc. Palm #lA Siltstone = light gray to medium gray brown; soft to moderately firm; mushy with occasionally poorly indurated cuttings; gritty, abrasive texture; appears to grade to and intercalate claystone/mudstone; common carbonaceous material; scattered bright light yellow mineral fluorescence blebs probably from contamination from original hole. Rare dolomitized/silicified, hard reddish-brown horizons are weak-moderately reactive with dilute hydrochloric acid. Poor porosity/permeability possible oxidized hodzon. Fractures preferably along weak shaley cleavages. 3250' Claystone / Mudstone = grayish red/brownish gray; thick, homogeneous; adhesive; moderately smooth to abrasive; occasionally well indurated; occasionally silty; common carbonaceous material disseminated; commonly dull/earthy; disseminated microsparkles; rarely reactive with dilute hydrochloric acid; easily hydrated; scattered dark gray/black igneous pebbles randomly; weak milky fluorescence noted; scattered bright light yellow mineral fluorescence; ash fall tuff = light gray, pale yellowish brown; very soft- soft; smooth to slight grainy texture; occasionally calcareous; commonly appears waxy; scattered gray ashy streaks; dull yellow mineral fluorescence - no visible oil 3330' Claystone = medium gray; moderately soft; sub blocky to amorphous; easily hydrated; smooth to silty to slight grainy texture; dull earthy to slightly sparkly texture commonly disseminated dark grains possibly carbonaceous; common transparent silt size grains; some grading to siltstone; non to very slight calcareous. 3420' Claystone = medium gray; moderately soft; sub blocky to amorphous; easily hydrated; smooth to silty to slight grainy texture; dull earthy to sl!ght sparkly texture common disseminated dark carbonaceous grains; common transparent silt size grains included mostly quartz and trace micas; non to very slightly calcareous; occasionally white to light gray firm calcareous streaks. 3485' Claystone = medium gray to olive gray; slight firm to soft; sub blocky to amorphous to occasionally subplaty; poorly to readily hydrated; occasionally platy grading to shale; occasionally grading to siltstone; slight to common disseminated carbonaceous material and trace micas; some carbonaceous flakes lineated along bedding planes; non to very slightly calcareous. 3605' Shale = medium dark gray to medium gray; slight firm to moderately firm; subplaty to subplaty; flaky along bedding planes; non to poorly hydrated; slight silty texture very slight carbonaceous material and trace micas; carbonaceous material disseminated and in flakes with common lineation along bedding planes; non to slight calcareous. 3660' [:! EPOCH 5 ~ PHILLIPS Alaska, Inc. Palm #lA Calcite = white to light brown to translucent; slight firm to moderately firm and brittle; mostly dense and choky; flaky to occasionally crystalline; dissolves rapidly in hydrochloric acid. 3720' Shale = medium dark gray to medium gray; moderately firm to slightly firm; subplaty to platy with flaky fracturing along bedding planes; slight silty texture; very poorly hydrateable increasing as it grade to claystone; trace carbonaceous material and micas; non to very slightly calcareous. 3755' Claystone = medium dark gray occasionally mottled white to light gray; moderately firm to moderately soft; sub blocky to subplaty; very slight to moderately silty texture poorly to moderately hydrateable; slight to moderately to some very abundant disseminated to flaky carbonaceous material; occasionally associated with possible white ash in firm fragments; 10% free calcite in sample and occasionally bands in claystone; non to slightly calcareous. 3815' Shale = medium dark gray to medium gray; moderately firm to slight firm; subplaty to platy with flaky fracturing along bedding planes; slightly silty texture; very poorly hydrateable increasing as it grades to claystone; trace carbonaceous material and micas; non to very slightly calcareous. 3845' Claystone = medium gray to medium light gray; moderately firm to moderately soft; subplaty to amorphous; smooth to moderately silty texture; slightly to easily hydrated slightly disseminated to flaky carbonaceous material and very slight disseminated to trace flaky micas; non to very slight calcareous. 3915' Claystone = medium gray; soft to slight firm; amorph°us to subplaty; smooth to moderately silty texture; easily to slowly rehydrated; slight disseminated carbonaceous mat; very slight disseminated micas; non to very slight calcareous. 3975' Claystone = medium gray; soft to moderately firm; amorphous to subplaty; smooth to slight silty texture; easily to fairly rehydrated; rare disseminated carbonaceous mat; slight very finely disseminated mica; very slight to non calcareous. EPOCH 6 ~ PHILLIPS Alaska, Inc. Palm #lA 4010 C-50 4050' Claystone = medium gray; soft to moderately firm; amorphous to subplaty; smooth to slight silty texture; easily to poorly rehydrated; very slight disseminated carbonaceous material; slight very finely disseminated mica; very slight to non calcareous. 4110' Shale = moderately- dark gray; soft to firm; firms with depth; crumbly to occasionally moderately tough; large, irregular cuttings with distinct linear edges; waxy, slightly resinous luster; smooth to occasionally slightly silty texture/appearance; predominantly non calcareous, rarely calcareous; moderately fissile; occasionally books of lamellar planar bedding; clay-rich shale; no visible oil indicators 4155' Claystone = medium gray; soft to moderately firm; amorphous to subplaty; smooth to slight silty texture; easily hydrated; very weakly disseminated carbonaceous material; slightly to very finely disseminated mica; very slight to non calcareous - sticky, mushy to fecal consistency; occasionally firm; massive - usually no visible structure; grades to silty texture occasionally 4245' Shale = moderate - dark gray; soft to firm; firms with depth; crumbly to occasionally moderately tough; large, irregular cuttings with distinct linear edges; waxy, slightly resinous luster; smooth to occasionally slight silty text/appear; predominantly no calcareous, rare calcareous; moderately fissile; occasionally books of lamellar planar bedding; clay-rich shale; no visible oil indicators 4305' Claystone = medium/dark gray; soft to moderately firm; predominantly amorphous; occasionally subplaty; smooth to slight silty texture; easily to poorly hydrated; very slight disseminated carbonaceous material; very finely disseminated mica; weakly to non calcareous; occasionally forms planar bedding, tougher and more resistant than amorphous claystone; white/light gray calcite lumps 4470' Ash Fall Tuff = white, medium gray; predominantly soft rarely crunchy; small, rounded, irregular cuttings; waxy luster; occasionally calcareous Claystone = medium gray to medium dark gray; soft to moderately firm; amorphous to subplaty; occasionally subfissile grading to shale; readily to slowly rehydrated; slight to moderately carbonaceous material inclusions; non to slightly calcareous with trace free calcite. 4505' Claystone = medium/dark gray; soft to moderately firm; predominantly amorphous; occasionally subplaty; smooth to slight silty texture; easily to poorly hydrated; very slight EPOCH 7 ~ PHILLIPS Alaska, Inc. Palm #lA disseminated carbonaceous material; very finely disseminated mica; weakly to non calcareous; occasionally forms planar bedding, tougher and more resistant than amorphous claystone; white/light gray calcite lumps 4535' Carbonaceous Material/Claystone = dark brownish gray to medium gray; soft; predominantly loose matte flakes and occasionally inclusions with claystone and shale; noncalcareous; commonly associated with ash fall tuff; common association with loose chalky to crystalline calcite, occasionally associated with occasionally loose sand including sub rounded to rare angular shard like mostly fine to very fine grained pebbles. 4580' Claystone = medium/dark gray; soft to moderately firm; predominantly amorphous; occasionally subplaty; smooth to slight silty texture; easily to poorly hydrated; very slight disseminated carbonaceous material; very finely disseminated mica; weakly to non calcareous; occasionally forms planar bedding, tougher and more resistant than amorphous claystone; white/light gray calcite lumps 4605' Carbonaceous Material/Shale = dark brownish gray to medium gray; slightly firm to soft; predominantly matte flakes mostly loose but occasionally occurring flat along bedding planes of subplaty to flaky shale; occasionally clustered in claystone; noncalcareous; commonly associated with ash fall tuff and occasionally calcareous material and minor loose sand and shards; trace pebbles; some dull yellow fluorescence and cut on ash and pebbles. 4665' Claystone = medium/dark gray; soft to moderately firm; predominantly amorphous; occasionally subplaty; smooth to slight silty texture; easily to poorly hydrated; very slight disseminated carbonaceous material; very finely disseminated mica; weakly to non calcareous; occasionally forms planar bedding, tougher and more resistant than amorphous claystone; white/light gray calcite lumps EPOCH 8 ~ PHILLIPS Alaska, Inc. Palm #lA SHOW SUMMARY PHILLIPS ALASKA, INC. PALM #lA NORTH SLOPE ALASKA SHOW NO. 1:4685-4695' Bit Type: 8 %" HTC DS70FN, INTERVAL 4865'-4695' (TVD:'4071.68-4075.8)" ROP WOB RPM GAS C1 C2 C3 C4 C5 BEFORE 91. 12.6 98 37.9 5589 571 249 74 0 9 DURING 90. 12.6 94 34.72 4088 420 184 56 0 8 MAXlMU 71. 15.7 91 37.21 4393 447 194 59 2 M 6 AFTER 89. 12.8 96 19.2 2295 226 97 31 2 3 4715' Claystone = medium/dark gray; soft to moderately firm; predominantly amorphous; occasionally subplaty; smooth to slight silty texture; easily to poorly hydrated; very slight disseminated carbonaceous material; very finely disseminated mica; weakly to non calcareous; occasionally forms planar bedding, tougher and more resistant than amorphous claystone; white/light gray calcite lumps 4770' Claystone = medium/dark gray; soft to moderately firm; predominantly amorphous; occasionally subplaty; smooth to slight silty texture; easily to poorly hydrated; very slight disseminated carbonaceous material; very finely disseminated mica; weakly to non calcareous; occasionally forms planar bedding, tougher and more resistant than amorphous claystone; white/light gray calcite lumps 4806' C-40 EPOCH 9 ~ PHILLIPS Alaska, Inc. Palm #lA SHOW SUMMARY PHILLIPS ALASKA, INC. PALM #lA NORTH SLOPE ALASKA SHOW NO. 2: 4800-4850' ' Bit Type: 8 %" HTC DS70FN INTERVAL: ' (TVD:4118.2-4138.4)' ' ROP WOB RPM GAS Cl C2 C3 C4 C5 BEFORE 80,4 8 94 31.31 3486 326 159 61 18 DURING 71.6 12.9 100 55.82 6241 804 463 214 137 MAXIMUM 82. 5.2 92 155.21 17725 2205 1238 558 336 AFTER 78.3 2 99 48.11 4573 563 318 144 88 4810' Shell Fragments = white to translucent; very calcareous - reacts fast with hydrochloric acid; mostly loose fragments occasionally occur as round coarse grains and pebbles; associated with claystone and minor very fine to fine sub rounded to angular sand grains; trace carbonaceous material occurs with grains; some dull yellow fluorescence with instant cut on surface of fragments and grains. 4850' Tuffaceous Claystone = medium gray to light gray to medium light gray; very soft to soft; easily rehydrated and expands slightly; slight silty texture as minor silt and very fine angular to sub rounded shard like grains including minor shell and calcite fragments; trace fluorescence and cut on fragments. 4890' Tuffaceous Siltstone = medium gray; moderately firm to firm; clayey; hydrates poorly or not at all; clayey; slight carbonaceous material mostly disseminated to minor flakes; silt moderately silty angular shards; non calcareous. 4965' Tuffaceous Claystone = medium gray to occasionally very light gray; soft; readily hydrates in water; slight to moderately disseminated and very slight flaky carbonaceous material; slight to moderately silty shards; non calcareous except for trace loose calcite/shell fragments. 5040' Claystone = medium gray to medium light gray; soft to slight firm; subplaty to amorphous and occasionally slight flaky grading to shale; readily to slowly hydrates in water; slight to moderately disseminated and flaky carbonaceous material; slight silt and EPOCH 1 o ~ PHILLIPS Alaska, Inc. Palm #lA silty shards; very slight very finely disseminated micas; trace micritic pyrite; noncalcareous except trace very fine calcite crystal inclusions. 5085' Siltstone = brownish gray to dark yellowish brown; tough; crumbly to moderately easily scored; medium sized planar cuttings with rounded edges; matt luster with occasionally microsparkles; gritty texture; weak to moderately calcareous; grades to mudstone; scattered micromicas; numerous black-dark gray carbonaceous material; rounded black quartz 'eyes' noted disseminated randomly; common no visible oil sign with scattered light yellow cut fluorescence flecks noted. Occasionally angular, gritty, very thin/planar- bedded shards 5140' Claystone = medium gray to medium light gray; soft to slight firm; subplaty to amorphous and occasionally slight flaky; readily to slowly hydrates in water; slight to moderately disseminated and flaky carbonaceous mat; slight silt and silty shards; very finely disseminated micas; trace-l% micritic pyrite with occasionally 2-5mm agglomerations; predominantly noncalcareous 5200' Ash Fall Tuff = white, medium gray; predominantly soft rarely crunchy; small, rounded, irregular cuffings; waxy luster; occasionally calcareous; rarely displays thin bedding. No visible oil indicators 5280' Claystone = medium gray to medium light gray; soft to moderately firm; subplaty to amorphous and occasionally slight flaky; readily to slowly hydrates in water; ubiquitous disseminated and flaky carbonaceous mat; occasionally silt and silty shards; very finely disseminated micas; trace-l% micritic pyrite with occasionally 2-5mm agglomerations; predominantly noncalcareous 5325' Siltstone = brownish gray to dark yellowish brown; tough; ~crumbly to moderately easily scored; medium sized planar cuffings with sharp edges; matte luster with occasionally sparkles; gritty texture; weak to moderately calcareous; grades to mudstone; scattered micromicas; numerous black-dark gray carbonaceous material; rounded black quartz 'eyes' noted disseminated randomly; commonly no visible oil sign with scattered light yellow cut fluorescence flecks noted; rare mm size, sub-rounded light brown quartz fragments; occasionally angular, >cm very thin/planar-bedded fragments 5400' Claystone = medium gray to medium light gray; soft to moderately firm; subplaty to amorphous and occasionally slight flaky; readily to slowly hydrates in water; ubiquitous disseminated and flaky carbonaceous mat; occasionally silt and silty shards; very finely disseminated micas; trace-l% micritic pyrite with occasionally 2-5mm agglomerations; predominantly noncalcareous EPOCH 11 ~ PHILLIPS,Alaska, Inc. Palm #lA 5445' Ash Fall Tuff = white, medium gray; predominantly soft rarely crunchy; small, rounded, irregular cuttings; waxy luster; occasionally calcareous; rarely displays thin bedding. No visible oil indicators 5470 Siltstone = brownish gray to dark yellowish brown; tough; crumbly to moderately easily scored; medium sized planar cuttings with sharp edges; matte luster with occasionally sparkles; gritty texture; weak to moderately calcareous; grades to mudstone; scattered micromicas; numerous black-dark gray carbonaceous material; dark gray/black carbonaceous mats disseminated randomly; common no visible oil sign with scattered light yellow cut fluorescence flecks noted; rare mm size, sub-rounded light brown quartz fragments; occasionally 5525' Ciaystone = medium gray to medium light gray; soft to moderately firm; subplaty to amorphous and occasionally slight flaky; readily to slowly hydrates in water; ubiquitous disseminated and flaky carbonaceous mat; occasionally silt and silty shards; very finely disseminated micas; trace-l% micritic pyrite with occasionally 2-5mm agglomerations; predominantly nonreactive with dilute hydrochloric acid rare quartz fragments are rounded, fine - medium grained. 5575' Siltstone = brownish gray to dark yellowish brown; tough; crumbly to moderately easily scored; medium sized planar cuttings with sharp edges; matte luster with occasionally sparkles; gritty texture; weak to moderately calcareous; grades to mudstone; scattered micromicas; numerous black-dark gray carbonaceous material; dark gray/black carbonaceous mats disseminated randomly; common no visible oil sign with scattered light yellow cut fluorescence flecks noted; rare mm size, sub-rounded light brown quartz fragments; occasionally 5630' Claystone = medium gray to medium light gray; soft to moderately firm; subplaty to amorphous and occasionally slight flaky; readily to slowly hydrates in water; ubiquitous disseminated and flaky carbonaceous mat; occasionally silt and silty shards; very finely disseminated micas; trace-l% micritic pyrite with occasionally 2-5mm agglomerations; predominantly nonreactive with dilute hydrochloric acid rare quartz fragments are rounded, fine - medium grained. 5695' Siltstone = brownish gray to dark yellowish brown; tough; crumbly to moderately easily scored; medium sized planar cuttings with sharp edges; matte luster with occasionally sparkles; gritty texture; weak to moderately calcareous; grades to mudstone; scattered micromicas; numerous black-dark gray carbonaceous material; dark gray/black carbonaceous mats disseminated randomly; common no visible oil sign with scattered light yellow cut fluorescence flecks noted; rare mm size, sub-rounded light brown quartz EPOCH 12 ~ PHILLIPS Alaska, Inc. Palm #lA fragments; siltstone commonly seen as sharp angled shards probably representing thin horizons. 5775' Ash Fall Tuff = white, medium gray; predominantly soft rarely crunchy; small, rounded, irregular cuffings; waxy luster; occasionally calcareous; rarely displays thin bedding. Probably intermediate/felsic composition: no visible oil indicators 5855' Siltstone = brownish gray to dark yellowish brown; tough; crumbly to moderately easily scored; medium sized planar cuttings with sharp edges; matte luster with occasionally sparkles; gritty texture; weak to moderately calcareous; grades to mudstone; scattered micromicas; numerous black-dark gray carbonaceous material; dark gray/black carbonaceous mats disseminated randomly; common no visible oil sign with scattered light yellow cut fluorescence flecks noted. 5920' Claystone = medium gray to medium light gray; soft to slight firm; amorphous to subplaty to sub blocky; occasionally slight flaky grading to shale; slight to moderately silty texture; trace very fine sandy; slight to moderately disseminated flaky carbonaceous material; trace disseminated micas; very slight to slight calcareous with slightly disseminated calcareous material. 5955' Siltstone = medium gray to occasionally with brownish hues; soft, occasionally firm to hard andesite tuff; amorphous to subplaty; slight disseminated carbonaceous material and occasionally flakes; slight to some moderately calcareous with scattered disseminated calcareous matter; hard tuff siltstone very calcareous; disseminated calcareous material;, slight very fine sandy; mostly sub angular grains. 5995' Claystone = medium gray to medium light gray; soft to slight firm; amorphous to subplaty to sub blocky; occasionally slight flaky grading to shale; slight to moderately silty texture; trace very fine sandy; slight to moderately disseminated flaky carbonaceous mat; trace disseminated micas; very slight to slight calcareous with slight disseminated calcareous material. 6030' Sandstone = medium light gray with slight brownish hue; fine to very fine grain; sub angular; moderately well sorted; moderately clayey; moderately to very calcareous; mostly quartz and some dark probably carbonaceous grains; associated with dense gray cryptocrystalline limestone and occasional pebbles; very poor visible porosity; no fluorescence or cut. 6065' Shale = medium gray to medium dark gray; soft to moderately firm; subplaty with some planar fracture; smooth to some silty texture slightly disseminated carbonaceous [:1 EPOCH 13 ~ PHILLIPS Alaska, Inc. Palm #lA material and trace mica; non to slightly calcareous inclusions some scattered disseminated calcareous material. 6110' Claystone = medium gray; soft to slight firm; amorphous to subplaty; hydrates readily to moderately; slight silty texture overall; slight very finely disseminated dark probably carbonaceous material; trace disseminated mica; trace very fine sand; very slight calcareous overall with scattered very finely disseminated white calcareous material; trace pyrite clusters and disseminated pyrite. 6150' Sand = some loose grains mostly white, light orangish brown and translucent; includes medium to coarse fragments and round grains; mostly noncalcareous, moderately firm lithics and some calcareous grains; with trace pyrite clusters; no stain or fluorescence on grain surface; possible with soluble clay matrix. 6185' Claystone = medium gray to occasionally medium dark gray; soft to slight firm; amorphous to subplaty commonly with slight visible fissility and planar fracture grading to shale; readily to moderately hydrates decreasingly grading to shale; slightly disseminated to flaky carbonaceous material increases locally and occasionally along planar bedding planes in shale; non to slight calcareous including scattered disseminated calcareous matedal 6230' Claystone = medium gray to occasionally medium dark gray; soft to slight firm; amorphous to subplaty common with slight visible fissility and planar fracture grading to shale; readily to moderately hydrates decreasing grading to shale; slight disseminated to flaky carbonaceous material increases locally and occasionally along bedding planes especially shale; non to slight calcareous including scattered, disseminated calcareous material 6290' Shale = medium gray to brownish gray to medium dark gray; slightly firm to firm; subplaty with weakly visible fissility; hydrates slowly to not at all; smooth to slightly silty texture; slightly disseminated carbonaceous material and rare flakes; trace very finely disseminated micas; non to slight calcareous. 6325' Claystone = medium gray to occasionally medium dark gray; soft to slight firm; amorphous to subplaty common with slight visible fissility and planar fracture grading to shale; readily to moderately hydrates decreasing grading to shale; slightly silty overall; slight very finely disseminated carbonaceous material and trace flakes; slight calcareous overall including slightly disseminated calcareous material; trace isolated pyrite and small clusters; trace micas. EPOCH 14 ~ PHILLIPS Alaska, Inc. Palm #lA 64O0' Claystone = medium gray to occasionally medium dark gray; soft to slight firm; amorphous to subplaty common with slightly visible fissility and planar fracture; smooth with earthy luster; mushy, soft; grades to planar bedded shale; readily to moderately hydrates slight silty overall; disseminated white/light gray carbonate rounded blebs are highly reactive with dilute hydrochloric acid - noted along weak bedding planes; finely disseminated carbonaceous material throughout; trace isolated flecks and small clusters pyrite; weak light yellow cut fluorescence flecks noted. 6465' Shale = medium gray to brownish gray to medium dark gray; slight firm to firm; subplaty with slight visible fissility; hydrates slowly to not at all; smooth to slight silty texture; disseminated carbonaceous material and rare flakes; trace very finely disseminated micas; non to slight calcareous; clay-rich, easily scored with probe. Note - when dried, shale has talc like white coating - non-reactive with dilute hydrochloric acid. 6515' Ash Fall Tuff = light gray/white -pale yellowish brown very soft - soft to moderately tough; smooth texture 20% calcareous; commonly appears waxy; scattered gray ashy streaks; rounded edges, amorphous blebs; weak bright yellow mineral fluorescence - no visible oil. 6550' Ciaystone = medium gray to occasionally medium dark gray; soft to slight firm; amorphous to subplaty common with slight visible fissility and planar fracture; smooth With earthy luster; mushy, soft; grades to planar bedded shale; readily to moderately hydrates slight silty overall; disseminated white/light gray carbonate rounded blebs are highly reactive with dilute hydrochloric acid - noted along weak bedding .planes; finely disseminated carbonaceous material throughout; trace isolated flecks and small clusters pyrite; weak light yellow cut fluorescence flecks noted. 6630' Ash Fall Tuff = light gray/white-pale yellowish brown; very soft - soft to moderately tough; smooth texture 20% calcareous; commonly appears waxy; scattered gray ashy streaks; rounded edges, amorphous blebs; weak bright yellow mineral fluorescence - no visible oil. 6665' Shale = medium gray to brownish gray to medium dark gray; slightly firm to firm; subplaty with slight visible fissility; hydrates slowly to not at all; smooth to slightly silty texture; disseminated carbonaceous material and rare flakes; trace very finely disseminated micas; non to slightly calcareous; clay-rich, easily scored with probe. Note - when dried, shale has talc like white coating - non-react with dilute hydrochloric acid. [:1 EPOCH 15 ~ PHILLIPS Alaska, Inc. Palm #lA 6715' Claystone = medium gray to occasionally medium dark gray; soft to slight firm; amorphous to subplaty common with slight visible fissility and planar fracture; smooth with earthy luster; mushy, soft; grades to planar bedded shale; readily to moderately hydrates slight silty overall; disseminated white/light gray carbonate rounded blabs are highly reactive with dilute hydrochloric acid - noted along weak bedding planes; finely disseminated carbonaceous material throughout; trace isolated flecks and small clusters pyrite; weak light yellow cut fluorescence flecks noted. 6780' Ash Fall Tuff = light gray/white-pale yellowish brown; very soft - soft to moderately tough; smooth texture 20% calcareous; commonly appears waxy; scattered gray ashy streaks; rounded edges, amorphous mm size blabs; occasionally weak bright yellow mineral fluorescence- no visible oil. 6830' Claystone = medium gray to occasionally medium dark gray; soft to slight firm; amorphous to subplaty common with slight visible fissility and planar fracture; smooth with earthy luster; mushy, soft; grades to planar bedded shale; readily to moderately hydrates slight silty overall; disseminated white/light gray carbonate rounded blabs are highly reactive with dilute hydrochloric acid - noted along weak bedding planes; finely disseminated carbonaceous material throughout; trace isolated flecks and small clusters pyrite; occasionally light yellow cut fluorescence noted. 6895' Shale = medium gray to brownish gray to medium dark gray; slight firm to firm; subplaty with slight visible fissility; hydrates slowly to not at all; smooth to slight silty texture; disseminated carbonaceous material and rare flakes; trace very finely disseminated micas; non to slight calcareous; clay-rich, easily scored with probe. Note - when dried, shale has talc like white coating - non-react with dilute hydrochloric acid. 6945' Ash Fall Tuff = light gray/white pale yellowish brown; very soft - soft to moderately tough; smooth texture; 20% calcareous; commonly appears waxy; scattered gray ashy streaks.; rounded edges, amorphous mm size blabs; weak bright yellow mineral fluorescence- no visible oil. 6980' Claystone = medium gray to occasionally medium dark gray; soft to slight firm; amorphous to subplaty common with slight visible fissility and planar fracture; smooth with earthy luster; mushy, soft; grades to planar bedded shale; readily to moderately hydrates slight silty overall; disseminated white/light gray, rounded calcite blabs are highly reactive with dilute hydrochloric acid - noted along weak bedding planes; finely EPOCH 16 ~ PHILLIPS Alaska, Inc. Palm #lA disseminated carbonaceous material throughout; occasionally crystals and small clusters pyrite to 1-3% occasionally light yellow cut fluorescence noted. 7060' Ash Fall Tuff = light gray/white-pale yellowish brown very soft - soft to moderately tough; smooth texture 20% calcareous; commonly appears waxy; scattered gray ashy streaks; rounded edges, amorphous mm size blebs; weak bright yellow mineral fluorescence- no visible oil. 7110' Claystone = medium gray; very soft to slight firm; amorphous to subplaty; hydrates readily to moderately slowly; slight to moderately silty/gritty text with silt grains, and fragmented calcite and shell debris; appearing as small elongate crystals, disseminated material and grainy white specks; moderately to abundant mostly black carbonaceous material; slight to moderately calcareous overall; occasionally grainy pyrite cluster; 10- 15% spotty light brown stain and dull yellow fluorescence; instant blue white cut. SHOW SUMMARY PHILLIPS ALASKA, INC. PALM #IA NORTH SLOPE ALASKA SHOW NO. 3: '7170-7252' Bit Type:. 8 %" HTC DS70FN INTERVAL: ' (TVD:') 5071.2-5104.12" ROP WOB RpM GAS C._J.1 C...~2 C~3 C_~4 C..~5 BEFORE 119 1.3 85 104.61 12212 1120 671 415 227 DURING 99.6 1.8 93 86 10176 912 534 321 216 MAXIMUM 44.6 0 95 179.94 22303 1808 995 575 369 AFTER 83.2 1 96 106.65 14650 1184 686 427 283 7165' Claystone = medium gray; very soft to slight firm; amorphous to subplaty; hydrates readily to moderately slowly; slight silty/gritty text with silt grains, and fragmented calcite and shell debris; appearing as small elongate crystals, disseminated material and grainy white specks; moderately to abundant mostly black carbonaceous mat; slight to moderately calcareous overall; occasionally grainy pyrite clusters; 10% dull light brown stain and dull yellow fluorescence on calcite; instant cut. 7221' Calcite/Shell Fragments = abundant translucent and some white; mostly very fine to fine elongate crystals and some grainy very fine to medium lower lithic; calcite possible from recrystallized shells; 20-30% of sample appearing as mostly loose debris with trace dense crystalline grainstone; associated with moderately to abundant black to H EPOCH 17 ~ PHILLIPS Alaska, Inc. Palm #lA brownish black carbonaceous material and minor silt; associated with occasionally grainy pyrite cluster; 20-30% spotty dull yellow fluorescence and light brown stain; instant bluish white cut on fragment and slight instant to very slow streaming on grain stain. 7305' Claystone = medium gray to medium dark gray; soft to slight firm; amorphous to subplaty with occasionally incipient sandstone grading to shale; smooth to some silty texture; slight to moderately flaky carbonaceous material occasionally flat along bedding planes; associated with abundant calcite spicules; trace pyrite; 10% stain, fluorescence, and weak cut 7385' Sandstone = medium light gray; very fine to fine grained; sub rounded; high sphericity; moderately sorted; occasionally as loose grains to well consolidated with calcareous and slight to occasionally moderately clay and silt matrix; grading to siltstone; includes quartz, some calcite lithics, and minor carbonaceous material and trace white to light brown lithics; faint dull yellow fluorescence and very weak cut. 7425' Tuff = white to tan to light brown; slight firm to brittle medium to coarse round grains and fragments; appears reworked but possible bedded in place; associated with minor sand; trace very weak cut and fluorescence. 7455' Claystone = medium dark gray to medium gray; soft to slight firm to occasionally very firm; amorphous to subplaty to platy; occasionally subplanar fissility; occasionally grading to firm 'shale; smooth to slightly silty texture; moderately to abundant dark carbonaceous flaky and disseminated material occasionally fiat along bedding planes; some loose tuff, calcite, and silt in sample; trace pyrite. EPOCH 18 7490' MORAINE ~ PHILLIPS Alaska, Inc. Palm #lA SHOW SUMMARY PHILLIPS ALASKA, INC. PALM #lA NORTH SLOPE ALASKA SHOW NO. 4: 7490-8600" Bit Type: 8 %" HTC DS70FN INTERVAL ' (TVD:') 5198.62-5641' ' · ROP WOB RPM GAS C._~1 C_.~2 C_~3 C_~4 C5 BEFORE 57.5 11.7 0 87.59 9895 975 577 344 219 DURING 102.3 7 94 167.01 14997 1098 696 617 480 MAXIMUM 69.7 6.4 90 691.88 97901 7094 2728 1710 1124 AFTER 81.3 7.6 90 180.17 17639 1633 878 538 358 7510' Siltstone = medium gray to medium dark gray; dense to some friable; some loose silt; common very fine to fine grains included; sub angular to sub rounded; some thinly bedded with claystone; subplaty to platy; mostly quartz and some minor dark carbonaceous and calcareous lithics; moderately clay and slightly calcareous cement; occasionally poorly visible porous if friable; 10% spotty yellow fluorescence and very light brown stain in sample; instant surface to slow streaming cut. 7560' Formation = Interbedded medium-light grey to medium gray sandstone, siltstone, siltstone and claystone with Sandstone = very fine grained to silty with scattered fine grains; subangular to subrounded; moderate to well sorted; very friable to poorly consolidated with occasional very slightly calcareous cement; occurs as loose grains and very small grain clusters in sample; mostly quartz and minor igneous volcanics, lithics with trace of carbonaceous material and micas; some poorly visible porosity and permeability; 20-30% light to medium brown oil stain and moderate, bright yellow fluorescence; slight instant and slow to moderate streaming cut; trace oil sheen in washed sample. 7625' Formation = Interbedded medium-light grey to medium gray sandstone, siltstone, siltstone and claystone with Sandstone = very fine grained to silty with scattered fine grains; subangular to subrounded; moderate to well sorted; very friable to poorly consolidated with occasional very slightly calcareous cement; occurs as loose grains and very small grain clusters in sample; mostly quartz and minor igneous volcanics, lithics with trace of carbonaceous material and micas; some poorly visible porosity and permeability; 20-30% light to medium brown oil stain and moderate, bright yellow [:1 EPOCH 19 ~ PHILLIPS Alaska, Inc. Palm #lA fluorescence; slight instant and sow to moderate streaming cut; trace oil sheen in washed sample. 770O' Sandstone = medium light gray to occasionally medium gray; very fine grain to silty with scattered fine grains; sub angular to sub rounded; well to moderately sorted; very friable to poor consolidated with some slight to occasionally moderately calcareous cement; abundant loose grains and grain clusters; mostly quartz and minor igneous volcanic lithics; slightly disseminated carbonaceous material and trace micas; thinly interbedded siltstone and sandstone with minor claystone; very poor to poorly visible porosity and permeability; 30% spotty light to medium brown oil stain and moderately bdght yellow fluorescence; instant moderately streaming cut. 7760' Sand = grayish brown-medium gray; very fine grained; unconsolidated quartz grains; sub angular to sub rounded; moderately well sorted; quartz rich with occasionally igneous lithics; scattered micro-micas; scattered carbonaceous specks; 20% medium-- coarse grained milky and light brown & translucent abraded grains; instant milky fluorescence; light yellow streaming cut; distinct oil odor. 7805' Tuff = white- tan to light brown; mushy to firm brittle medium to coarse round grains and fragments; possible tuff layers noted within sandstone; weak-moderate cut fluorescence. 7830' Sandstone = medium light gray to occasionally medium gray; very fine grain to silty with scattered fine grained; sub angular to sub rounded; well to moderately sorted; very friable to poorly consolidated with some slight to occasionally moderately calcareous cement; abundant loose grains and grain clusters; mostly quartz and minor igneous volcanic lithics; slightly disseminated carbonaceous material and trace micas; thinly interbedded siltstone and sandstone with minor claystone; very poor to poor visible porosity and permeability; weak split light brown oil stain & strong bright yellow fluorescence; instant moderately streaming cut. 7905' Shale = dark grayish green - brownish gray; slight firm to firm; subplaty; fissile; hydrates slowly; smooth to slight silty texture; disseminated carbonaceous material and rare flakes; very finely disseminated micas; non to slight calcareous; clay-rich easily scored with probe - often waxy app; thin to medium bedded; hardens with depth - large >5cm pieces noted in returns. 7950' Claystone = medium dark gray to medium gray; soft to slight firm to occasionally very firm; amorphous to subplaty to platy; occasionally subplanar fissility; occasionally grading firm shale; smooth to slight silty texture; moderately to abundant dark carbonaceous flaky and disseminated material occasionally flat along bedding planes; [::1 EPOCH 20 ~ PHILLIPS Alaska, inc. Palm #lA some loose tuff, calcite, and silt in sample; trace pyrite.; resistant to hydration, tends to form large balls of clay on shaker table; pyrite crystals and agglomerations to 5mm diameter; weak light yellow cut fluorescence; weak milky fluorescence; weak oil odor remaining. 8015' Tuff = white- tan to light brown; mushy to firm brittle medium to coarse round grains and fragments; possible tuff layers noted within claystone; occasionally thick (>cm wide) layers noted; weak-moderately cut fluorescence. 8060' Shale = dark brownish gray - brownish gray; slight firm to firm; subplaty; fissile; hydrates slowly; smooth to slight silty texture; disseminated carbonaceous material and rare flakes; very finely disseminated micas; non to slightly calcareous; clay-rich easily scored with probe - often waxy app; thin to medium bedded; hardens with depth - large >5cra pieces noted in returns; quick light yellow streamers, slow milky luminescence. 8125' Claystone = medium dark gray to medium gray; soft to slight firm to occasionally very firm; amorphous to subplaty to platy; occasionally subplanar fissility; occasionally grading to firm shale; smooth to slight silty texture; 5-20% dark gray/black carbonaceous flakes and disseminated material occasional parallel bedding planes; calcite blebs disseminated; trace pyrite throughout; resistant to hydration, tends to form clots/clay balls on shaker table. 8175' Siltstone = medium gray to medium light gray to brownish gray, and occasionally light brown grading tuff; subplaty to platy often interbedded with claystone and minor very fine sandstone; slight carbonaceous material occurring as finely disseminated or as flakes lineated to laminated along bedding planes; non to slight calcareous and occasionally moderately calcareous especially sandy; occasionally very poorly visible porosity with spotty fluorescence and cut. 8193' TOP HRZ 8220' Claystone = medium gray to brownish gray; soft to slight firm; platy to flaky; earthy to slight velvety texture; smooth to slight silty with some thinly interbedded siltstone and minor sandstone; abundant flaky carbonaceous material occurring as iineations and laminated along bedding planes; mostly resists hydration to occasionally readily hydrated when ashy; very slightly disseminated micas and possible micropyrite; spotty dull yellow fluorescence and cut in siltstone and sandstone; slow diffuse cut fluorescence from carbonaceous material. 8280' Shell Fragments = white to light brown to occasionally translucent coarse to very fine fragments and sub rounded grains; some round white tuff fragments included; possibly Ecl EPOCH 21 ~ PHILLIPS Alaska, Inc. Palm #lA reworked sandstone; 20% moderately bright yellow fluorescence and light brown stain; instant cut. 8325' Carbonaceous Claystone = brownish gray to medium gray; subplaty to platy with slight incipient fissility grading to shale; slight velvety to moderately silty texture abundant dark grayish brown to brownish black carbonaceous flakes irregularly laminated or lineated along bedding planes or loose in sample; thinly laminated with some siltstone and minor tuff and very fine sandstone; hydrates very slowly or not at all- tuffaceous; slightly disseminated mica; slow diffuse cut fluorescence from carbonaceous matter. 8385' Claystone = brownish gray to medium light gray subplaty to platy with some incipient sandstone grading to shale; smooth to slight velvety to moderately silty texture moderately to slight dark grayish brown to brownish black carbonaceous flakes irregularly laminated or lineated along bedding planes or loose in sample; increases with ash contamination grading tuff claystone; hydrates very slowly or not at all- tuffaceous; slight disseminated mica; slow diffuse cut from carbonaceous mat. 8445' Tuffaceous Claystone = medium light gray; soft to slight firm; sub blocky to subplaty; smooth to some slight silty texture; trace very finely disseminated micas and carbonaceous material; locally associated with moderately to abundant carbonaceous flakes; hydrates readily; non to slight calcareous. 8485' Carbonaceous Claystone = dark grayish brown to grayish brown; soft and malleable to slight brittle; flaky to subplaty composed of predominantly flaky carbonaceous matter thinly laminated with clay and tuffaceous clay; smooth to slight silty texture; clay content poorly to readily hydrates; non calcareous; no fluorescence and very slow diffuse cut fluorescence. 8518' C-28 8525' Ash Flow Tuff = light bluish gray; soft to moderately soft; flaky to subplaty; smooth texture; non calcareous. 8545' Carbonaceous Shale = brownish gray to dark brownish gray; slight firm to very firm; subplaty to flaky; smooth and earthy to slight silty texture; carbonaceous material appears more indurated and less flaky than above. 8590' Carbonaceous Shale = dark brownish gray to brownish gray: slight firm to firm; subplaty to sub blocky; smooth and earthy to slight silty texture flaky to some poorly indurated [-1 EPOCH 22 ~ PHILLIPS Alaska, Inc. Palm #lA fissility; grading to shale; non calcareous overall; rare grading slight calcareous siltstone and trace calcareous sandstone. 8602' BASE HRZ 8675' Conglomeratic Sand = transparent to some white to translucent to light brown loose grains; fine to occasionally coarse and trace pebbles; rounded to sub rounded; hi sphericity; lithics includes mostly quartz, reworked calcareous fragments; and minor igneous volcanic and some dark grains; trace spotty fluorescence and cut; possibly cavings. 8710' Shale = dark gray to dark brownish gray; moderately firm to slight firm; subplaty to flaky; smooth to slight silty texture planar fracture; common carbonaceous matedal compressed along bedding planes; organic rich clayey shales overall; non to slight calcareous; no fluorescence but slow diffuse cut. 8745' Siderite = light brown to brown to light brownish gray; dense to slight chalky; cryptocrystalline to occasionally microcrystalline; firm and brittle to slightly firm and crumbly; medium to coarse fragments and occasionally flaky; mostly slightly argillaceous and occasionally thinly interlaminated with dark gray to black carbonaceous shale; no visible porosity and permeability; no fluorescence; slow diffuse cut. 8805' Sand = composed mostly of white to light orange brown coarse angular fragments and round grains of dense aphanitic tuff and some medium to fine grain sub rounded to round quartz; loose grains only; angular fragments logged as tuff; no fluorescence or cut 8845' Shale = dark gray to dark brownish gray; moderately firm to slight firm; subplaty to flaky; smooth to slight silty texture planar fracture; common carbonaceous material compressed along bedding planes; organic rich clayey shales overall; non to slightly calcareous; no fluorescence but slow diffuse cut. 8880' Sand = composed mostly of white to light orange brown coarse angular fragments and round grains of dense aphanitic tuff and some medium to fine grain sub rounded to round quartz; loose grains only; 2-3% euhedral quartz grains disseminated; pyrite crystals and agglomerations to 1-2% locally; tuff clasts intimately associated with sand; quick light yellow fluorescence seen. Note - probably ice-rafted sand EPOCH 23 ~ PHILLIPS Alaska, Inc. Palm #lA 8889' K-1 8930' Shale = dark gray to dark brownish gray; moderately firm to slight firm; subplaty to flaky; smooth to slight silty texture planar fracture; common carbonaceous material aligned along bedding planes; organic rich clayey shales overall; non to slight calcareous; occasionally crunchy & friable; interbedded with claystone quick light yellow fluorescence noted 8970' Ash Fall Tuff = light gray to white; soft to moderately soft; sub rounded blebs to subplaty; ubiquitous, disseminated throughout; weak fluorescence only 8995' Shale = dark gray to dark brownish gray; moderately firm to slight firm; very thin bedded; smooth to slight silty texture planar fracture; common carbonaceous material aligned along bedding planes; clay rich; non to weakly calcareous; friable, occasionally crunchy; interbedded with claystone; quick light yellow fluorescence noted weak milky fluorescence when crushed 9040' Claystone = dark grayish brown to grayish brown; soft/malleable to occasionally brittle; flaky to subplaty interbedded with shale; rarely resistant; rare oil indicators. [---I EPOCH 24 ~ PHILLIPS Alaska, Inc. Palm #lA 9046' KUPARUK C SHOW SUMMARY PHILLIPS ALASKA, INC. PALM #lA NORTH SLOPE ALASKA SHOW NO. 5: 9045-9258" Bit Type: 8 %" HTC DS70FN INTERVAL ' (TVD:') 5848.02-5890.68': ' · ROP WOB RPM GAS C_.~.1 C2 C_~3 C~4 C...~5 BEFORE 47.8 5.4 98 165.2 16854 2025 1678 1406 1084 DURING 80.9 5.8 98 201.28 35380 3261 1772 953 464 MAXIMUM 71.9 8.5 94 905.41 125627 11596 6153 3083 1387 AFTER 43.2 8.5 94 126.17 10487 877 596 468 449 9065' SAND/SANDSTONE = Grayish brown to brownish black; dominantly clear > translucent > milky; dominantly sub rounded; good sphericity; occasional pyrite crystals scattered throughout; lower medium to upper fine grained with trace to 5% glauconite; moderate to well sorting; trace siderite chunks; rare calcite and inoceramus fragments; free oil seen on shaker table; gold fluorescence; instant milky cut fluorescence; brown cut; 100% oil stain in sands; possibly 20-40% cavings; mostly shale, siltstone and minor white volcanic ash. 9120' SANDSTONE = Light gray overall- mostly clear grained quartz with minor milky quartz; trace glauconite, pyrite and rare inoceramus prisms; trace to 10% siderite as chunks and matrix material/grain coating; mostly unconsolidated; slightly calcareous; 100% oil stain; gold fluorescence; streaming milky cut fluorescence; brown cut; possible rare tar on some grains; 20-30% shale, siltstone and volcanic ash are possible cavings. EPOCH 25 ~ PHILLIPS Alaska, Inc. Palm #lA 9140' BASE KUPARUK C (LCU) 9183 MILUVEACH 9215' Shale = grayish brown to dark brownish gray to medium gray to medium light gray; slight firm and brittle to crumbly; earthy to a slight silty/resinous texture; subplaty to flaky to subplaty commonly with very thin lamina; slight carbonaceous to slight tuffaceous; noncalcareous; associated with occasionally siliceous to rare tuff sandstone with fine to very fine and rare medium to coarse; very poor cut in shales; occasionally sandstone with slow to moderately streaming cut from organic rich grains in clay matrix. [-1 EPOCH 26 ~ PHILLIPS Alaska, Inc. Palm #lA RIG ACTIVITIES Epoch commenced logging the Phillips Alaska Palm #lA at 2800' on February 23, 2001. The Palm #lA sidetracked the Palm #1, kicking off a cement plug at approximately 2700'. FEBRUARY 23, 2001 Drilled ahead from 2681' to 3338' with a 9.7# mud weight. Drilling averaged 137 feet per hour, and gas averaged 20 units with a maximum of 37 units. FEBRUARY 24, 2001 Drilled ahead from 3338' to 4422' with a 9.7 mud weight, pumped hi vis sweep and cleaned hole. Short tripped to 3997', pumped another hi vis sweep, and short tripped to 2600'. Ran in hole to bottom increasing mud weight to 10.2, circulated out with maximum 64 units of trip gas, and drilled ahead to 4518'. For the day, drill gas averaged 24 units with a maximum of 59, and drill rate averaged 130 feet per hour. FEBRUARY 25, 2001: 4518-5921'MD Drilled ahead from 4518' to 4645', fixed a frozen auger, and drilled ahead from 4645' to 5921'. Mud weight was maintained at 10.3 to 10.4, drill rate averaged 120 feet per hour, and gas averaged 78 units with a maximum of 251. FEBRUARY 26, 2001: 5921-7165'MD Drilled ahead from 5921'to 6399', pumped sweep and conditioned hole, and short tripped 23 stands. Circulated and conditioned hole, and drilled ahead from 6399' to 7165'. Mud weight was maintained in a range of 10.2 to 10.4. Background gas averaged 76 units with a maximum of 135, and trip gas peaked at 157 units. Drilling averaged 137 feet per hour. FEBRUARY 27, 2001: 7165-8171'MD Drilled ahead from 7165' to 8171' raising the mud weight from 10.3 to 10.6 at 7200' and gradually up to 10.8. Drill rate averaged 82 feet per hour and gas 194 units. Maximum gas was 538 units. [-.-I EPOCH 27 ~ PHILLIPS Alaska, Inc. Palm #lA FEBRUARY 28, 2001: 8171-8643'MD Drilled ahead from 8171' to 8385', and circulated and conditioned hole after 691 units of gas. Drilled ahead to 8643' until base of HRZ identified by geologist on Sperry Sun log. Overall, gas averaged 205 units, 691 maximum, maintained a 10.8 mud weight, and drilled on average 97 feet per hour. Circulated and conditioned hole and tripped out to 8111' for leak off test. Leak off passed, measuring to 12.9 equivalent mud weight. Pulled out of hole and laid down MWD tool. MARCH 1, 2001: 8643'MD Downloaded Sperry Sun and laid back tool. Removed wear bushing and performed BOP tests. Finished testing, inserted wear bushing, and picked up BHA. Ran in hole to shoe and circulated bottoms up. Ran in hole to 5145' and circulated and conditioned hole. Ran in hole to 8590', and circulated and conditioned hole, maximum 230 units of trip gas. Weighted up mud from 10.8 to 12.2 in three stages circulating out in each stage. Circulating on third stage. MARCH 2, 2001: 8643-9160'MD Circulated out 12.2 mud and picked up singles to bottom. Ran slow pump rates and drilled ahead from 8643' to 8810'. Checked flow after 410 units of gas, no flow, and shut in well and checked pressures, no pressure. Drilled ahead from 8810' to 9015', checked flow with high gas, no flow, and circulated out high gas, maximum 960 units. Drilled ahead from 9105' to 9137', checked flow with high gas, no flow, and circulated out high gas, maximum 630 units. Drilled ahead from 9137' to 9160'. MARCH 3, 2001: 9160-9318'MD Drilled ahead from 9160' to 9318'. Pumped sweep and circulated out. Short tripped to 8500' and circulated bottoms up, maximum 364 units of trip gas. Pulled out of hole to shoe, and began tripping in. MARCH 4, 2001: 9318'MD(TD) Tripped in to bottom and circulated out, maximum 315 units of gas. Pulled out of hole to run e-logs [:1 EPOCH 28 ~ PHILLIPS Alaska, Inc. Palm #lA EPOCH MUD RECORD Mud Report Phillips Alaska, Inc. Palm #lA North Slope, Alaska , , Date Depth TVD MW ViS PV YP Gel FL Cake Sol O/W SN MBT pH AIk PflMf CI ~Ca 2/23/01 2,700.00' 9.6 48 20 14 4/8 4.0 1/0 9.9 0~90 0.00 5.0 9.8 0.00 .18/.5 1200 80 2124101 3,170-00' 9.8 43 11 9 2/3 5.2 110 8.0 0/92 TR 5.0 9.5 0.00 .3/.2 550 80 2/25/01 4,500.00' 10.2 48 16 16 4/7 5.0 110 10.0 1/89 TR 10.0 9.2 0.00 .021.25 500 60 2/26/01 5,750.00. 10.3 48 22 21 7/17 4.8 1/0 11.0 1/88 TR 12.5 9.0 0.00 .01/1.2 300 40 2/27/01 7,080.00' 10.3 46 19 21 9/18 4.6 110 12.0 1/87 TR 15.0 9.0 0.00 .02/1.4 300 40 2/28/01 8,100.00' 10.8 45 19 19 7/12 3.8 ,1/2 13.0 2/85 TR 15.0 9.0 0.00 .02/1.6 300 40 3/1/01 8,643.00' 10.7 45 17 20 7/15 3.2 1/2 13.0 2/85 TR 15.0 10.0 0.00 .07/1.6 300 40 3/2/01 9,137.00' 12.2 45 21 18 6112 3.0 1/2 20.0 1.5/78.5 0.25 15.0 10.0 0.00 .1812.1 700 60 3/3/01 9,318.00' 12.2 46 22 19 6/9 2.8 1/2 20.5 1.5/78 0.25 15.0 10.0 0.00 .14/2.4 650 60 EPOCH 29 ~ PHILLIPS Alaska, Inc. Palm #lA SURVEY RECORD il/EPOCH Survey Report Phillips Alaska, Inc. Palm #lA North Slope, Alaska Measured Inclination Azimuth TVD Latitude Departure Vertical Dogleg Depth An~]le An~ile Depth Feet Feet Section Severity 2,700.00' 2,700.00' 0.63 117.75 2,699.41' 15.88S 50.91E 40.82 0.36 2,747.69' 3.66 104.58 2,747.07' 16.38S 52.62E 42.20 6.4 2,779.50' 5.40 92.36 2,778.78' 16.70S 55.09E 44.36 6.2 2,812.10' 6.62 87.61 2,811.10' 16.68S 58.50E 47.51 4.06 2,875.72' 9.26 79.11 2,874.20' 15.56S 67.20E 55.97 4.52 2,940.53' 11.95 72.32 2,937.90' 12.54S 78.71E 67.76 4.57 3,004.07' 14.69 71.64 2,999.73' 8.00S 92.63E 82.35 4.33 3,067.69' 17.28 69.72 3,060.88' 2.18S 109.16E 99.84 4.15 3,131.31' 19.70 68.30 3,121.21' 5.05N 127.99E 120.00 3.86 3,195.05' 22.00 67.93 3,180.77' 13.51N 149.04E 142.68 3.62 3,258.95' 24.59 66.73 3,239.46' 23.27N 172.35E 167.95 4.12 3,322.92' 27.01 66.47 3,297.05' 34.33N 197.90E 195.79 3.78 3,386.62' 29.72 68.66 3,353.10' 45.85N 225.87E 226.04 4.56 3,450.24' 32.72 70.42 3,407.50' 57.35N 256.77E 258.99 4.93 3,513.85' 35.82 69.65 3,460.06' 69.59N 290.43E 294.76 4.92 3,577.73' 39.03 68.48 3,510.78' 83.47N 326.67E 333.56 5.13 3,642.07' 42.00 66.44 3,559.70' 99.51N 365.26E 375.34 5.06 EPOCH 30 /; ~ PHILLIPS Alaska, Inc. Palm #lA 6,543.71' 66.64 66.75 4,814.73' 1124.17N 2757.18E 2977.41 0.7 6,639.40' 66.25 66.54 4,852.96' 1158.94N 2937.71E 3065.13 0.45 6,735.02' 65.68 67.06 4,891.90' 1193.33N 2917.98E 3152.45 0.78 6,830.80' 65.23 66.95 4,931.69' 1227.37N 2998.19E 3239.58 0.48 6,926.83' 65.50 67.99 4,971.72' 1260.81N 3078.81E 3326.87 1.02 7,022.21' 65.45 67.47 5,011.30' 1293.70N 3159.12E 3413.64 0.49 7,117.89' 66.52 68.32 5,050.24' 1326.58N 3240.09E' 3501.03 1.38 7,213.52' 66.66 69.04 5,088.23' 1358.49N 3321.85E 3588.76 0.71 7,309.08' 66.30 68.33 5,126.37' 1390.34N 3403.47E 3676.35 0.78 7,404.53' 65.99 67.04 5,164.98' 1423.48N 3484.23E 3763.64 1.27 7,500.13' 67.18 67.75 5,202.97' 1457.19N 3565.22E 3851.37 1.42 7,595.74' 66.84 66.70 5,240.30' 1491.27N 3646.37E 3939.39 1.07 7,692.33' 66.52 67.73 5,278.54' 1525.62N 3728.15E 4028.09 1.04 7,787.37' 66.18 66.36 5,316.67' 1559.57N 3808.31E 4115.14 1.36 7,883.30' 65.70 66.21 5,355.77' 1594.80N 3888.51E 4202.72 0.52 7,978.75' 66.18 66.50 5,394.69' 1629.75N 3968.35E 4289.87 0.57 8,074.37' 66.03 66.73 5,433.42' 1664.45N 4048.59E 4377.29 0.27 8,169.80' 67.04 66.85 5,471.42' 1698.95N 4129.04E 4464.82 1.07 8,265.33' 66.57 65.71 5,509.04' 1734.27N 4209.44E 4552.62 1.2 8,361.08' 65.97 66.00 5,547.57' 1770.12N 4289.42E 4640.25 0.69 8,456.37' 67.39 64.92 5,585.29' 1806.46N 4369.02E 4727.70 1.82 8,552.55' 67.32 64.21 5,622.32' 1844.58N 4449.19E 4916.37 0.69 8,648.15' 67.11 66.24 5,659.35' 1881.51 N 4529.21E 4904.45 1.97 8,743.84' 66.65 64.63 5,696.93' 1918.10N 4609.24E 4992.40 1.62 8,839.44' 68.04 66.73 5,733.76' 1954.42N 4689.63E 5080.58 2.49 8,935.10' 68.18 66.58 5,769.42' 1989.60N 4771.13E 5169.34 0.21 9,030.55' 67.99 67.19 5,805.05' 2024.37N 4952.27E 5257.89 0.63 EPOCH 32 ~ PHILLIPS Alaska, Inc. Palm #lA Measured Inclination Azimuth TV Latitude Departure Vertical Dogleg Depth Angle Angle Depth Depth Feet Section Severity 9,126.05' 68.05 66.29 5,840.79' 2059.34N 4933.92E 5346.44 0.87 9,221.87' 67.64 66.47 5,876.92' 2094.90N 5015.24E 5435.18 0.47 EPOCH 33 ~ PHILLIPS Alaska, Inc. Palm #lA BIT RECORD EPOCH Bit Record Phillips Alaska, Inc. Palm # lA North Slope, Alaska Bit # Size Manufacturer Type Serial# Jets In Out Feet Hrs 1 8.50 Hughes DS70FN 23840 3X13,3X142,700.00' 5,618.00' 3,918.00' 84 ,, EPOCH 34 ~ PHILLIPS Alaska, Inc. Palm #lA DAYS VS DEPTH PHILLIPS ALASKA, INC. PALM #lA DAYS VS. DEPTH 0 0 I 2 3 4 $ 6 8 9 10 -1000 -2000 -3000 ~ -4000 -5000 -6000 -7000 -8000 -9000 -10000 Days EPOCH 35 Fluid Analysis on Separator Samples Phillips Alaska, Palm Palm 1A Final Report Prepared For Dennis Wegener Phillips Petroleum Co. Standard Conditions Used: Pressure: 14.696 psia Temperature: 60oF Prepared By: Nikhil Joshi Reviewed By: Dennis D’Cruz Oilphase Houston A Schlumberger Company 2315 Schlumberger Street, Building 15 Houston, Texas, 77023 (713) 921-9500 Date: August 2001 Report# NAM 679 TABLE OF CONTENT LIST OF FIGURES ................................................. 3 LIST OF TABLES .................................................. 4 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 2 EXECUTIVE SUMMARY ....................................... 5 OBJECTIVE ...................................................... 5 INTRODUCTION ................................................... 5 SCOPE OF WORK .................................................. 5 RESULTS ....................................................... 5 CHAIN OF SAMPLE CUSTODY .......................................... 6 RESULTS AND DISCUSSIONS ................................. 7 FLUIDS PREPARATION AND ANALYSIS ................................... 7 PVT ANALYSIS ON RECOMBINED RESERVOIR FLUID ......................... 14 CONSTANT COMPOSITION EXPANSION ................................... 20 DIFFERENTIAL VAPORIZATION ........................................ 24 Oil Phase Properties .......................................... 24 Gas Phase Properties .......................................... 28 Compositions .................................................. 33 RESERVOIR OIL VISCOSITY ......................................... 36 SINGLE-STAGE SEPARATION TEST ..................................... 38 APPENDIX A: NOMENCLATURE AND DEFINITIONS ............... 45 APPENDIX B: MOLECULAR WEIGHTS AND DENSITIES USED ....... 46 APPENDIX C: EQUIPMENT .................................. 47 FLUIDS PREPARATION AND VALIDATION ................................. 47 RECOMBINATION EQUIPMENT ......................................... 48 FLUID VOLUMETRIC (PVT) AND VISCOSITY EQUIPMENT ..................... 48 APPENDIX D: PROCEDURE .................................. 49 SEPARATOR FLUIDS PREPARATION AND VALIDATION ........................ 49 RECOMBINATION OF SEPARATOR SAMPLES ................................ 49 RESERVOIR FLUID VALIDATION ....................................... 50 CONSTANT COMPOSITION EXPANSION PROCEDURE ........................... 50 DIFFERENTIAL VAPORIZATION PROCEDURE ............................... 50 MULTI-STAGE SEPARATION TEST ..................................... 51 LIQUID PHASE VISCOSITY AND DENSITY MEASUREMENTS ..................... 51 STOCK-TANK OIL (STO) VISCOSITY AND DENSITY MEASUREMENTS ............. 51 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 3 List of Figures PVT MEASUREMENTS ON RECOMBINED RESERVOIR FLUID FIGURE 1: CCE RELATIVE VOLUME ......................................... 22 FIGURE 2: CCE % LIQUID VOLUME ......................................... 23 FIGURE 3: DV OIL VOLUME FACTOR (BO) .................................... 25 FIGURE 4: DV GAS-OIL RATIO (RS) ....................................... 26 FIGURE 5: DV LIQUID DENSITY (G/CC) ..................................... 27 FIGURE 6: DV GAS VOLUME FACTOR (BG) .................................... 29 FIGURE 7: DV GAS DEVIATION FACTOR (Z) .................................. 30 FIGURE 8: DV GAS RELATIVE DENSITY (AIR = 1) ............................. 31 FIGURE 9: DV GAS VISCOSITY (CP) ....................................... 32 FIGURE 10: RESERVOIR OIL VISCOSITY ..................................... 37 FIGURE 11: SEPARATION CORRECTED OIL VOLUME FACTOR (BO) .................... 43 FIGURE 12: SEPARATION CORRECTED GAS-OIL RATIO (RS) ....................... 44 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 4 List of Tables TABLE 1: WELL AND SAMPLE IDENTIFICATION .................................. 7 TABLE 2: SAMPLING AND TRANSFER SUMMARY ................................... 8 TABLE 3: SEPARATOR GASES COMPOSITION ..................................... 8 TABLE 4: SEPARATOR FLUID PROPERTIES ...................................... 9 TABLE 5: SEPARATOR LIQUID COMPOSITION (SAMPLE# 1.02) ..................... 10 TABLE 6: SEPARATOR LIQUID CALCULATED PROPERTIES (SAMPLE# 1.02) ............. 11 TABLE 7: SEPARATOR LIQUID COMPOSITION (SAMPLE# 1.04) ..................... 12 TABLE 8: SEPARATOR LIQUID CALCULATED PROPERTIES (SAMPLE# 1.04) ............. 13 TABLE 9: MATHEMATICALLY RECOMBINED RESERVOIR FLUID ........................ 15 TABLE 10: MATHEMATICALLY RECOMBINED FLUID CALCULATED PROPERTIES .............. 16 TABLE 11: RESERVOIR FLUID PRELIMINARY RESULTS ............................ 16 TABLE 12: RESERVOIR FLUID ANALYSES ..................................... 17 TABLE 13: RESERVOIR FLUID CALCULATED PROPERTIES ........................... 18 PVT MEASUREMENTS ON RECOMBINED RESERVOIR FLUID TABLE 14: CONSTANT COMPOSITION EXPANSION RESULTS AT 158OF .................. 20 TABLE 15: DV OIL PHASE PROPERTIES ...................................... 24 TABLE 16: DV GAS PHASE PROPERTIES ...................................... 28 TABLE 17: DV GAS COMPOSITIONS (MOLE %) ................................. 33 TABLE 18: DV RESIDUAL LIQUID COMPOSITION (MOLE %) ........................ 35 TABLE 19: RESERVOIR OIL VISCOSITY ...................................... 36 TABLE 20: SEPARATION TEST OIL PHASE PROPERTIES ........................... 38 TABLE 21: SEPARATION TEST GAS COMPOSITIONS ............................... 40 TABLE 22: SEPARATION TEST RESIDUAL LIQUID COMPOSITION (MOLE %) .............. 41 TABLE 23: SEPARATION TEST CORRECTION FOR DIFFERENTIAL VAPORIZATION ........... 42 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 5 EXECUTIVE SUMMARY Objective To evaluate the validity of the separator gases and liquids. Subsequently, recombine them to obtain reservoir fluid and measure its composition, phase behavior and transport properties. Introduction At the request of Phillips Alaska, Oilphase has conducted a fluid analysis study on separator fluid samples collected from Palm 1A well in the Palm field. Subsequently, the separator set was recombined to obtain the reservoir fluid. PVT measurements were conducted on the recombined reservoir fluid. Scope of Work • Homogenize separator fluid samples at the separator conditions with rocking. • Validate their integrity by measuring their compositions and bubblepoint pressure at separator temperature for the liquids. • Recombine the selected separator samples at a GLR of 360 SCF/sep. bbl. to generate the reservoir fluid. • Conduct a Constant Composition Expansion (CCE) test at the reservoir temperature. • Conduct differential vaporization at the reservoir temperature. • Conduct a single-stage separation test at the specified conditions. • Also conduct viscosity measurements of the oil at the reservoir temperature. Results The following bullets summarize the PVT analysis conducted on the bottomhole hydrocarbon samples: • The separator samples were homogenized at the separator conditions and were validated. • The separator liquid bubblepoint pressures were measured to be in the range of 280 – 290 psia at the separator temperature. The separator pressure was 283 psia. Hence, the separator liquids were valid for further analyses. • The separator gas compositions were similar. • Sample# 1.01 and 1.02 were selected and recombined at the GOR of 360 SCF/sep. bbl. to obtain the reservoir fluid. The reservoir fluid was homogenized at the reservoir conditions. • The bubblepoint pressure of the recombined reservoir fluid was measured to be 2737 psia at the reservoir temperature of 158oF and the fluid compressibility was measured to be 10.45 x 10-6 1/ psia at the bubblepoint pressure. • The reservoir fluid viscosity was measured to be 2.015 cP at the reservoir conditions. The stock-tank oil viscosity at 158oF was 5.834 cP. • The PVT results for the reservoir fluid are summarized in the table below: Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 6 Gas-Oil Ratio Oil Volume Factor at Pb API Gravity (SCF/STB) (bbl/STB) Zero Flash 494 1.254 26.1 Differential Vaporization 519 1.269 25.8 Single-Stage Separation test 471 1.238 26.7 Chain of Sample Custody The two sets of separator samples were received at Oilphase in Houston, Texas. They were homogenized at the separator conditions and used for validity check and for recombination to obtain reservoir fluids. Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 7 RESULTS AND DISCUSSIONS Fluids Preparation and Analysis Two sets of separator samples were restored and homogenized to the separator conditions. The well and sample details are presented in Table 1. Subsequently, the integrity of the separator liquid samples was checked by measuring their opening pressures. They are reported in Table 2. Subsequently, sub-samples from the separator gases were used to measure their molecular compositions using the gas chromatograph. The results are presented in Table 3. Both the samples possess similar properties. Sub-samples from the homogenized separator liquids were used to conduct zero flash to measure their gas-oil ratio (GOR) and stock- tank oil (STO) density and molecular weight. Also, another sub -sample was used to measure the bubblepoint pressure at the separator temperature. These results are tabulated in Table 4. The flashed gas and residual liquid from the zero flash of each separator liquid was used to measure their molecular compositions using gas chromatography. Subsequently, they were mathematically recombined to obtain the separator liquid composition by using the measured GOR. The results are presented in Tables 5 – 8. Table 1: Well and Sample Identification Well Palm 1A Field Palm Reservoir Pressure (psia) 3580 Reservoir Temperature (oF) 158 Study Samples Separator Conditions Sample ID Cylinder ID Sample Type Sampling Date Pressure (psia) (oF) 1.01 MM33037 Sep Rec Gas 4-Apr-2001 283 82 1.02 CSB 6589-MA Sep Rec Oil 4-Apr-2001 283 82 1.03 MM33065 Sep Rec Gas 5-Apr-2001 283 82 1.04 CSB 6590-MA Sep Rec Oil 5-Apr-2001 283 82 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 8 Table 2: Sampling and Transfer Summary Sample ID Transfer Closing Opening Sample Cylinder # conditions in conditions in Volume the field the Lab (psia/oF) (psia/oF) (cc) 1.01 MM33037 315/65 325/70 20 Lit. 1.02 CSB 6589-MA 60/65 90/71 600 1.03 MM33065 265/65 285/70 20 Lit. 1.04 CSB 6590-MA 75/65 102/71 600 Table 3: Separator Gases Composition Separator Gases from the field Conditions (Pressure/Temperature) Sample ID 1.01 1.03 Cylinder ID MM33037 MM33065 Components Mole % Mole % Nitrogen 0.27 0.26 Carbon Dioxide 0.67 0.65 Hydrogen Sulfide 0.00 0.00 Methane 87.35 86.52 Ethane 7.37 7.31 Propane 2.82 2.82 I - Butane 0.34 1.06 N - Butane 0.63 0.63 I - Pentane 0.18 0.39 N - Pentane 0.15 0.16 pseudo C6H14 0.10 0.10 pseudo C7H16 0.05 0.05 pseudo C8H18 0.04 0.04 pseudo C9H20 0.01 0.01 pseudo C10H22 0.00 0.00 pseudo C11H24 0.00 0.00 C12 Plus 0.00 0.00 Total 100 100 MW 18.84 19.24 Mole % C7+ 0.10 0.10 MW of C7+ 102.7 102.5 Relative Density (Air = 1) 0.650 0.664 Dry Gross Heat Content (BTU/scf) 1139 1162 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 9 Wet Gross Heat Content (BTU/scf) 1119 1141 Table 4: Separator Fluid Properties Sample ID 1.02 1.04 Units Cylinder ID CSB 6589-MA CSB 6590-MA Separator Liquid Properties "Zero" Flash GLR1 87 89 SCF/STB Shrinkage Factor @ Pb 0.946 0.945 VSTO/VT,P Bubblepoint Pressure at 82oF 283 293 psia Molar Mass of Separator Fluid 213.43 213.75 daltons Flashed Stock-Tank Liquid Molar Mass 246.52 247.74 daltons Density (@ 60 oF) 0.893 0.893 g/cc API Gravity 27.04 26.99 oAPI Asphaltene content 1.10 n/d % w/w Wax content 1.730 n/d % w/w Pour point temperature < -65 n/d o F Wax Appearance temperature (WAT) 63.7 n/d o F 1 Flashed gas volume (scf) per barrel of stock tank liquid @ 60oF Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 10 Table 5: Separator Liquid Composition (Sample# 1.02) (Sample 1.02; CSB 6589-MA) Components Flashed Liquid Flashed Gas Monophasic Fluid Mole % Mass % Mole % Mass % Mole % Mass % Nitrogen 0.00 0.00 0.36 0.32 0.05 0.01 Carbon Dioxide 0.00 0.00 0.84 1.20 0.13 0.03 Hydrogen Sulfide 0.00 0.00 0.00 0.00 0.00 0.00 Methane 0.00 0.00 47.08 24.38 7.23 0.54 Ethane 0.34 0.04 19.98 19.39 3.35 0.47 Propane 1.29 0.23 17.69 25.17 3.81 0.79 I - Butane 0.53 0.12 2.79 5.24 0.88 0.24 N - Butane 1.96 0.46 6.44 12.09 2.65 0.72 I - Pentane 1.18 0.34 1.62 3.76 1.24 0.42 N - Pentane 1.78 0.52 1.53 3.57 1.74 0.59 pseudo C6H14 2.91 0.99 0.96 2.60 2.61 1.03 pseudo C7H16 4.91 1.91 0.53 1.65 4.24 1.91 pseudo C8H18 6.92 3.00 0.16 0.56 5.88 2.95 pseudo C9H20 5.93 2.91 0.02 0.06 5.02 2.85 pseudo C10H22 5.27 2.87 0.00 0.00 4.46 2.80 pseudo C11H24 5.07 3.02 0.00 0.00 4.29 2.95 pseudo C12H26 4.18 2.73 0.00 0.00 3.53 2.67 pseudo C13H28 4.96 3.52 0.00 0.00 4.20 3.45 pseudo C14H30 4.39 3.39 0.00 0.00 3.72 3.31 pseudo C15H32 3.90 3.26 0.00 0.00 3.30 3.18 pseudo C16H34 3.55 3.20 3.00 3.12 pseudo C17H36 2.49 2.39 2.10 2.34 pseudo C18H38 2.73 2.78 2.31 2.72 pseudo C19H40 2.71 2.89 2.29 2.82 pseudo C20H42 2.07 2.31 1.75 2.25 pseudo C21H44 1.96 2.31 1.66 2.26 pseudo C22H46 1.76 2.15 1.49 2.10 pseudo C23H48 1.64 2.07 1.39 2.03 pseudo C24H50 1.41 1.85 1.19 1.81 pseudo C25H52 1.34 1.83 1.13 1.79 pseudo C26H54 1.28 1.81 1.08 1.77 pseudo C27H56 1.13 1.65 0.96 1.62 pseudo C28H58 1.05 1.58 0.89 1.54 pseudo C29H60 1.08 1.68 0.92 1.64 C30+ 18.32 40.19 15.50 39.30 Total 100 100 100 MW 246.52 30.98 213.43 MW C30+ 540.99 540.99 Mole Ratio 0.8465 0.1535 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 11 Table 6: Separator Liquid Calculated Properties (Sample# 1.02) (Sample 1.02; CSB 6589-MA) Properties Flashed Liquid Flashed Gas Monophasic Fluid Mole % C7+ 90.03 0.71 76.32 C12+ 61.93 0.00 52.42 C20+ 33.03 0.00 27.96 Molar Mass C7+ 266.40 99.15 266.16 C12+ 332.69 - 332.69 C20+ 443.58 - 443.58 Density C7+ 0.904 - - C12+ 0.933 - 0.933 C20+ 0.980 - 0.980 Fluid at 60oF 0.893 - - Gas Relative Density (Air = 1) - 1.070 - Dry Gross Heat Content (BTU/scf) - 1787 - Wet Gross Heat Content (BTU/scf) - 1756 - Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 12 Table 7: Separator Liquid Composition (Sample# 1.04) (Sample 1.04; CSB 6590-MA) Components Flashed Liquid Flashed Gas Monophasic Fluid Mole % Mass % Mole % Mass % Mole % Mass % Nitrogen 0.00 0.00 0.19 0.18 0.03 0.00 Carbon Dioxide 0.00 0.00 0.83 1.18 0.13 0.03 Hydrogen Sulfide 0.00 0.00 0.00 0.00 0.00 0.00 Methane 0.00 0.00 46.96 24.31 7.36 0.55 Ethane 0.22 0.03 19.87 19.28 3.30 0.46 Propane 1.20 0.21 17.78 25.29 3.80 0.78 I - Butane 0.55 0.13 3.27 6.14 0.98 0.27 N - Butane 2.11 0.50 6.46 12.11 2.79 0.76 I - Pentane 1.29 0.38 1.84 4.29 1.38 0.46 N - Pentane 2.02 0.59 1.50 3.48 1.94 0.65 pseudo C6H14 3.35 1.13 0.83 2.25 2.95 1.16 pseudo C7H16 5.29 2.05 0.36 1.13 4.52 2.03 pseudo C8H18 7.26 3.13 0.09 0.32 6.13 3.07 pseudo C9H20 6.08 2.97 0.01 0.05 5.12 2.90 pseudo C10H22 5.26 2.84 0.00 0.00 4.43 2.78 pseudo C11H24 4.84 2.87 0.00 0.00 4.09 2.81 pseudo C12H26 3.94 2.56 0.00 0.00 3.32 2.50 pseudo C13H28 4.24 3.00 0.00 0.00 3.58 2.93 pseudo C14H30 4.14 3.18 0.00 0.00 3.49 3.10 pseudo C15H32 3.87 3.22 0.00 0.00 3.26 3.15 pseudo C16H34 3.53 3.17 2.98 3.10 pseudo C17H36 2.43 2.32 2.05 2.27 pseudo C18H38 2.74 2.77 2.31 2.71 pseudo C19H40 2.80 2.98 2.36 2.91 pseudo C20H42 1.92 2.13 1.62 2.08 pseudo C21H44 1.87 2.20 1.58 2.15 pseudo C22H46 1.81 2.20 1.53 2.15 pseudo C23H48 1.61 2.02 1.35 1.98 pseudo C24H50 1.40 1.82 1.18 1.78 pseudo C25H52 1.32 1.79 1.11 1.75 pseudo C26H54 1.20 1.69 1.01 1.65 pseudo C27H56 1.14 1.65 0.96 1.62 pseudo C28H58 1.09 1.63 0.92 1.59 pseudo C29H60 1.04 1.60 0.87 1.56 C30+ 18.46 41.24 15.56 40.31 Total 100 100 100 MW 247.74 30.99 213.75 MW C30+ 553.56 553.56 Mole Ratio 0.8432 0.1568 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 13 Table 8: Separator Liquid Calculated Properties (Sample# 1.04) (Sample 1.04; CSB 6590-MA) Properties Flashed Liquid Flashed Gas Monophasic Fluid Mole % C7+ 89.26 0.47 75.33 C12+ 60.53 0.00 51.04 C20+ 32.84 0.00 27.69 Molar Mass C7+ 269.33 98.99 269.17 C12+ 340.37 - 340.37 C20+ 452.47 - 452.47 Density C7+ 0.905 - - C12+ 0.936 - 0.936 C20+ 0.981 - 0.981 Fluid at 60oF 0.893 - - Gas Relative Density (Air = 1) - 1.070 - Dry Gross Heat Content (BTU/scf) - 1790 - Wet Gross Heat Content (BTU/scf) - 1759 - Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 14 PVT Analysis on Recombined Reservoir Fluid Sample# 1.01 and 1.02 were selected for recombination using a separator GLR of 360 SCF/sep. bbl. The fluid compositions were combined mathematically to obtain the reservoir fluid composition. The calculations are presented in Table 9 and 10. Subsequently, the samples were recombined to obtain the reservoir fluid. The fluid was homogenized at the reservoir conditions for a day. Sub-samples were then used to conduct measurements. A sub-sample was used to conduct zero flash to measure the gas-oil ratio (GOR) of the reservoir fluid. Also, the stock-tank oil (STO) density and molecular weights were measured. These preliminary results are tabulated in Table 11. The flashed gas and the residual liquid from the zero flash were used to measure their molecular composition using gas chromatography. Their compositions are presented in Table 12. Also, the reservoir fluid composition calculated from the flashed gas and residual liquid compositions using the zero flash GOR is reported. Using these composition, the plus fraction properties were calculated and are reported in Table 13. Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 15 Table 9: Mathematically Recombined Reservoir Fluid (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Separator Gas Sample 1.01 Separator Oil Sample 1.02 Components Numerically Recombined Reservoir Fluid Nitrogen 0.14 Carbon Dioxide 0.35 Hydrogen Sulfide 0.00 Methane 39.35 Ethane 4.96 Propane 3.41 I - Butane 0.66 N - Butane 1.84 I - Pentane 0.82 N - Pentane 1.10 pseudo C6H14 1.60 pseudo C7H16 2.56 pseudo C8H18 3.54 pseudo C9H20 3.01 pseudo C10H22 2.67 pseudo C11H24 2.57 pseudo C12H26 2.12 pseudo C13H28 2.52 pseudo C14H30 2.23 pseudo C15H32 1.98 pseudo C16H34 1.80 pseudo C17H36 1.26 pseudo C18H38 1.39 pseudo C19H40 1.37 pseudo C20H42 1.05 pseudo C21H44 0.99 pseudo C22H46 0.89 pseudo C23H48 0.83 pseudo C24H50 0.71 pseudo C25H52 0.68 pseudo C26H54 0.65 pseudo C27H56 0.57 pseudo C28H58 0.53 pseudo C29H60 0.55 C30+ 9.29 Total 100 MW 135.43 MW of C30+ 540.99 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 16 Table 10: Mathematically Recombined Fluid Calculated Properties (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Separator Gas Sample 1.01 Separator Oil Sample 1.02 Components Numerically Recombined Reservoir Fluid Mole % C7+ 45.77 C12+ 31.41 C20+ 16.75 Molar Mass C7+ 167.40 C12+ 332.68 C20+ 443.58 Density C7+ - C12+ 0.932 C20+ 0.978 Table 11: Reservoir Fluid Preliminary Results (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Separator Gas Sample 1.01 Units Separator Oil Sample 1.02 Reservoir Liquid Properties "Zero" Flash GLR 494 SCF/STB Shrinkage 0.7978 VSTO/VT,P Bubblepoint Pressure at 158oF 2737 psia Molar Mass of Recombined Fluid 136.00 daltons Flashed Stock-Tank Liquid Molar Mass 256.76 daltons Density (@ 60 oF) 0.8976 g/cc API Gravity 26.14 oAPI Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 17 Table 12: Reservoir Fluid Analyses (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Components Flashed Liquid Flashed Gas Monophasic Fluid Mole % Mass % Mole % Mass % Mole % Mass % Nitrogen 0.00 0.00 0.13 0.17 0.07 0.01 Carbon Dioxide 0.00 0.00 0.65 1.28 0.33 0.11 Hydrogen Sulfide 0.00 0.00 0.00 0.00 0.00 0.00 Methane 0.00 0.00 77.39 55.69 39.86 4.70 Ethane 0.05 0.01 9.53 12.85 4.93 1.09 Propane 0.36 0.06 6.32 12.51 3.43 1.11 I - Butane 0.21 0.05 1.08 2.81 0.66 0.28 N - Butane 0.89 0.20 2.65 6.90 1.79 0.77 I - Pentane 0.79 0.22 0.85 2.76 0.82 0.44 N - Pentane 1.35 0.38 0.78 2.52 1.06 0.56 pseudo C6H14 2.88 0.94 0.40 1.52 1.60 0.99 pseudo C7H18 4.66 1.74 0.17 0.72 2.34 1.66 pseudo C8H18 6.57 2.74 0.04 0.21 3.21 2.53 pseudo C9H20 5.50 2.59 0.01 0.04 2.67 2.38 pseudo C10H22 6.49 3.39 0.00 0.00 3.15 3.10 pseudo C11H24 5.59 3.20 0.00 0.01 2.71 2.93 pseudo C12H26 4.82 3.02 0.00 0.00 2.34 2.77 pseudo C13H28 4.74 3.23 0.00 0.00 2.30 2.96 pseudo C14H30 4.66 3.45 0.00 0.00 2.26 3.16 pseudo C15H32 4.21 3.38 0.00 0.00 2.04 3.09 pseudo C16H34 3.72 3.21 1.80 2.94 pseudo C17H36 2.57 2.37 1.24 2.17 pseudo C18H38 3.13 3.06 1.52 2.80 pseudo C19H40 2.90 2.97 1.41 2.72 pseudo C20H42 2.19 2.35 1.06 2.15 pseudo C21H44 2.11 2.39 1.02 2.19 pseudo C22H46 1.89 2.21 0.92 2.03 pseudo C23H48 1.70 2.07 0.83 1.89 pseudo C24H50 1.57 1.98 0.76 1.82 pseudo C25H52 1.46 1.92 0.71 1.75 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 18 pseudo C26H54 1.26 1.71 0.61 1.57 pseudo C27H56 1.14 1.59 0.55 1.46 pseudo C28H58 1.04 1.51 0.50 1.38 pseudo C29H60 1.09 1.61 0.53 1.48 C30+ 18.47 40.45 8.96 37.03 Total 100 100 100 100 100 100 MW 256.76 22.29 136.00 MW of C30+ 562 562 MOLE RATIO 0.4849 0.5151 Table 13: Reservoir Fluid Calculated Properties (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Properties Flashed Liquid Flashed Gas Monophasic Fluid Mole % C7+ 93.47 0.22 45.44 C12+ 64.66 0.00 31.36 C20+ 33.92 - 16.45 Mass % C7+ 98.14 0.99 89.94 C12+ 84.48 0.01 77.35 C20+ 59.79 - 54.74 Molar Mass C7+ 269.59 99.62 269.17 C12+ 335.47 - 335.47 C20+ 452.61 - 452.61 Density C7+ 0.905 - - C12+ 0.933 - 0.933 C20+ 0.981 - 0.981 Fluid at 60oF 0.898 - - Gas Relative Density (Air = 1) - 0.770 - Dry Gross Heat Content (BTU/scf) - 1328 - Wet Gross Heat Content - 1305 - Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 19 (BTU/scf) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 20 Constant Composition Expansion The CCE study was initiated by charging a sub-sample of live reservoir fluid into the PVT cell at a reservoir temperature of 158oF and at a pressure of 10,015 psia. Sequential pressure decrease in steps and the corresponding volume changes are presented in Table 14. The pressure-volume (P-V) plots of the CCE data are presented in Figure 1. The intersection of the single -phase and two-phase lines in the P-V plot and the visual observation was used to define the bubblepoint. For the subject fluid, the bubblepoint was determined to be 2,737 psia at the reservoir temperature of 158oF. For the diphasic region, the liquid volumes are also measured and are reported in Table 14. The percentage liquid volume as a function of pressure is presented in Figure 2. Also, calculated relative volume and oil compressibility is presented in Table 14. As seen in the table, the compressibility of this oil is 10.45 x 10-6 1/psia at the saturation pressure. Constant Composition Expansion of Reservoir Fluid (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 14: Constant Composition Expansion Results at 158oF Pressure Relative Volume Liquid Volume Oil Compressibility (psia) (vol/vol at Pb) (% of liquid vol at Pb) *10-6 (1/psia) 10015 0.9484 6.48 8020 0.9609 6.61 6025 0.9739 6.96 5015 0.9809 7.35 4015 0.9885 8.09 Pi 3580 0.9921 8.62 3315 0.9944 9.05 2925 0.9981 9.90 Pb 2737 1.0000 100.00 10.45 2670 1.0057 99.77 2525 1.0192 99.20 2392 1.0336 98.63 2160 1.0657 97.74 1960 1.1003 96.85 1650 1.1789 95.66 1333 1.3105 94.33 1006 1.5514 92.99 747 1.9096 92.00 608 2.2768 91.44 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 21 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 22 Constant Composition Expansion of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 1: CCE Relative Volume 0.80 1.00 1.20 1.40 1.60 1.80 2.00 2.20 2.40 0 2000 4000 6000 8000 10000 12000 Pressure (psia) Re l a t i v e V o l u m e ( v o l / v o l a t P b ) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 23 Constant Composition Expansion of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 2: CCE % Liquid Volume 92.00 94.00 96.00 98.00 100.00 500 1000 1500 2000 2500 3000 Pressure (psia) % L i q u i d V o l u m e Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 24 Differential Vaporization Results of the differential vaporization test are presented in Tables 15 through 18 and graphically presented in Figures 3 through 9. Oil Phase Properties The oil properties such as oil formation volume factor, oil density and solution Gas-Oil-ratios are summarized in Table 15. The oil formation volume factor is presented as a function of differential pressures in Figure 3. As expected, the oil formation volume factor increases with decreasing pressure until the bubblepoint, and subsequently, decreases with decreasing pressure. Solution GOR shows a decreasing trend with decreasing pressures (Figure 4). Oil densities were measured at the initial and the saturation pressure conditions and the intermediate values are calculated based on known mass and measured volume. The liquid density is measured to be 0.782 g/cc at the bubblepoint pressure (Table 15). The liquid density decreases with decreasing pressure until the bubblepoint, and increases with further decrease in pressure (Figure 5). Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 15: DV Oil Phase Properties Pressure Oil Volume Gas-Oil Liquid Factor (Bo) Ratio Density (psia) (bbl/STB) (SCF/STB) (g/cc) 10015 1.203 0.825 8020 1.219 0.814 6025 1.236 0.803 5015 1.245 0.797 4015 1.254 0.791 Pi 3580 1.259 0.788 3315 1.262 0.787 2925 1.266 0.784 Pb 2737 1.269 519 0.782 2211 1.243 445 0.790 1764 1.220 385 0.798 1338 1.193 319 0.808 897 1.160 248 0.822 466 1.120 156 0.839 14.696 1.038 0 0.864 Residual oil density at 60oF (g/cc) : 0.900 API Gravity : 25.8 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 25 Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 3: DV Oil Volume Factor (Bo) 1.00 1.05 1.10 1.15 1.20 1.25 1.30 0 2000 4000 6000 8000 10000 12000 Pressure (psia) O i l V o l u m e F a c t o r Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 26 Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 4: DV Gas-Oil Ratio (Rs) 0 100 200 300 400 500 600 0 500 1000 1500 2000 2500 3000 Pressure (psia) G a s - O i l R a t i o ( S C F / S T B ) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 27 Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 5: DV Liquid Density (g/cc) 0.76 0.78 0.80 0.82 0.84 0.86 0.88 0 2000 4000 6000 8000 10000 12000 Pressure (psia) Li q u i d D e n s i t y ( g / c c ) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 28 Gas Phase Properties The calculated differentially vaporized gas properties are summarized in Table 16 and graphically presented in Figures 6 through 9. As seen in the table and figures, gas volume factor and the gas deviation factor show an increasing trend with a decrease in pressure. The gas relative density values of the liberated gas tend to decrease slightly and then increase with a decreasing function of pressure. However, the gas viscosity that is calculated at the differential pressure steps from gas composition decrease with decrease in pressure as seen in Figure 9. Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 16: DV Gas Phase Properties Pressure Gas Volume Gas Deviation Gas Viscosity Gas Relative Factor (Bg) Factor (Z) Density (Air = 1) 2737 2211 0.0068 0.865 0.0170 0.652 1764 0.0086 0.870 0.0156 0.645 1338 0.0115 0.882 0.0143 0.641 897 0.0176 0.906 0.0131 0.652 466 0.0353 0.942 0.0117 0.695 14.696 1.1882 1.000 0.0077 1.187 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 29 Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 6: DV Gas Volume Factor (Bg) 0.00 0.01 0.02 0.03 0.04 0.05 0 500 1000 1500 2000 2500 3000 Pressure (psia) G a s V o l u m e F a c t o r Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 30 Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 7: DV Gas Deviation Factor (Z) 0.85 0.90 0.95 1.00 1.05 0 500 1000 1500 2000 2500 3000 Pressure (psia) G a s D e v i a t i o n F a c t o r Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 31 Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 8: DV Gas Relative Density (Air = 1) 0.6 0.7 0.8 0.9 1.0 1.1 1.2 0 500 1000 1500 2000 2500 3000 Pressure (psia) G a s R e l a t i v e D e n s i t y ( A i r = 1 ) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 32 Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 9: DV Gas Viscosity (cP) 0.005 0.008 0.011 0.014 0.017 0.020 0 500 1000 1500 2000 2500 3000 Pressure (psia) G a s V i s c o s i t y ( c P ) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 33 Compositions Compositions of the differentially liberated gas at each differential pressure step are presented in Table 17 along with calculated molecular weights. As seen in the table, and as expected, the concentrations of the heavier components in the liberated gas decreases with a decrease in pressure due to the inability of the gas to supercritically extract heavy ends at lower pressures. However, below 1,338 psia, the concentration of intermediate/heavy components (>C3) of the liberated gas increases as there partial pressures become significant. Composition of the residual oil obtained from the differential vaporization is presented in Table 18. The API Gravity of the residual oil is measured to be 25.8. Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 17: DV Gas Compositions (mole %) Pressure Step (psia) 2211 1764 1338 897 466 14.696 Components Nitrogen 0.67 0.53 0.38 0.23 0.09 0.00 Carbon Dioxide 0.54 0.55 0.58 0.65 0.76 0.86 Hydrogen Sulfide 0.00 0.00 0.00 0.00 0.00 0.00 Methane 89.33 89.43 89.41 87.98 83.21 47.37 Ethane 5.00 5.28 5.67 6.64 9.22 17.22 Propane 2.14 2.26 2.23 2.64 3.79 14.12 i - Butane 0.31 0.33 0.38 0.41 0.57 2.46 n - Butane 0.74 0.68 0.62 0.71 1.11 6.63 i - Pentane 0.27 0.24 0.20 0.20 0.36 2.52 n - Pentane 0.32 0.23 0.18 0.19 0.36 2.68 Pseudo - Hexanes 0.30 0.22 0.16 0.17 0.24 2.32 Pseudo - Heptanes 0.26 0.17 0.12 0.12 0.19 1.93 Pseudo - Octanes 0.12 0.07 0.05 0.04 0.06 1.20 Pseudo - Nonanes 0.01 0.01 0.02 0.02 0.02 0.43 Pseudo - Decanes 0.00 0.00 0.00 0.00 0.00 0.24 Pseudo - Undecanes 0.00 0.00 0.00 0.00 0.00 0.03 Dodecanes Plus 0.00 0.00 0.00 0.00 0.00 0.00 Total 100 100 100 100 100 100 MW 18.88 18.69 18.57 18.88 20.14 34.39 Relative Density (air = 1) 0.652 0.645 0.641 0.652 0.695 1.187 Wet Gross Heat Content (BTU/scf) 1139 1131 1126 1143 1210 1983 Dry Gross Heat Content 1119 1111 1106 1123 1189 1948 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 34 (BTU/scf) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 35 Differential Vaporization of Reservoir Fluid at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 18: DV Residual Liquid Composition (mole %) Components Liquid (mole %) Methane 0.00 Ethane 0.11 Propane 0.83 i - Butane 0.34 n - Butane 1.26 i - Pentane 0.83 n - Pentane 1.33 Pseudo - Hexanes 2.59 Pseudo - Heptanes 4.36 Pseudo - Octanes 6.54 Pseudo - Nonanes 6.03 Pseudo - Decanes 5.58 Pseudo - Undecanes 5.06 Dodecanes Plus 65.15 Total 100 MW 255 C12+ MW 332 API Gravity 25.8 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 36 Reservoir Oil Viscosity The liquid phase viscosity was measured at the reservoir temperature of 158oF. These values as a function of selected pressure steps are summarized in Table 19. The liquid phase viscosity values are graphically presented in Figure 10. As seen in the figures and as expected, the viscosity values decrease with decreasing pressure up to the bubblepoint pressure and increase with pressure above the bubblepoint pressure. Viscosity of Reservoir Oil at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 19: Reservoir Oil Viscosity Pressure Oil Viscosity (psia) (cP) 10091 3.564 8020 2.954 6016 2.500 5016 2.296 4021 2.107 Pi 3580 2.015 2757 1.866 Pb 2737 1.859 2020 2.220 1598 2.540 1019 3.180 516 3.970 281 4.510 77 5.580 15 5.834 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 37 Viscosity of Reservoir Oil at 158oF (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 10: Reservoir Oil Viscosity 1.0 2.0 3.0 4.0 5.0 6.0 0 2000 4000 6000 8000 10000 12000 Pressure (psia) O i l V i s c o s i t y ( c P ) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 38 Single-Stage Separation Test Single-stage separation test results are presented in Tables 20 - 22. The fluid properties (i.e., GOR, density and oil formation volume factor) are presented in Table 20. Single-stage separation test conditions are 80 psia/130oF, and 14.696 psia/60oF. As seen in Table 20, the GOR value obtained from the multi-stage separation test is 471 SCF/STB and the formation volume factor is 1.238. The compositional analyses of separator gas and tank gas are summarized in Table 21 and the composition of tank liquid is tabulated in Table 22. The total dry gross heat content of the separation gases is calculated to be 1251 BTU/scf whereas the total wet gross heat content is calculated to be 1229 BTU/scf. With reference to the assumption made in “The Properties of Petroleum Fluids” (McCain, 1990), the assumption made in generating reservoir fluid properties from a PVT study is that at pressures below the bubblepoint, the process in the reservoir can be mimicked by differential vaporization, while the process in the wellbore is simulated by the separator test. Hence, fluid properties at pressures below saturation pressure can be calculated by combining the data from the differential vaporization and a separator test. The differential vaporization flashes that occur in the reservoir at the reservoir temperature (158oF) would liberate more gas than flashes that occur during multi-stage separation test conducted at variable temperatures lower than the reservoir temperature. This expectation held true in this study and the overall solution GOR and Bo did see a significant decrease when the liberated data were combined with results of the separation test. Results are summarized in Table 23 and graphically presented in Figures 11 and 12. As seen in these figures, GOR and Bo values are decreased as the liberated reservoir oil is produced at the surface. Separation Test On Reservoir Fluid (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 20: Separation Test Oil Phase Properties Pressure Temperature GOR* Liquid Density Shrinkage Oil Separator Total Separator Tank Factor** Volume Factor*** (psia) (oF) (SCF/STB) (SCF/ST B) (g/cc) (g/cc) (STB/bbl at P) (bbl at Pb/STB) 2737 158 471 0.782 1.238 80 130 446 0.8755 0.973 14.696 60 25 0.894 1.000 * Flashed gas volume (scf) per barrel of stock tank liq @ 60F Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 39 ** Volume of flashed stock tank liquid volume @ 60oF per live oil at that pressure *** Volume of live oil at it’s bubblepoint pressure per flashed stock tank liquid volume @ 60oF Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 40 Separation Test On Reservoir Fluid (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 21: Separation Test Gas Compositions Mole % Separator Gas Tank Gas Pressure Step (psia) Temperature (F) Nitrogen 0.30 0.00 Carbon Dioxide 0.68 0.79 Hydrogen Sulfide 0.00 0.00 Methane 82.95 50.44 Ethane 8.23 18.10 Propane 4.55 16.25 i - Butane 0.71 3.49 n - Butane 1.33 6.45 i - Pentane 0.36 1.68 n - Pentane 0.31 1.50 Pseudo - Hexanes 0.22 0.79 Pseudo - Heptanes 0.25 0.38 Pseudo - Octanes 0.09 0.11 Pseudo - Nonanes 0.02 0.01 Pseudo - Decanes 0.00 0.00 Pseudo - Undecanes 0.00 0.00 Dodecanes Plus 0.00 0.00 Total 100 100 MW 20.39 30.29 Relative Density (air = 1) 0.704 1.046 Molar Ratio 0.9474 0.0526 Dry Gross Heat Content (BTU/scf) 1223 1756 Wet Gross Heat Content (BTU/scf) 1201 1726 Total Dry Gross Heat Content (BTU/scf) = 1251 Total Wet Gross Heat Content (BUT/scf) = 1229 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 41 Separation Test on Reservoir Fluid (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 22: Separation Test Residual Liquid Composition (mole %) Components Liquid (mole %) Methane 0.00 Ethane 0.55 Propane 1.18 i - Butane 0.40 n - Butane 1.86 i - Pentane 1.16 n - Pentane 1.66 Pseudo - Hexanes 3.03 Pseudo - Heptanes 4.62 Pseudo - Octanes 6.22 Pseudo - Nonanes 6.28 Pseudo - Decanes 5.67 Pseudo - Undecanes 5.32 Dodecanes Plus 62.05 Total 100 MW 248 C12+ MW 334 API Gravity 26.7 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 42 Separation Correction for Differential Vaporization (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Table 23: Separation Test Correction for Differential Vaporization Pressure Separator Corrected Solution GOR (Rs) FVF (Bo) (psia) (SCF/STB) (bbl/STB) 10015 1.174 8020 1.190 6025 1.206 5015 1.214 4015 1.224 Pi 3580 1.228 3315 1.231 2925 1.236 Pb 2737 471 1.238 2211 399 1.213 1764 340 1.190 1338 276 1.164 897 206 1.132 466 117 1.093 14.696 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 43 Separation Correction for Differential Vaporization (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 11: Separation Corrected Oil Volume Factor (Bo) 1.00 1.05 1.10 1.15 1.20 1.25 1.30 0 2000 4000 6000 8000 10000 12000 Pressure (psia) O i l V o l u m e F a c t o r Differential Vaporization Oil Volume Factor Separation Corrected Oil Volume Factor Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 44 Separation Correction for Differential Vaporization (Sample# 1.01 and 1.02 recombined at a GLR of 360 SCF/sep. bbl.) Figure 12: Separation Corrected Gas-Oil Ratio (Rs) 0 100 200 300 400 500 600 0 500 1000 1500 2000 2500 3000 Pressure (psia) G a s - O i l R a t i o ( S C F / S T B ) Differential Vaporization Gas-Oil Ratio Separation Corrected Gas-Oil Ratio Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 45 Appendix A: Nomenclature and Definitions API Gravity American Petroleum Institute gravity Bg Gas formation volume factor Bo Oil formation volume factor CCE Constant composition Expansion DV Differential Vaporization GOR Gas Oil Ratio LO Live Oil n Number of moles P Absolute pressure Pb Bubble point pressure PV Pressure-Volume Method Pi Initial Reservoir Pressure R Universal gas constant Rs Solution gas oil ratio T Temperature V Volume Vr Relative volume STO Stock Tank Oil %, w/w Weight Percent Z Gas deviation factor Dry Gross Heating Value is defined as the total energy transferred as heat in an ideal combustion reaction at a standard temperature and pressure in which all water formed appears as liquid. Wet Gross Heating Value is defined as the total energy transferred as heat in an ideal combustion reaction of water saturated gas at a standard temperature and pressure in which all water formed appears as liquid. Molar masses, densities and critical values of pure components are from CRC handbook of Chemistry and Physics and those of pseudo components are from Katz data. Gas viscosity is calculated from the correlation of Carr, Kobayshi and Burrows as given in the “Phase Behavior of Oilfield Hydrocarbon Systems” by M.B. Standing Compressibility in constant mass study is obtained from mathematical derivation of relative volume. Gas gravity is calculated from composition using the perfect gas equation (Gas deviation factor, Z=1) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 46 Appendix B: Molecular Weights and Densities Used Components MW Density (g/cc) Nitrogen 28.01 Carbon Dioxide 44.01 Hydrogen Sulfide 34.08 Methane 16.04 0.300 Ethane 30.07 0.356 Propane 44.10 0.508 I - Butane 58.12 0.567 N - Butane 58.12 0.586 I - Pentane 72.15 0.625 N - Pentane 72.15 0.631 pseudo C6H14 84 0.690 pseudo C7H16 96 0.727 pseudo C8H18 107 0.749 pseudo C9H20 121 0.768 pseudo C10H22 134 0.782 pseudo C11H24 147 0.793 pseudo C12H26 161 0.804 pseudo C13H28 175 0.815 pseudo C14H30 190 0.826 pseudo C15H32 206 0.836 pseudo C16H34 222 0.843 pseudo C17H36 237 0.851 pseudo C18H38 251 0.856 pseudo C19H40 263 0.861 pseudo C20H42 275 0.866 pseudo C21H44 291 0.871 pseudo C22H46 300 0.876 pseudo C23H48 312 0.881 pseudo C24H50 324 0.885 pseudo C25H52 337 0.888 pseudo C26H54 349 0.892 pseudo C27H56 360 0.896 pseudo C28H58 372 0.899 pseudo C29H60 382 0.902 Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 47 Appendix C: EQUIPMENT Fluids Preparation and Validation The opening pressure of the cylinder is measured using a Heise pressure gauge soon after the sample arrives in the laboratory. Subsequently, the separator oil sample bottle is pressurized to the separator pressure using nitrogen at the bottomside of the cylinder. Custom made heating jacket is wrapped around the cylinder to heat the sample bottle to the separator temperature. The sample bottle is then placed into a rocking stand and rocked for a day to homogenize the separator fluid. Live reservoir fluid and separator oil analysis is necessary in the sample validation process as well as during the completion of various fluid studies. A description of the experimental equipment used for these analyses follows. All live fluid analyses are completed with a JEFRI Gasometer. This unit in conjunction with GC analysis (see below) provides the full fluid compositional analysis, GOR, density at sampling P&T corrected to standard conditions. The JEFRI gasometer consists of a motor- driven piston in a stationary cylinder. The piston displacement is monitored to determine the swept volume of the cylinder. The cylinder pressure is automatically held at ambient pressure. Piston motion is tracked by a linear encoder, which is subsequently, converted to measure the gas volume in the cylinder. The total Gasometer volume is 10 L. The evolved gas can be re-circulated through the system to facilitate equilibrium at a maximum flow rate of 40 L/hr. The operating pressure of the Gasometer is ambient pressure (up to a maximum of 40 psia) and the operating temperature ranging from room temperature to 40oC. Following the flash of the live fluid sample to ambient conditions in the gasometer, compositional analysis of residual hydrocarbon liquid and evolved gas phase is conducted using gas chromatography (GC). Analysis of hydrocarbon liquids is conducted using an HP6890 liquid injection gas chromatograph equipped with flame ionization detector (FID). In this system, separation of individual components is carried out in a 30m long, 530µm diameter “Megabore” capillary column made of fused silica with 2.6-micrometer thick methyl silicone as the stationary phase. The operating temperature range of the stationary phase is 60 to 400oC. Over this temperature range, the components eluted are from C1 to C36 along with naphthenes and aromatics components. Based on the physical properties, these components are retarded in a segregated fashion by the stationary phase during the flow of carrier gas (helium) through the column. With prior knowledge of the amount of “retention” for known compounds contained in calibration standards, the same compounds can be identified in the unknown hydrocarbon sample by matching “retention” times. The relative concentration of each component is determined by the concentration of ions hitting the FID upon the elution of each component. The analysis of hydrocarbon gases is carried out using an HP6890 gas injection GC equipped with two separation columns. The first column is a combination of a 100 mesh packed column and 100 mesh molecular Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 48 sieve using high purity helium as a carrier gas. The molecular sieve is used to achieve separation of the light gaseous components (nitrogen, oxygen, and methane) while the packed column serves to separate ethane, propane, butanes, pentanes, and hexanes along with carbon dioxide and hydrogen sulfides. The second column is a packed column as described previously in liquid analysis. This column is capable of achieving separation of components up to C12+, along with the associated naphthenes and aromatics that are lumped into the C6+ fraction during analysis and reporting. Components up to C4 are analyzed using a thermal conductivity detector (TCD) while the C5+ components are analyzed for using an FID detector. The instrument has programmable air actuated multiport valves that allow the flow of the sample mixture to be varied between the two columns, and hence, allowing for the correct separation and analysis of the injected gas. Recombination Equipment The recombination of the surface samples takes place in a 2000 cc cell equipped with a piston and a heating jacket to control the pressure and temperature of the cell respectively. Digital gauges are mounted to read the temperature (0.1oC) and pressure (1 psia) accurately. Water- glycol mixture is used as the hydraulic fluid for pressure control. The sample side of the cell contains mixing balls to facilitate quick equilibrium and homogenization of the diphasic sample. Once, the separator samples are recombined to obtain a monophasic reservoir fluid, the sample is used for further studies. Fluid Volumetric (PVT) and Viscosity Equipment The preliminary saturation pressure, constant composition expansion (CCE), differential vaporization (DV), multi-stage separation tests (MSST) are measured using a pressure-volume-temperature (PVT) apparatus. The PVT apparatus consists of a variable volume, visual JEFRI PVT cell. The main component of the cell consists of a Pyrex glass cylinder 15.2-cm long with an internal diameter of 3.2 cm. An especially designed floating piston and a magnetically coupled impeller mixer are mounted inside the Pyrex cylinder to allow for mercury-free operation. The bottom section of the piston is furnished with o-rings to isolate the hydraulic fluid from the cell content. The piston allows liquid level measurements as small as 0.005 cc. The magnetically coupled impeller mixer, mounted on the bottom end cap of the PVT cell, allow quick equilibration of the hydrocarbon fluid. The effective volume of the cell is approximately 120 cm3. The Pyrex cylinder is housed inside a steel shell with vertical tempered glass plates to allow visual observation of the internal tube contents. A variable volume JEFRI displacement pump controls the volume, and hence, the pressure of the fluids under investigation by means of injection or withdrawal of transparent hydraulic fluid connected to the floating piston from the top of the JEFRI PVT cell. The same hydraulic fluid is also connected to the outer steel shell to maintain a balanced differential pressure on the Pyrex cylinder. The PVT cell is mounted on a special bracket, which can be rotated 360o. The bracket along with the PVT cell is housed inside a temperature controlled, forced air circulation oven. The cell temperature is measured with a platinum resistance thermal detector (RTD) and displayed on a digital indicator with an accuracy of 0.2oF. The cell Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 49 pressure is monitored with a calibrated digital Heise pressure gauge precise to ± 0.1% of full scale. The temperature and pressure ratings of this PVT system are 15,000 psi (103 MPa) and 360oF (182oC). The fluid volume in the PVT cell is determined using a cathetometer readable to the nearest 0.01 mm. The cathetometer is equipped with a high-resolution video camera that minimizes parallax in readings and uses a high-resolution encoder producing both linear and volumetric readings. The height measurements by the cathetometer have been precisely calibrated with the total cell volume prior to the start of the test. The floating piston is designed in the shape of a truncated cone with gradually tapered sides, which allows measurement of extremely small volumes of liquid (0.005 cm3) corresponding to roughly 0.01% of the cell volume. The viscosity of the live reservoir fluid is measured at the reservoir temperature and pressure conditions using Cambridge SPL440 electromagnetic viscometer, which consists of one cylindrical cell containing the fluid sample and a piston located inside the cylinder. The piston is moved back and forth through the fluid by imparting an electromagnetic force on the piston. Viscosity is measured by the motion of the piston, which is impeded by viscous flow around the annulus between the piston and the sample cylinder wall. Various sizes of pistons are used to measure the viscosity of various fluids having different levels of viscosity. The temperature is maintained at the experimental condition using a re-circulating fluid heating system. The internal temperature is monitored using an internal temperature probe. The temperature rating of the viscometer is 190oC and pressure rating is 15,000 psig. The accuracy is ±1.5% of full scale for each individual piston range. The total volume of fluid sample required for viscosity measurement is 5 cc. Appendix D: PROCEDURE Separator Fluids Preparation and Validation The valid separator oil samples are homogenized at the separator temperature and pressure. A sub sample is then subjected to single stage flash to determine the flash gas-oil-ratio (GOR) for the separator oil samples by using the atmospheric Gasometer. The flash gas and stock tank liquid compositions are analyzed using the Chromatographs. Subsequently, the separator oil composition is calculated using the single stage flash GOR and the flash gas and STO compositions. The separator gas is also analyzed using the gas chromatograph. A field GOR is used to mathematically recombine the separator gas and oil compositions to obtain the reservoir fluid composition. Recombination of Separator Samples The chosen separator gas and liquid samples are stabilized to a known pressure and separator temperature in two different bottles. A known volume of separator gas is first charged to the recombination cell (which is maintained at the separator temperature) and the cell is allowed to stabilize at that pressure. From the GOR value, the volume of separator liquid at separator condition to be added to the Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 50 gas to obtain the reservoir fluid is determined. After adding the separator liquid, the diphasic fluid is pressurized to the reservoir pressure and rocked several times to homogenize it. The monophasic fluid is allowed to stabilize at the reservoir conditions and then a sub-sample is taken for individual experiments. Reservoir fluid Validation After homogenizing, a small portion of the single-phase reservoir fluid is isobarically transferred into the PVT cell at the reservoir temperature. Subsequently, a quick P-V relationship is established to determine the saturation pressure. Constant Composition Expansion Procedure A sub-sample of the test fluid is initially charged to the PVT apparatus and the system temperature stabilized at the reservoir temperature. The CCE experiment is then conducted by incrementally reducing the pressure from some pressure above the bubblepoint pressure to a pressure well below the bubblepoint pressure in a number of discrete steps. At each pressure step, the magnetic stirrer is used to make sure that the subject fluid achieved equilibrium. Total fluid volume (with visual observation of a single or two phase condition in the cell) is measured at each pressure stage, and subsequently, a pressure-volume (P-V) plot is created identifying the phase state at each P-V condition. The intersection of the two lines plotted using the pressure and volume data above and slightly below the observed phase change corresponded to the measured saturation pressure of the fluid. In this manner, the P-V plot confirms the saturation pressure observed visually in the PVT cell. The measured pressure and volume data a re then used to compute live oil compressibility above the bubblepoint pressure and relative oil volumes over the entire pressure range. Differential Vaporization Procedure Subsequent to the completion of the CCE experiment, another sub- sample of the test fluid is charged to the PVT apparatus and the cell contents are then mixed with the magnetic mixer to allow for phase equilibration at the reservoir temperature and pressure conditions. A differential vaporization (DV) experiment is then conducted by incrementally reducing the pressure in the PVT cell in discrete steps. In these steps, the pressure is reduced below the saturation pressure, and hence, allowing the gas phase to evolve. A typical pressure stage in a DV test is described below: • The pressure in the PVT cell is reduced to a pressure just above the bubblepoint pressure of the oil. This is the starting point of the DV test. • The pressure of the fluid is then reduced to the first pressure stage (below the bubblepoint pressure) of the DV test allowing free gas to evolve. The magnetic mixer is then used to achieve equilibration between the free gas and the pressurized liquid. • The evolved gas phase is then isobarically removed from the PVT cell into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure (see Fluid Analysis Equipment Section) Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 51 • The previous two steps are repeated until either an atmospheric pressure or a predetermined abandonment pressure is reached. Multi-Stage Separation Test Subsequent to the completion of the DV experiment, another sub-sample of the test fluid is charged to the PVT apparatus and the cell contents are then mixed with the magnetic mixer to allow for phase equilibration at the reservoir temperature and pressure conditions. A multi-stage separation experiment is then conducted by incrementally reducing the pressure and temperature conditions in the PVT cell in discrete steps. In these steps, the pressure is reduced below the saturation pressure, and hence, allowing the gas phase to evolve. A typical pressure stage in a separation test is described below: • The pressure in the PVT cell is reduced to a pressure just above the bubblepoint pressure of the oil. This is the starting point of the separation test. • The temperature of the PVT cell are then reduced to the first- stage separation test temperature and allowed the cell content to equilibrate. The pressure of the fluid is then reduced to the first pressure stage (below the bubblepoint pressure) of the separation test allowing free gas to evolve. The magnetic mixer is then used to achieve equilibration between the free gas and the pressurized liquid. • The evolved gas phase is then isobarically removed from the PVT cell into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure (see Fluid Analysis Equipment Section) The previous two steps are repeated in five stages to stock tank conditions. Liquid Phase Viscosity and Density Measurements Prior to measuring the viscosity, a suitable size piston is selected with the proper viscosity range and the electromagnetic viscometer is calibrated using a fluid with known viscosity. A portion of the live reservoir fluid is transferred into a high-pressure high-temperature electromagnetic viscometer. The viscometer is initially evacuated and kept at the same temperature as that of the PVT cell. During the transfer of approximately 15 cc of live hydrocarbon liquid to the evacuated viscometer, flashing of oil takes place, and hence, the viscometer system is flushed with live oil twice to make sure a representative live oil sample is taken. Subsequent to transfer of live reservoir fluid into the viscometer, the fluid system is allowed to achieve thermal and pressure equilibration. Then, the viscosity reading is taken. Following the viscosity reading, incremental pressure reduction steps are taken. At each pressure point, the piston was allowed to run back and forth for sufficient time to achieve pressure equilibration and allow the liberated gas to migrate vertically upwards and accumulate at the top of the carrier chamber. Stock-Tank Oil (STO) Viscosity and Density Measurements A sample of STO is taken in a known capillary tube to measure the STO viscosity at a preset temperature. The temperature bath is maintained at the preset temperature. Client: Phillips Alaska Field: Palm Well: Palm 1A PVT Report 52 A small sample of the liquid is also transferred into the Anton Paar DMA45 densitometer to measure the density of the liquid phase. The viscosity and density measurements are repeated for data consistency check.
